While Hinkley Nuclear Was Being Built, The UK Grid Decarbonized

Michael Barnard

The latest announcement about Hinkley Point C was predictable. The first reactor at the plant in Somerset is now expected to begin generating electricity in 2030. The cost estimate has climbed again, now reaching roughly £35B in 2015 pounds or about £49B in current money according to Electricité de France. When the project received final approval in 2016, the expected construction cost was £18B and the first reactor was expected to begin operating in 2025. In the span of a decade, the expected capital cost nearly doubled while the schedule slipped by five years. The project illustrates the pattern described by Oxford megaproject scholar Bent Flyvbjerg. Large infrastructure projects tend to run over budget, over schedule, and deliver fewer benefits than originally promised. Hinkley Point C appears to be achieving the full trifecta.

To understand how the project arrived at this point it is necessary to revisit the electricity system that existed when Hinkley was first proposed. Around 2006 the United Kingdom grid looked very different from today. Coal provided close to 40% of electricity generation. Gas provided about 35%. Nuclear power supplied about 18%. Wind generation was still emerging with only about 2.5 GW of installed capacity across the country. Solar generation was negligible. Electricity carbon intensity averaged roughly 520 gCO2 per kWh according to data from National Grid and Carbon Brief. Policymakers faced a looming capacity gap as aging coal plants approached retirement under European pollution rules and older nuclear reactors approached the end of their operating lives. Large baseload nuclear plants seemed like a logical replacement for retiring coal and nuclear capacity while maintaining system reliability and reducing emissions.

EDF entered the picture in 2008 when it acquired British Energy for about £12.4B. This acquisition gave the French utility access to several UK nuclear sites including Hinkley Point in Somerset. Plans for a pair of European Pressurized Reactor units emerged soon afterward. The reactors would provide about 3.2 GW of generation capacity and produce roughly 25 TWh of electricity each year assuming a 90% capacity factor. That would represent about 7% of UK electricity demand. EDF partnered with China General Nuclear to help finance the project. The UK government supported the project through a Contract for Difference that guaranteed a strike price of £92.50 per MWh in 2012 pounds for 35 years. Adjusted for inflation that price is now roughly £120 to £130 per MWh in current money.

The timeline of the project reflects the slow progress typical of large nuclear builds. The formal proposal took shape around 2010. Regulatory reviews and financing negotiations consumed the next several years. The final investment decision occurred in 2016. Construction began soon afterward. The original schedule expected the first reactor to enter service in 2025. Early construction challenges appeared within a few years. Welding issues and supply chain delays increased costs. In 2019 EDF revised the cost estimate to roughly £22B and delayed the schedule to 2026. The COVID pandemic slowed construction further during 2020 and 2021. A new estimate in 2022 increased the expected cost to roughly £26B. In 2024 EDF raised the estimate again to between £31B and £34B in 2015 pounds. The most recent revision places the cost at about £35B in 2015 pounds with startup expected in 2030. If the schedule slips to 2031, EDF estimates another £1B in additional cost.

Hinkley is not an isolated example. The reactor design used at the site is the European Pressurized Reactor. Other projects using this design have experienced similar difficulties. Olkiluoto 3 in Finland began construction in 2005 and entered commercial operation in 2023. The project took roughly 18 years from start to finish and cost about €11B compared with an original estimate of about €3B. Flamanville 3 in France began construction in 2007 and only began producing electricity in 2024 after more than a decade of delays and cost escalation. These projects demonstrate that modern nuclear construction faces structural challenges including complex regulatory oversight, large supply chains, and one-off engineering work.

While Hinkley Point C progressed slowly, the electricity system around it began to change rapidly. UK grid carbon intensity fell from about 520 gCO2 per kWh in 2006 to roughly 120 gCO2 per kWh in 2025 according to National Grid data. That represents a reduction of about 77%. Coal generation collapsed during the same period. In 2012 coal still produced about 40% of UK electricity. By 2024 the last coal plant closed and coal generation fell to zero. Gas generation initially increased as coal declined, providing a bridge fuel that cut emissions roughly in half per kWh compared with coal. At the same time renewable energy expanded quickly.

Wind power became the largest contributor to this change. Installed wind capacity grew from about 2.5 GW in 2006 to roughly 32 GW by 2025 according to data from the UK Department for Energy Security and Net Zero. Early growth came from onshore wind farms. Onshore capacity increased from about 1.9 GW in 2006 to roughly 15.5 GW in 2025. Offshore wind emerged later but expanded faster. Offshore capacity grew from about 0.6 GW in 2006 to about 16.5 GW by 2025. Projects such as the Dogger Bank offshore wind complex in the North Sea represent the industrial scale of the new industry. Dogger Bank alone will provide about 3.6 GW of capacity when fully operational. That is comparable to the output of Hinkley Point C.

Electricity generation from wind rose along with installed capacity. Wind produced about 8 TWh of electricity in 2006. By 2024 wind generation exceeded 80 TWh in some years depending on weather conditions. That represents roughly one third of UK electricity generation. Offshore wind turbines grew in size during this period. Early offshore turbines had capacities of about 3 MW. Modern offshore turbines commonly exceed 12 MW. Larger turbines capture more energy and reduce installation costs per unit of capacity. This change in technology helped drive the rapid expansion of offshore wind.

The grid also evolved to accommodate the growing share of renewable energy. Market reforms played a significant role. The Contract for Difference program created long term price stability for renewable developers. Early offshore wind projects received strike prices above £140 per MWh. Subsequent auctions saw rapid declines. Recent auctions have cleared at prices below £50 per MWh in 2012 pounds according to UK government auction data. Transmission infrastructure expanded as well. High voltage direct current interconnectors connected the UK to electricity markets in France, Norway, Belgium, and Denmark. These interconnectors allow power to flow between regions and help balance variable generation.

Grid operations also changed to manage a system with lower inertia and higher renewable penetration. Batteries began appearing in grid services markets around 2017. These batteries provide fast frequency response and reserve capacity. A typical grid battery project may have a capacity of 50 to 100 MW with discharge durations of one to two hours. Hundreds of megawatts of such batteries now operate across the UK. System operators also introduced synthetic inertia services and stability markets. These tools allow power electronics and synchronous condensers to stabilize the grid as coal plants retire.

The economic dynamics of electricity generation shifted during the same period. Nuclear plants represent a form of megaproject economics. Each plant is a large custom built facility that takes many years to construct. Learning effects are limited because each plant is unique. Wind turbines and solar panels follow a different model. These technologies are manufactured in large volumes. Production learning and scale economies reduce costs over time. Global deployment of wind and solar increased dramatically during the 2010s. This expansion drove steep declines in capital costs. Offshore wind costs in the UK fell by more than 60% between 2015 and 2022 according to data from the International Energy Agency.

These cost trends changed the relative economics of electricity generation. The Hinkley strike price of £92.50 per MWh in 2012 pounds—£130/MWh in 2025 pounds—looked competitive with offshore wind in 2016. That comparison no longer holds. Recent offshore wind auctions cleared at prices well below that level. Solar costs declined even faster. Utility scale solar projects in Europe now commonly produce electricity for less than £40 per MWh depending on location and financing conditions. Battery costs declined as well. Lithium ion battery pack prices fell from roughly $1,000 per kWh in 2010 to about $140 per kWh in 2023 according to BloombergNEF.

The rising cost of Hinkley also raises questions about opportunity cost. The current estimated cost of about £49B in today’s money represents a very large capital investment. Offshore wind projects in Europe commonly cost between £2M and £3M per MW of installed capacity depending on location and turbine size. At £2.5M per MW, £49B could finance roughly 20 GW of offshore wind capacity. With a typical offshore wind capacity factor of about 45%, that capacity would produce around 79 TWh of electricity annually. Hinkley Point C is expected to produce about 25 TWh annually. The comparison is not exact because nuclear provides firm generation while wind is variable. The scale difference is significant.

The question of reliability often arises in discussions about renewable dominated grids. Nuclear plants provide steady output and high capacity factors. Wind and solar output varies with weather conditions. The UK grid addresses this variability through several mechanisms. Interconnectors allow electricity imports and exports across Europe. Gas plants provide flexible generation when renewable output is low. Battery storage provides short term balancing services. Demand flexibility also plays a role as electric vehicles and heat pumps respond to price signals. By 2030 the UK is expected to have tens of gigawatts of offshore wind, several gigawatts of battery storage, and expanded interconnection capacity.

Hinkley Point C will still contribute meaningful low carbon electricity once it begins operating. The two reactors will produce roughly 25 TWh per year and supply about 7% of UK electricity demand. Nuclear plants typically operate for 60 years or longer. Over its lifetime the plant may generate more than 1,500 TWh of electricity assuming steady operation. That electricity will displace fossil generation and reduce emissions. The role of the plant in the overall system will be different from what policymakers expected in 2006. Much of the decarbonization challenge that motivated the project has already been addressed by renewable energy expansion and coal phase out.

The next UK nuclear project, Sizewell C in Suffolk, raises obvious questions about what lessons policymakers are drawing from the experience at Hinkley Point C. Sizewell C is planned as a near replica of Hinkley using the same European Pressurized Reactor design and similar capacity of about 3.2 GW. The estimated construction cost is currently around £20B to £30B depending on assumptions about financing and schedule. Unlike Hinkley, the project will be financed through a regulated asset base model that allows developers to collect revenue from electricity consumers during construction. This structure reduces financing risk for investors but shifts more cost exposure onto the public.

The core question is whether the UK energy system in the 2030s and 2040s still requires additional nuclear megaprojects built on decade long timelines when wind, solar, and storage technologies continue expanding on much shorter deployment cycles. A second question concerns opportunity cost. If Sizewell C ultimately approaches the capital intensity seen at Hinkley, the same level of investment could finance tens of gigawatts of renewable capacity or large expansions of grid infrastructure. Policymakers therefore face a strategic choice between continuing the megaproject model for firm low carbon generation or allocating capital toward technologies that can scale incrementally and rapidly across the electricity system.

The broader lesson from the Hinkley experience concerns the pace of technological change in energy systems. Large infrastructure projects require long planning and construction timelines. Energy technologies such as wind turbines, solar panels, and batteries follow faster innovation cycles driven by manufacturing scale and global deployment. Between the time Hinkley Point C was conceived and the time it will enter operation, the UK electricity system transformed itself. Coal disappeared. Wind capacity expanded more than tenfold. Carbon intensity fell by more than three quarters. The project will arrive into a grid that has already undergone much of the transition it was designed to support.

Michael Barnard works with executives, investors, and policymakers to navigate the pathways toward decarbonization. He helps make sense of complex transitions by combining insights from physics, economics, and human systems, turning them into practical strategies and clear opportunities. His work spans sectors from sustainable building materials and aviation fuels to grid storage and logistics, always with an eye on how they fit together in the larger picture of the clean economy. Informed by projects across North America, Asia, and Latin America, his perspective is both global and grounded in real-world application. Michael shares his thinking through regular publications on technology trends, innovation, and policy frameworks — not as final answers, but as contributions to an ongoing conversation about building a sustainable future.