BP shareholders delivered what the FT called a “heavy defeat.” But the bigger win was to cap BP’s renewables losses to $5.4 billion rather than losing many more billions. BP’s Q1 numbers showed underlying profit more than doubling to $3.2 billion. The company is now generating cash, not bleeding it.

Follow This, the Dutch-led campaign group, asked BP to disclose how it would create shareholder value in a world of falling oil and gas demand. It will ask Shell shareholders to also vote on this question. I respect the Follow This leader Mark van Baal. Mark advocates for urgent renewables investment. Renewable electricity is a major solution to an impending climate crisis, but timing is everything. Shareholders also have to assess what happens to energy companies that move too far, too fast.

Ørsted, the world’s biggest offshore wind developer outside China, is the closest thing to a pure bet on the activist strategy demanded from BP. Since 2023, Ørsted has written off more than $6 billion on cancelled US projects. The model made sense when borrowing was cheap. It fell apart when it wasn’t.

BP changed its mission to Beyond Petroleum in 2000, before it suffered the tragedy of Deepwater Horizon in 2010, and later quietly dropped its greenwashing messages. It then sought a green halo in 2020 when its aptly named CEO Looney made new undeliverable ESG promises. European supermajors have learned hard lessons about transition timing vs. commerciality.

BP wrote off $5.4 billion on low-carbon investments in 2025, primarily Lightsource and Archaea. Shell took a $1.6 billion hit on Atlantic Shores wind farm and its Rotterdam biofuels plant. Equinor lost around $1 billion on US wind farms. TotalEnergies took a $700 million loss on offshore wind. Add Ørsted, and these companies lost over $14 billion on these projects since 2023. Are these the projects that shareholders want?

I often met institutional investors when I worked at Shell. I’d explain how Shell’s emissions targets were designed to reflect the realistic range of independent IPCC scenarios. The world demands hydrocarbons for decades. That is why Shell just agreed to buy Canada’s ARC Resources Ltd, its biggest deal in over a decade, adding 370,000 boe/d. But this also adds top quartile, lower carbon intensity barrels, and gas for lower carbon LNG Canada.

Credit to Murray Auchincloss, the previous BP CEO, who pivoted to cut renewables spend from $5 billion a year to $1.5–2 billion. The new CEO Meg O’Neill, who took the helm this month, inherited $22 billion in debt and a target of $14–18 billion by 2027. At the original spend, BP would have faced an emergency cash crunch.

A resilient energy strategy cannot go too far, too fast. It also cannot dismiss climate risk, as Follow This shareholders are right to insist. Boards need to lead, rather than follow: energy transition must serve all stakeholders.

INSIGHTS

The same institutional investors backing Follow This also demand quarterly returns. The tension is not between ESG and profits. It is that transition investment is long-cycle capital in a short-cycle market. Wind farms, green hydrogen, CCS infrastructure are 20 to 30 year assets. The markets that finance them operate on quarterly reporting cycles and fund manager performance windows of three to five years. Institutional investors must be prepared to collectively share the risk of energy transition investments as a separate capital allocation category. Catalytic capital investments, which patiently stimulate new energies supply and create offtake demand, must be judged initially on different time horizons and returns. Investors need to stop asking for two incompatible things at once. No AGM resolution fixes that.

What we also witness is the hangover from two intersecting peaks: the overreach of ESG as an investment doctrine, and the era of near-zero interest rates. Both peaked around 2020 and have now hit a reality buffer. Projects that made financial sense at 1% cost of capital do not make sense at 5%. Strategies built on the assumption that ESG mandates would only tighten have seen political reversal in several major markets. Write-downs are the consequence of strategy using narrow scenarios and sensitivities.

Prudent scenario thinking is not a planning luxury. It separates strategies that survive a changing world. As I explain in the note linked above: no energy transition has ever unfolded as planned. Nuclear was going to make electricity too cheap to meter. The US shale revolution wasn’t in any credible forecast. Solar left every official projection looking timid within years of publication. The current energy transition is no different. The unexpected is to be expected.

Energy transition is a once-in-a-generation opportunity. But energy must remain affordable, secure and sustainable. Those three imperatives are not in conflict by nature. They come into conflict when the strategy is built around only one of them.

Energy transition leader or fast-follower are both risk positions. Both require an upside thesis and a pre-planned response to downside. Think of it as juggling a bull strategic position and a bear strategic position. The bull leg captures the opportunity if transition accelerates: policy tightens, capital costs fall, new markets open. The bear leg is the pre-planned exit, triggers for reallocation before losses compound. Winners are held with a trailing stop that locks in gains as the position moves in your favour. Losers are exited quickly, at a signal set before investment.

Ørsted had a bull thesis. Offshore wind was the right technology in the right decade. What it did not have was a credible bear leg: no pre-planned response to rising rates, US policy reversal, or deteriorating project economics. The positions were held long after the stop signal had fired. That is not a failure of vision; it is a failure of risk management discipline. The companies that will lead energy transition are not those that moved first or those that waited. They are the ones that moved with intent, protected the downside, and knew in advance what would change their mind.

The right answer to “lead or follow?” is “it depends”. It depends on which country, which technology, which market, which regulatory environment, and the prevailing capital cycle. Ørsted leads on offshore wind outside China because Denmark’s policy environment and financing conditions made it commercially viable. The Danish government still owns 50.1% of the company. I would expect another national energy company, Saudi Aramco, to defend hydrocarbons given its reserve position, its low production costs, and a home market that is not going to price carbon at levels that make oil extraction uneconomic any time soon. Both companies are making strategically coherent decisions from where they stand.

The United States is a different geography again. It is a net oil and gas exporter, and Chevron and ExxonMobil are disciplined on liquid hydrocarbon returns. But both have to play catch-up on LNG. The opportunity was visible but they were slow to act. Exxon’s encounter with Engine No. 1 in 2021 is another illustrative case study. The activist fund secured three board seats after a campaign centred on climate risk and long-term financial exposure. Being right about near-term liquid hydrocarbon demand did not protect Exxon from a governance failure rooted in not taking energy transition scenarios seriously enough. Balance works both ways. It can switch again.

European supermajors overreached on transition and are now correcting. US majors face their own reckoning: on LNG positioning, on stakeholder expectations they underestimated, and when their portfolios are tested in a world where policy does eventually tighten. For companies in between, which is most of the listed energy sector, the answer is not to pick one lane. Hold multiple scenarios at once, iterate each position against genuine risk analysis, and be open to the evidence as it arrives.

That discipline is harder than either leading or following. It is also the only approach that is resilient to the uncertainty involved.

The UK government announced an electricity market reform that successive governments have ducked for a decade. From next year, legacy low-carbon generators will be moved, voluntarily but under Treasury pressure, onto fixed-price contracts and off the gas-linked wholesale price. This covers roughly a third of UK power and was long overdue. It is one of three reforms required. The other two are: to synchronise renewables build-out with grid expansion delivery pace; and to diversify supply with firm, dispatchable low-carbon gas power+CCS generation alongside renewables, and small modular nuclear reactors.

UK wind is a crown jewel. Wind overtook gas in 2024 as the UK’s largest source of electricity, at about 30% of generation against gas at 26%. Carbon intensity hit a record low of 124 gCO₂/kWh in 2024, down from 419 gCO₂/kWh a decade earlier. Chris Stark’s Mission Control, working with NESO, has rationalised the grid connection queue from over 700 GW of speculative applications to 283 GW of shovel-ready projects, of which 132 GW align directly with the Clean Power 2030 target. That is real progress, moving electrical mountains at rapid speed.

DISTRESSED BUYER

Chris Stark is right that a target drives concerted action. I would add from thirty years of experience that a target has to be resilient over time, or it erodes stakeholder trust. Inflexible targets that force bad procurement decisions cost more than minimal delays avoided. There are signals that the government got this wrong with the AR7 auction.

The seventh Contracts for Difference (CfD) allocation round closed on 14 January 2026. The press release lauded 8.4 GW of offshore wind secured, cleared at a strike price of £91.20/MWh for fixed-bottom wind projects. That is around 11% above AR6 on a year-on-year basis, and closer to 26% higher when you normalise for the shift from 15-year contracts in AR6 to 20-year contracts in AR7. The auction structure itself signalled something had gone awry. Unconsented projects were allowed to bid and win for the first time, a deliberate relaxation to widen the pool. The auction budget doubled mid-process, from £900 million to £1.8 billion. Around 82% of capacity went to a single German utility, RWE. Along with its project partners, RWE won 6.9 of the 8.4 GW.

82% of an auction round concentrated in one company is excessive single-company risk for a system that depends on the build-out completing on schedule. The Ørsted Hornsea 4 halt in May 2025, the loss of about 5% of the 2030 offshore wind target at the time, is the concentration risk made concrete.

Read those AR7 signals together, the relaxed eligibility, the doubled budget, the dominant single winner, and you see a government that bidders sensed was a distressed buyer, bound by its manifesto promise and the fear of the AR5 auction, which received no bids. Distressed buyers pay premiums.

Procurement failure was dressed up as climate ambition but consumers will carry the high costs for twenty years. More worrying still is that high strike prices are now anchored. Legacy wind operators with contracted prices at half this level will be rubbing their hands at the prospect of new fixed-price contracts offered to them.

CONGESTED GRID

Meanwhile, the grid cannot absorb what has already been contracted. Transmission constraint costs reached around £1.9 billion in 2024/25. Around 98% of curtailed and stranded wind is in Scotland, because the cross-border transmission capacity into England is a bottleneck. About £350 million of that £1.9 billion was paid directly to Scottish wind farms to switch off, and the CfD top-up makes the wind farm whole against its strike price regardless. Consumers fund both sides of this wasteful trade. NESO projects the bill will rise to between £4 billion and £8 billion a year by 2030.

A reader in Stonehaven commented to me that he was looking out at seven wind turbines from his home. Five were turning slowly, two still. Stonehaven was where my favourite model train shop was when I was a boy. Those miniature engines may be why I became an engineer. They ran on electricity. I explained to the reader that the turbines are not broken. The grid is full. The wind blades are paid to stand down because the wires to England are congested, and the wind farm gets paid either way.

Which brings us to the speech given by the Energy Minister, and the latest conflict to create an energy shock. The war in the Middle East has reopened the question that shaped UK energy policy after Ukraine: how exposed are British household energy bills to global events they have no control over? This is the second such shock in less than five years. The Chancellor’s statement to the Commons framed the package as a direct response to that. Ed Miliband’s speech to the Good Growth Foundation framed the delinking reform as structural, not just immediate.

STRUCTURAL REFORM

Energy Minister Miliband and Chancellor Reeves are right that there is a structural distortion at the heart of the UK electricity market. Volatile gas prices usually set the wholesale price of electricity. Miliband explained that around 90% of the time in the early 2020s, the marginal price-setting plant on the grid was a gas turbine. This meant wind, nuclear and other low-carbon generators received the gas price for their output even though their own costs had nothing to do with gas. Today, Miliband told the Good Growth Foundation audience, gas sets the price around 60% of the time. The government expects that to fall to about half the time by 2030, as more firm low-carbon generation comes online. This is all positive progress.

The Treasury’s move is the piece that makes the structural reform bite. The Chancellor raised the Electricity Generator Levy rate from 45% to 55% with immediate effect and extended the levy past 2028. The rate rise is calibrated to make the new Wholesale Contracts for Difference (WCfD) more attractive to legacy low-carbon generators than staying on the gas-linked wholesale price. Take-up is voluntary. DESNZ will introduce WCfDs later this year with an allocation round in 2027. Together the generators in scope cover about a third of UK power.

I have watched this closely over many years. Almost every serious market economist and half the industry have been asking for a version of what the Chancellor announced. Congratulations are due. When I helped to originate the Net Zero Teesside industrial CCS cluster (and its gas power+CCS project) with David Eyton at BP, and many other allies, we recognised that UK clean power revenues eventually had to be decoupled from gas. Electricity has to be cheap enough to support the industrial electrification business case and the broader economy. This is the decoupling move. Successive governments have been told for a decade that the merit-order effect is the single largest source of avoidable bill pain. This one has done something about it. Good.

This is where we begin to diverge. Miliband’s speech cited AR7 as proof that renewables are around 40% cheaper than building and operating new gas. That figure relies on comparison to an unbuilt CCGT at a load factor that would never be financed, and it excludes the cost of getting those electrons to demand.

MARGINAL GAINS

The Minister borrowed the British Cycling Team philosophy during his speech to describe the marginal-gain approach to clean energy infrastructure. A great metaphor. But the marginal gain that matters most right now is not another gigawatt of generation contracted. It is another kilometre of overhead line energised, another substation commissioned, or cross-border subsea cable laid.

Reforms announced on land access, permitted development rights and self-build grid connections help. They will not make the grid accelerate to keep pace with AR7, let alone AR8 and AR9. And while we debate the queue, the AI data centres that could be anchored on cheap Scottish wind are moving to Ireland and the Nordics. The government cannot see the electrification and AI wood for its Clean Power 2030 trees. Affordable electricity, not wind energy, is the priority. Cheap electricity will electrify our homes, cars and industries much more than overpaying stranded Scottish wind turbines to do nothing. This is common sense.

THREE SUGGESTIONS

Three components of the delinking package will decide whether bills fall or climb for twenty years.

1. The first is negotiation mechanics. A legacy generator will only switch to a voluntary WCfD if the fixed price leaves it at least as well off as staying on wholesale minus the 55% Electricity Generator Levy. The current second fossil-fuel shock in under five years anchors the price. The Treasury is a distressed buyer, bound by its promise to cut bills by November, and the generators know it. Distressed buyers pay premiums. This is what cleared AR7 at £91.20/MWh. A fix would be to index the WCfD strike to long-run marginal cost plus a fair return on capital still invested, and let Ofgem adjudicate the formula rather than the Treasury negotiate a fixed outcome.

2. The second is instrument shape. The Electricity Generator Levy taxes windfalls when they happen and disappears when they don’t. It is shock-responsive, the right shape for a decade of perma-crises. A WCfD is the opposite. It pays a fixed price for twenty years whatever wholesale does, insulating the generator from risk and locking the consumer into one price for two decades. The danger is that the scheme reprices the cheapest third of British electricity up towards the AR7 strike of £91.20/MWh. Wind energy for consumers is not cheap in this market. The fix here is to cap any new WCfD with a floor and a ceiling around the strike so both sides carry some risk and neither locks in the extremes.

3. The third is policy credibility. Raising the EGL on revenues generators are still earning is a change in the rules mid-flight. A scheme described as voluntary but engineered through tax pressure looks like coercion to investors. Investors may demand a premium for that uncertainty in the next auction. Not all legacy generators face the same risk profile, and the scheme needs to reflect that. The LNG glut expected in 2026 may reduce gas prices significantly, leaving consumers paying a premium above a falling wholesale price. It would be wise to build in break clauses or a ceiling that shares that downside with bill-payers, without conceding the upside of a low wholesale price to the generator.

Negotiated well, households will avoid higher bills the next time fossil fuels spike.

Negotiated badly, generators lock in a premium for two decades, AI and wider electrification are not viable, the Treasury loses the windfall tax line it is currently raising, and consumers pay twice: a higher fixed strike price on every bill, and the loss of the windfall clawback that used to come back to them.

My balanced summary is this. The delinking announcement is the right move, and successive governments have ducked it for too long. Clean power generation does not drive grid expansion. We are still spending to turn clean power off. Those outcomes are not derived from generation alone. We must be wary of distressed buyer behaviour forced by short-term targets. There are more levers to pull. Grid transformation, zonal pricing, conditional LDES investment, much to explore. That said, credit is due. There is much to praise. Market reform has arrived at last.

INSIGHTS

The delinking announcement is the electricity market reform the UK has needed for a decade. Today, 60% of the time, the price of electricity is driven by the price of imported gas when a third of UK electricity comes from legacy low-carbon generators whose costs have nothing to do with gas. As a result, wind operators earn windfall profits in crisis periods, which the 2022 Electricity Generator Levy partially claws back. Wind energy is not cheap in this market. The Chancellor extended the EGL beyond 2028 and raised the EGL from 45% to 55%. This is to push legacy generators to move voluntarily onto fixed-price Wholesale Contracts for Difference from 2027.

If the strike prices are negotiated well, households will see lower bills the next time a fossil fuel shock hits. If they are set badly, the Treasury loses both ways: forgone EGL revenue today, and higher bills to defend at the next election. A well-designed scheme would index the WCfD strike to long-run marginal cost plus a modest return on amortised capex, publish floor and ceiling bands, and put the negotiation under independent adjudication. The risk is that the scheme reprices the cheapest third of British electricity up towards the AR7 strike of £91/MWh for twenty years, trading the cyclical EGL insurance policy instrument for a fixed premium. The detail of contract negotiation will matter more than the announcement. The AR7 negotiation set a worrying precedent. But market reform is directionally right.

The 40% figure Miliband cites to describe AR7 against new gas is misleading, because new CCGTs will not be financed at a 30% load factor. New gas like NZT Power will be over 90% clean gas power+CCS plants at £86–94/MWh with shared transport and storage costs included. Gas+CCS is not subject to heavy carbon price penalties and is not intermittent like wind. Gas would require prudent hedges: explore our own North Sea gas; secure long-term deals with Norway and Qatar; and expand UK gas storage. Equinor (an NZT Power partner) and Qatar LNG will likely welcome long-term contracts because prices will fall with a near-term global glut of new LNG production predicted from 2026 onwards.

Miliband obscures the true cost of wind. We must include grid infrastructure costs to move electrons from generation largely in the north to demand in the south. Transmission constraint costs reached around £1.9 billion in 2024/25 and direct payments to switch Scottish wind off ran to around £350 million of that. About 98% of curtailed and stranded wind is in Scotland. The constraint bill is projected by NESO to escalate to £4 billion to £8 billion a year by 2030. A clean electron that cannot reach demand is not a cheap electron. And yet, applying zonal pricing, Scottish electricity could be among the most competitive in Europe and attract growth industries like AI.

A grid-first pivot alongside price delinking is sound industrial policy. The decisions that matter next are not about hope, as Miliband said in the questions after his speech. Hope is not a method. The decisions are about sequencing. We must synchronise AR8 and AR9 with grid delivery. It is also wise to diversify bidders in future CfD rounds to protect the system from another Ørsted episode. Let firm, dispatchable low-carbon do the work that intermittent generation should not be forced to do on its own. This includes several more gas+CCS projects where the supply chain and skills already exist. Keep accelerating the Great Grid Upgrade’s 17 projects and the 35 schemes in NESO’s Beyond 2030 plan. Build subsea HVDC corridors that link Scottish wind to English demand, and ensure that the Royal Navy can defend them. Keep working the LDES toolkit to cut curtailment and capacity costs. Set zonal pricing to reward locations, not strand them. Clean Power 2030 will be judged by household bills. Delinking helps, as do wires and faster connections. Sensible sequencing and a commercial mindset help most of all.

AI superpowers source the cheapest electricity. Gulf states recognise this, and the UK and Europe must compete. The US and China are ahead in the AI race. The US leads on chips and frontier models, and is energy independent. China is first on the podium of electro-tech roll-out. China State Grid spent a staggering $11 billion on infrastructure in the first two months of 2026. The AI economy race is becoming an electrification race. Generate cheap, abundant electrons and you can power more Nvidia chips than rivals.

When I was working for ADNOC Group, I sat in a glass tower overlooking the diamond blue Arabian Gulf below. One day a senior peer coached me that a ‘green halo’ was not a convincing argument to drive investment in clean energy. As I looked out at the sun-sparkled sea, I appreciated that I needed to reframe energy transition around the benefits of refining solar photons, not oil. The most compelling argument for energy transition is commercial. You exploit lowest cost feedstock (free photons), refine highest margin product (AI tokens), and use resources (land) you already own.

The Gulf is building a vertically integrated AI economy. Low-carbon solar photons will power its AI refineries for compute. Clean energy is incidental to the investment case. It just has to be cheap. Saudi Arabia’s Al Shuaibah solar project costs $0.01 per kilowatt-hour. Compare that to UK offshore wind, Britain’s primary clean power bet. January’s AR7 winning bids were eleven times the Saudi solar price. Of course, such deliberations should include the value of having secure local AI infrastructure and keeping certain data private nationally. Offshore wind has fewer permit hurdles or environmental protests seen with onshore wind. There are nuances beyond cost.

Gulf nations have related structural advantages that most European policy cannot easily copy. GCC countries have tracts of state-owned desert land, and patient capital from Gulf wealth funds that European project finance cannot match. Affordable, available land in New Mexico helped solar and wind capacity increase by 40%. On the Arabian Peninsula, there is abundant state-owned land and fewer planning and market barriers than in the US.

The Emiratis are investing in British offshore wind. Abu Dhabi’s Masdar co-invested €5.2 billion in East Anglia THREE, one of the UK’s largest offshore wind projects. It holds a 49% stake in the £11 billion, 3 GW Dogger Bank South development. The UAE will receive UK Contracts for Difference (CfD) payments about six to eleven times higher than its own domestic generation cost. These high energy prices are locked in by CfDs until 2045. Masdar understands the spread.

Our talent is the other prize for overseas investors. DeepMind was bought by Google. Darktrace cybersecurity was taken private by US Private Equity. Japan’s SoftBank acquired ARM Holdings. It will not only be petroleum engineers and exploration geologists coveted in the UAE, but also the best AI modelling entrepreneurs and advanced computing talent. We may also lose talent if alluring tax havens start to offer expats cheap access to AI tokens. The energy cost numbers compound. If the compute layer migrates to $0.01/kWh electricity and the UK’s contracted offshore wind price is up to eleven times that, European AI inference costs will be structurally higher for decades.

I still have my ADNOC lapel pin, black enamel with gold-lettering, celebrating fifty years of extracting oil, refining it, and exporting the product that powered the world economy. The Gulf countries are applying the same model in a new form. The new commodity is photons refined into AI tokens. Saudi Arabia’s NEOM has already pivoted to a $5 billion net-zero AI data centre cooled by Red Sea seawater.

AI and photons are not stopped by the Strait of Hormuz chokepoint. Data moves at the speed of light, not the speed of an oil tanker, and can be beamed via satellite.

The UK and Europe are responding. The EU will mobilise €660 billion annually to catalyse clean energy investment with a new Energy Transition Investment Council. Data centre investment in Northern Spain has surpassed ~$90 billion. Meanwhile, the UK has its AI Opportunities Action Plan. DeepMind continues to anchor London’s AI ecosystem and OpenAI announced it is establishing its UK office nearby. France has developed its Mistral frontier model. The talent to build the AI model layer is not the constraint.

Electricity cost is the constraint. The AI compute layer will relocate to other regions if the UK and Europe cannot compete with $0.01 per kilowatt-hour. Skilled engineers may move too if they are offered better pay, expat lifestyles, and other assurances.

INSIGHTS

OpenAI’s decision to pause its UK Stargate data centre project is the clearest signal yet that electricity economics are a binding constraint on AI infrastructure. OpenAI announced its first permanent London office this week. It will have the capacity for 500 staff and will be its largest research hub outside the US. On the same day, the company put on hold its data centre project, citing energy cost and the regulatory environment. The talent is staying but the compute is not. This is not a vote of no confidence in Britain’s talent or institutions. It is a vote of no confidence in Britain’s electricity price. The AI model layer and the AI compute layer are separating geographically. That separation may eventually lure some of the talent away too.

The Gulf’s energy advantage is not limited to solar. The UAE’s Barakah nuclear plant, built with South Korean expertise, comprises four reactors at 5.6 gigawatts. It reached full operational capacity in September 2024. The capital cost was approximately $5,700 per kilowatt, compared to Hinkley Point C’s estimated $11,800 per kilowatt. The UAE built twice the nuclear capacity for the same money. I advised on the first nuclear/solar credits sold to ADNOC to decarbonise its Scope 2 emissions.

Nuclear together with solar gives the Gulf diversified, ultra-low-cost electricity at a speed and cost with which most of Europe may struggle to compete. But Europe does have strengths, if it can concoct the right economic formula. Norway’s hydro-power and sovereign wealth funds are an example. Countries like Spain have growing industrial solar, and interconnections with North African renewables may offer hybrid potential. France is already a nuclear powerhouse. UK offshore wind is a crown jewel.

Sovereign wealth funds are the largest category of state investor in global AI. SWFs invested $66 billion in AI and digital infrastructure in 2025. The Norwegian SWF (the world’s largest) invests heavily in mega-scalers like Nvidia, Alphabet and Amazon. Gulf funds led overall, with 43% of all state-investor capital in the sector. Saudi’s HUMAIN has ordered 18,000 Nvidia Blackwell chips. Abu Dhabi’s MGX took a material stake in OpenAI. This is a deliberate strategy: build the cheapest electricity, attract the compute data centres, own stakes in frontier model leaders. The Gulf states are vertically integrating from photon to token across the AI stack.

Responsible Energy Briefing: When molecules can’t move examines the physical infrastructure chokepoints that define whether energy resilience is achievable. Free to read.

The clue is in the name. French oil supermajor Total rebranded to TotalEnergies in 2021. This repositioned it as an old and new Energies chameleon. I have worked a lot with Total. The French are proud to have hosted the Paris Agreement and this is a legacy they cherish. So why have they dropped net zero 2050?

What many people do not realise is that the Paris Agreement and net zero 2050 are not the same thing. The agreement itself does not say net zero or 2050. Those commitments arrived later, along with Greta Thunberg and a wave of investor-led ESG pressure. And now we are seeing the pendulum swing back.

The original Paris text (Article 4.1) calls for rapid reductions to “achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century.” This ‘net’ balance means that if we overshoot the Paris temperature goals of 1.5–2°C then we will need to remove emissions. In my view that is inevitable, and it’s why Carbon Capture and Storage, and Direct Air Capture technologies will be essential; in addition to myriad new ways to stop current emissions growth.

The Paris goal is to achieve “global peaking” as soon as possible and net zero in the “second half of the century”. The second half is between 2050 and 2100. I was lucky to chat to Christiana Figueres, UN’s COP21 top negotiator, at a Shell event in The Hague. Christiana explained over dinner how the text’s broad language was agreed to reach consensus. That flexibility recognised the needs of different countries. This is why China’s 2060 net zero target and India’s 2070 target are both Paris compliant. TotalEnergies is too.

But we should not forget “as soon as possible” on limiting temperature. My fellow Scot, and esteemed Imperial College colleague, Professor Sir Jim Skea is chair of the UN panel which assesses climate science. Jim gave a keynote speech in the Great Hall at Edinburgh Castle. The walls there display historic swords, armour and pole-axes. But it was Jim’s advice on emissions cuts I most remember. Jim co-led the UN Special Report on 1.5°C and cautioned that we should not see that as a doomsday cliff edge. Nor should we assume that 1.5°C would avert climate harm. Every fraction of a degree matters above or below 1.5°C.

At the time of Paris, 4°C of warming by 2100 was projected. Today the range bends under 3°C. We are also running off the 1.5°C cliff edge desperately trying to build our energy transition bridge to safety. I have been showing the EU Copernicus data to people for years. The trend was unstoppable. It now shows the three-year global temperature average has passed 1.5°C. Which brings me back to TotalEnergies.

A couple of weeks ago I was speaking on a panel for a French bank, and stayed on to see Aurélien Hamelle, who leads strategy and sustainability at TotalEnergies. This was the same week he was fielding questions on the company’s regulatory bind: “We cannot adopt a net zero transition plan according to European regulations, because such a plan has to be aligned with 1.5 degrees.” Speaking to Aurélien, it was clear to me that his company is not ruling out 1.5°C. No single company decides that. Something else was amiss.

TotalEnergies has been put in a weirdly contradictory position. On one side, a judicial tribunal in Paris upheld a misleading advertising claim against their use of “ambition to achieve carbon neutrality by 2050”. At the same time, a coalition of 14 cities aims to legally force Total to align its activities with 1.5°C. Ironically, the group of cities includes Paris. This legal paradox is the climate equivalent of damned if you do or don’t. This is the background to the European regulations bind which caused TotalEnergies to drop net zero 2050.

The European Union’s political schizophrenia acts like its Copernicus 1.5°C overshoot does not exist. It is demanding companies follow its ESRS E1 reporting standard, which is not fully defined. This at a time when Brussels is in turmoil over its level of climate ambition, in the current permacrisis. Reported net zero plans have to be compatible with 1.5°C, but what compatibility will finally mean in practical terms is guesswork. The Europeans are trying to adapt to a non-linear, resilient energy transition. The Omnibus package scaled back its deluge of data requirements by 70%. And it adopted the lower end of 90-95% reduction by 2040.

I empathise. The energy transition will be a squiggle not a straight line. Total is navigating that future. It is investing in it too. It has 34 GW of installed renewable capacity. This compares to the solar capacity in The Netherlands, European leader in solar per capita. Total invested $3.5 billion in low carbon energy in 2025. It announced a $2.2 billion Asian tie-up with UAE’s Masdar, looking to double that JV’s 3GW capacity by 2030. A company walking away from net zero does not commit that capital. But with the pivot in US offshore wind, changes to renewables economics (just ask Ørsted), sharing financial risk helps.

Let’s test the company on its absolute emissions too. It targets 40% reduction in Scope 1 and 2 emissions by 2030 vs 2015. It has reached 33 MT in 2025, down from 46 MT and ahead of schedule. Methane emissions are down 65% since 2020. The TotalEnergies CEO, Patrick Pouyanné, was a champion of cutting methane emissions when I chaired OGCI, and was key to the Oil and Gas Decarbonisation Charter.

Admittedly, for all major energy companies, Scope 3 emissions is a harder question, especially for net zero in 2050. TotalEnergies’ Scope 3 emissions are the Scope 1 of steel, cement, shipping, aviation, trucking, aluminium, and chemicals industries. These so-called hard-to-abate sectors are responsible for a third of global emissions. Those industries are also constrained by affordability, energy security and the physics of industrial heat. How can any energy company outpace its own customers or society in general?

We are right to hold all of these companies to account. The litmus test is whether we measure not just where a company is, but also appreciate how fast it moves, especially when compared to the rest of society. Responsible energy security, affordability, and profitability are not obstacles to energy transition. Those conditions make it last.

INSIGHTS

Pure play renewables was heralded, but resilient integrated models work beyond oil and gas. TotalEnergies has a diverse mosaic of energies in its portfolio. Even its low carbon portfolio include 68% solar, 21% onshore wind and 5% offshore. Add those to oil, gas and petrochemicals and the risk of any one concentration is diluted. Hydrocarbon cash subsidises new growth opportunities, whether that is solar or EV chargers until they are commercially viable. Total’s return on capital overall was 12.6% in 2025 with its legacy energy businesses supporting the lower 10% return of its integrated power division. That is a sustainable difference. It does not bet the company. It positions it to grow with its new markets. BP recently had to u-turn on its strategy, its CEO admitting that they went “too far, too fast”. There is a new CEO now.

And yet, the EU punishes integrated energy companies. Take, for example, the EFRAG GHG intensity metric which reports emissions per euro of net revenue. An integrated company producing hydrocarbons and renewables reports higher intensity than a pure renewables competitor. This is regardless of energy transition capital deployed. We penalise the business model most capable of financing decarbonisation.

Ørsted failed the test: concentration risk, resilience premium and policy sequencing. Compare Ørsted’s recent history to TotalEnergies. It was lauded as the exemplar of new energy. Then it was caught out by near-zero interest rates and a cost of capital that evaporated [see Energy scenarios for an erratic world insights]. When Ørsted started to haemorrhage money they brought in Andy Brown, a Shell veteran, to make drastic project changes. Ocean Wind 1 and Ocean Wind 2 developments were cancelled. Sunrise Wind was delayed three years. The darling of offshore wind’s model had failed, writing off at least ~$7-8 billion. Share price fell ~80% from its 2021 peak; also the year of peak-ESG. Sadly, a quarter of its workforce will be cut by 2027.

In an earlier Commentary, I identified three tests for an energy portfolio: concentration risk, resilience premium, and policy sequencing. Ørsted’s story tested all three. There was concentration risk: a single energy technology and dominant expansion focus (US offshore). The resilience premium lesson is that a portfolio optimised across multiple policy and geopolitical scenarios gives you more options. And policy sequencing is there too. US political support for offshore wind disappeared, although it may return just as suddenly. Ørsted had no alternative market or technology to pivot toward when the energy libretto changed mid-performance. [see When the energy libretto changes for more on the three tests].

There remains overshoot delusion and 1.5°C denial which limits our action. The 1.5°C world has gone (for now) and we need to stop the pretence. A “low or no overshoot” world does not exist either. IPCC low-overshoot pathways peak at ~1.6°C around mid-century and return to 1.5°C by 2100 through rapid emissions cuts and moderate carbon dioxide removal. High-overshoot pathways peak closer to 1.8°C in the 2060s, and require large-scale carbon removal to bring temperatures down. Both depend on global emissions peaking around 2025 and then steep declines. We are just not in that world.

The good news is that current policy scenarios suggest that we have reduced future temperatures to around 2.6°C by 2100. It was 3.5–4°C only a decade ago. We are moving from catastrophic to severe outcomes. Our Paris goal of 2°C by 2100 is on our horizon.

Responsible Energy Briefing: When molecules can’t move examines the physical infrastructure chokepoints that define whether energy resilience is achievable. Free to read.

No energy transition has ever unfolded as planned. Nuclear was going to make electricity too cheap to meter. The US shale revolution wasn’t in any credible forecast. Solar left every official projection looking timid within years of publication. Each reworked the energy landscape; none followed the script.

The current energy transition is no different. The unexpected is to be expected.

The UK’s 2023 offshore wind auction attracted no bids, not because the technology had failed, but because costs had moved beyond what the policy framework assumed.

The energy transition has surfaced a dependency that most scenarios hadn’t modelled: solar panels, batteries and wind turbine magnets are all manufactured through supply chains dominated by a single country. Diversifying energy sources turns out to require first diversifying supply chains.

Then there was AI. ChatGPT launched in November 2022, and within months Microsoft, Google, Amazon and Meta had committed hundreds of billions to new data centres. An electricity demand surge that almost no transition scenario had modelled was suddenly underway. The limit to the AI revolution will not be Nvidia chips: it will be the ability to power them.

The energy transition is happening. Just not the way anyone planned.

The dominant mode of transition planning is normative: start from a desired end-state and work backwards. This is useful for setting direction. But a normative scenario that turns out to be wrong is not just unhelpful; it is actively misleading. It directs capital, policy and infrastructure towards assumptions that may never materialise, while crowding out the harder, more honest question: what if it doesn’t go to plan?

The 1.5°C target is the clearest example. The EU’s Copernicus data has confirmed what the trend lines had been signalling for years: the threshold is already being crossed. This was always the likely outcome of a normative target derived from a politically negotiated endpoint rather than from a range of plausible energy futures. That does not make the underlying ambition wrong. Reaching net zero before this century ends remains within reach. But the path there will not be the one the target prescribed.

The more useful frame is exploratory: not a predetermined endpoint, but a set of possible futures and strategies that hold their value across more than one of them.

Shell’s scenario set is instructive: alongside their normative net-zero pathway, Archipelagos maps a fragmented world of geopolitical tension and uneven transition; Surge is shaped by AI demand and rapid technology deployment. Both look considerably more like the world we are actually in.

The World Energy Council’s 2025 review reinforces the point: AI demand, critical mineral dependencies and affordability pressures remain underweighted in most normative models.

The answer is not a better normative scenario. It is a different kind of planning altogether, one that holds multiple exploratory futures simultaneously, tests strategy against each of them, and resists the temptation to pick a winner.

One normative scenario, however well-constructed, is not a strategy. In too many organisations, it has become one.

INSIGHTS

Ukraine and Hormuz didn’t arrive without warning. They arrived without sufficient preparation. The Strait of Hormuz has featured in IEA energy security analysis for decades. Europe’s structural dependence on Russian gas was documented years before February 2022. The question was never whether the risks were known. It was whether organisations had stress-tested their strategy against them. Most hadn’t. The same pattern runs through every major energy disruption of the past decade. The UK’s 2023 offshore wind auction design flaw halted an entire deployment cycle; the risk of policy-cost misalignment had been visible for years. Chinese dominance of solar panels, batteries and wind turbine magnets was not invisible to analysts. It was deprioritised because cheap manufacturing was the fastest path to deployment, and resilience was a problem to solve later. A single commercial AI product rewrote global electricity demand projections within eighteen months of its launch. None of these were outliers.

The 2008 financial crisis arrived without a mainstream forecast. What followed quietly rewrote the economics of the energy transition. Near-zero interest rates and quantitative easing ran for over a decade, making transition capital look cheap on a cost of capital that now no longer exists. COVID compounded it: when China locked down, the world discovered that batteries, solar panels and rare-earth magnets were largely manufactured in a single country. Both shocks reshaped the investment landscape. The version of the energy transition that most organisations were planning for assumed stable geopolitics, cheap money and open supply chains. All three assumptions have been tested. None have held.

Shell’s scenario planning gave it a competitive advantage in 1973, not because it predicted the oil shock, but because it had already considered comparable futures before the crisis arrived. Most organisations have not followed, because scenario thinking does not produce a single answer and boards need a single number. The confusion runs deep. The IEA calls the World Energy Outlook 'the most authoritative source of global energy projections' and 'a scenario-based approach' — both terms on the same page. These are not the same thing. A projection implies a most-likely outcome. A scenario is one of several plausible futures, designed not to predict but to test. They reach for the projection without engaging with the scenario. What they need is not a better projection. They need scenario thinking: holding multiple plausible futures and testing strategy against each of them, rather than reaching for a single number.

Responsible Energy Briefing: When molecules can't move — examines the physical infrastructure constraints that make exploratory scenario planning essential. Free to read.

What do women in energy need to progress? Eight years after researching the question, are we any closer to providing it? Careers can be a rollercoaster ride, and embracing the career squiggles in our work and family lives can be challenging.

Monica Collings OBE, Chair of POWERful Women coined the squiggle term when talking about her resilient and successful career. Someone who also navigated career squiggles successfully is my friend Rachel. Congratulations to Rachel Armstrong on a brilliant career which went from leading carbon solutions at Shell to shaping policy at DESNZ on carbon markets and industrial decarbonisation. I hope stepping back from the day to day means she might be persuaded to join a board. Rachel’s retirement and job moves by other talented women I know prompted me to revisit my own research.

In 2018 I completed my MSc dissertation at Henley Business School: “Coaching women to lead in the energy sector: an intersectional perspective on preferred strategies to overcome barriers to career progression.” I surveyed 215 women across 37 nationalities, using both quantitative analysis and open-ended questions. My supervisor Professor Dorota Bourne encouraged me to take an intersectional approach to examine how gender, ethnicity, years of experience, employment level and caring responsibilities all shaped women’s preferences.

TEN STRATEGIES FOR CAREER PROGRESSION

From the academic literature I synthesised ten strategies for career progression and asked women to rank them:

• Mentoring and sponsorship

• Networking

• Confidence and knowledge of own strengths

• Career development and stretch assignments

• Career strategy and planning

• Balance of career with caring responsibilities

• Understanding corporate culture

• Role models

• Inclusive workplace and gender behaviours

• Family and career balance

Most of those matter for anyone building a career, regardless of gender. But my research found that women in energy are disproportionately denied the most critical one: mentoring and sponsorship. They are left to rely on building self confidence instead.

Mentoring means someone advises you. Sponsorship means someone advocates for you when you are not in the room. Both came out as the number one preferred strategy, statistically significantly ahead of everything else.

Yet when I asked what had actually helped women in the past, the answer was building self confidence because they had to help themselves in the absence of structured support.

Needs also change across a career. Women in their first ten years valued confidence-building and stretch assignments most highly. Those with eleven to twenty years of experience valued balance significantly more. Caring responsibilities means not just mothers with young children, but elderly parents, relatives with disabilities or other needs, and the cumulative weight of being the person others depend on. But mentoring remained the number one need at every stage.

Almost half the women surveyed had used a coach, and almost all found it useful. Many described their coach as a kind of mentor. The roles blur in practice, and both serve the same underlying need: an independent trusted sounding board and counsel on career tactics.

85% of women said female colleagues had helped their careers. Many senior women who did not actively support others were not unwilling. They were often the only female leader in their organisation when they started, with no support structures of their own. You cannot pull someone up a ladder you are still clinging to alone. Building critical mass is part of the work that remains.

Positively, many senior women complimented the men who had mentored them. Male allyship is not a footnote. Allyship is essential, particularly when women are still so underrepresented at senior levels.

Gender was identified as the primary barrier above all other diversity dimensions. And when women described their biggest challenge in their own words, it was about workplace culture: being overlooked in meetings, excluded from informal networks where decisions are really made, and judged by different standards to male peers.

One respondent captured this perfectly: “I just don’t fit in their mental picture of how a technical leader looks. I have to work much harder to be visible.” Another reflected on feedback she had received to be “less assertive” and wondered whether she would have heard the same if she had been a man.

Confidence helped women survive that environment, but it was the environment itself that needed to change.

WHAT ADVICE WOULD YOU GIVE?

I asked 215 women: what advice would you give to a younger woman at the start of her career? Their answers still resonate eight years on.

On finding support: “Use mentors and sponsorships and plan ahead.” “Build a network to counter the very strong influence of the male network.” And, wisely: “Do not build your network to just build your career, build it on interest in people and their contributions and development.”

On self-belief: “Don’t be afraid of being yourself.” “Have confidence & challenge yourself: you set your own limits … be bold!” “Ring your own bell, as no-one else will.”

On critical mass: “Create powerful networks of women.” “Get more of you: get to a critical mass.”

On determination: “Do not give up, change is coming, and we need to be the ones driving that change.”

And on reshaping the workplace itself: “Don’t be limited by established ways of working, especially when it comes to juggling work and family life. Propose solutions that work for you and demonstrate that they work.”

EIGHT YEARS ON, WHAT HAS CHANGED?

When I was researching in 2016–2018, PwC reported that 62% of the top 89 UK energy companies had no women on the board. Only 1% of CEOs were women.

The latest POWERful Women / Bain & Company State of the Nation (2025) tells a more encouraging story, but with persistent gaps. Women now hold 30% of board roles, up from 29% in 2024. 8% of CEOs are women. But 20% of companies still have no women at board level at all. And in technical roles, women drop from 18% at entry level to just 5% at executive level.

Globally, the picture moves even more slowly. Women remain around 20% of the energy workforce (IEA). In oil and gas, 23%, up just one percentage point since 2020. In renewables, 32%, unchanged since 2019.

The pipeline from technical entry to executive leadership remains broken at exactly the career stages where mentoring, sponsorship and culture matter most.

Monica put it well recently: “resilience isn’t a personality trait, it’s a practice built over years.” She is right. The squiggle of a non-linear career is something to celebrate, not just survive. My research suggests we can go further, by building the mentoring, sponsorship and culture that means resilience is a choice, not the only option.

I have learned most about what that actually looks like from the women closest to me, in my family, circle of friends, and from the many talented women I have met throughout my career. Two pioneers who shaped my thinking on what genuine allyship means in practice are Katie Mehnert, who built Ally Energy to create real career pathways and community for women in energy, and my dear friend Lamé Verre, who co-founded Lean In Equity & Sustainability and now leads Net Zero sustainability at The Crown Estate. Thank you Katie and Lamé for mentoring me.

If your organisation runs a coaching and mentoring programme, that is a start. My research says you also need to tailor it by career stage, pair it with genuine sponsorship, and address the workplace culture that makes resilience necessary in the first place.

At a POWERful Women conference I handed out MARC by Catalyst cards: “Actions Men Can Take to Create an Inclusive Workplace”, and “Actions Women Can Take to Support Men’s Engagement”. We used them to run a round robin table discussion. The conversations they sparked were some of the most honest I have heard. MARC has since evolved. It now stands for Mutual Accountability, Real Change, reflecting a broader truth my research also points to: inclusion is not a task for women alone, or for men alone. It is a shared practice. You can find their resources at catalyst.org.

The women I mentor and sponsor give me confidence that the next generation of leaders is now at critical mass, and supporting one another more than ever before. This is absolutely vital because the energy transition needs the best talent, all of it.

INSIGHTS

My thesis conclusions still hold — and the business case has strengthened since 2018. McKinsey’s “Diversity Matters Even More” (2023) found that companies in the top quartile for board-gender diversity are 27% more likely to outperform financially, and those with diverse executive teams show a 39% increased likelihood of outperformance. MSCI’s 2024 research found that companies with 30% or more female directors saw 19% higher cumulative returns over the five years to 2024. The board representation numbers have improved: 62% with no women has fallen to 20%, and women CEOs have risen from 1% to 8%. But the 18%-to-5% drop in technical roles suggests we are still losing women at exactly the career stage where my research said companies should be investing most. This is in the mid-career years when caring responsibilities as mothers, looking after elderly parents, relatives with other needs, may reshape priorities. Too many talented women take the off-ramp.

The energy transition is creating opportunities that have grown dramatically since my 2018 research. Roles in grid digitalisation, carbon markets, hydrogen, battery storage, renewables and nature-based solutions have expanded enormously. Renewable energy employment alone reached 16.2 million globally in 2023 and is projected to double by 2030. Hydrogen has grown from a nascent sector to over 1.4 million jobs worldwide. Many of these roles value the cross-sector experience and systems thinking that women with non-linear careers bring naturally. Monica’s “squiggle” is becoming a competitive advantage, not a liability. The normalisation of flexible and hybrid working since the pandemic has also begun to address one of the biggest barriers my research identified: the balance between career and caring responsibilities. Women no longer have to choose between being present for their family and being always visible in the office. That is progress worth building on.

We have a rare chance to build new structures rather than simply reform old ones. My thesis ended with a quote from Mary Beard: “if women are not perceived to be fully within the structures of power, surely it is power that we need to redefine rather than women.” The companies and institutions being created now, such as in clean energy, in smart grid digitalisation, in climate finance, have the chance to design mentoring, sponsorship and culture into their foundations rather than retrofitting them. The question is whether we seize that chance. The women in my research already told us what they need. It is time that we listened.

Responsible Energy Briefing: When molecules can't move — goes deeper on the physical infrastructure chokepoints that sit beneath these investment risks. Free to read.

My hotel sat next door to the Palais Garnier, Paris's grand opera house. It is a few metro stops from where energy ministers gathered for the IEA ministerial in Paris last month. In opera, each performance follows the libretto. In energy policy, the libretto keeps getting rewritten mid-performance.

The energy transition just got harder. It is no longer enough to assume it simply carries on as planned. It will continue, but with energy security and resilience moving up the agenda, what gets funded first is starting to change.

The question for investors is no longer whether the transition is happening. It is which parts of the transition continue to attract capital when resilience, affordability and security start to matter more than abstract energy transition assumptions.

When governments or companies feel insecure, they rarely abandon the overall direction. But they do reprioritise within that direction. Projects that reduce exposure, build resilience and increase optionality move up the list. Others wait.

Three tests matter more than ever for any energy-exposed portfolio:

1. Concentration risk: not just in energy supply, but in the transport, processing and industrial supply chains that depend on the same routes, inputs and infrastructure, including feedstocks and products that do not diversify as easily as power.

2. Resilience premium: assets with optionality across multiple policy and geopolitical scenarios are becoming more valuable than assets optimised for a single pathway.

3. Policy sequencing: in a security-first moment, energy transition commitments are usually reordered rather than abandoned. Understanding that sequence is now part of the investment case, not an afterthought.

This reprioritisation was already visible at the IEA ministerial in Paris last month; even before the Strait of Hormuz crisis reinforced it.

The transition is still moving forward. But in a less stable world, the winners may be the investments that remain valuable across more than one future.

INSIGHTS

The investment case for the energy transition was double-subsidised. Both subsidies are now gone simultaneously. A decade of quantitative easing and near-zero interest rates made capital-intensive, long-duration transition assets look compelling on a 3% cost of capital. Low geopolitical risk provided the second subsidy: portfolio construction assumed stable supply chains, open trade routes and predictable policy sequencing. Neither assumption survives contact with 2024–26. Boards that priced their energy transition positions in the era of cheap money need to reprice them for the world that has actually arrived.

The direction of capital hasn’t reversed but the motivation has fundamentally shifted. CERAWeek confirmed that global clean energy investment surpassed $2.2 trillion in 2025 — two-thirds of all energy spending that year. It is now driven by energy security, economic competition and industrial policy, not climate pledges alone. The concentration risk is moving with it: China controls roughly 70% of refining capacity for the minerals the energy transition requires. Replacing a chokepoint controlled by Iran, a regional power, with one controlled by China, a nuclear-armed superpower with global economic reach, is not a transition strategy. It is an escalation of the same problem.

The signal to watch is policy sequencing and whether emergency energy security spending begins to crowd out energy transition capital. The evidence is already visible: investors withdrew nearly $20 billion from US ESG funds in 2024, the ninth consecutive quarter of outflows. The clearest historical illustration of sequencing risk remains the White House solar panels: Jimmy Carter installed them in 1979 as a symbol of American energy independence; Ronald Reagan had them removed in 1986; Barack Obama reinstalled them in 2010; Donald Trump kept them but dismantled the policy framework that would have scaled what was on the roof. The symbol persisted. The substance didn’t. The risk for energy transition capital is not that governments abandon the direction. It is that they reprioritise within it in ways that strand investments optimised for the previous sequencing.

Responsible Energy Briefing: When molecules can't move — goes deeper on the physical infrastructure chokepoints that sit beneath these investment risks. Free to read.

The standard way to discuss an energy crisis is in terms of barrels.

How many million barrels a day transit the Strait of Hormuz? How much of global LNG supply is at risk? What does OPEC spare capacity look like? How quickly can shale producers ramp up?

These are legitimate questions. But in a serious disruption, they are not the first questions that matter. The first question is simpler and harder: can the molecules actually move?

Energy security is widely discussed as if it were primarily a question of resource abundance: how much exists, where it is, and who controls it. The Hormuz crisis has exposed something more fundamental. Resilience depends not on the scale of the resource, how much is produced or where it sits, but on whether it can be extracted, processed, transported and delivered when normal routes fail. The chokepoints are rarely where people expect them. There are more of them than most energy security planning ever identifies.

This distinction matters enormously for how energy companies invest, and how investors, banks, insurers and policymakers assess risk. It also reframes what responsible energy security planning requires.

FOUR CASES WORTH UNDERSTANDING

Route optionality: Yanbu and the limits of the bypass

Saudi Arabia's East-West pipeline (Petroline) runs roughly 1,200 kilometres from the Eastern Province to Yanbu on the Red Sea coast, bypassing the Gulf entirely. Its normal operating capacity is around five million barrels a day. Since the current crisis deepened, Saudi Arabia has converted companion natural gas liquids pipelines to carry crude. This has pushed throughput toward seven million barrels a day. This is a significant and rapid response.

But the pipeline is not the binding constraint. Yanbu's export terminals are. Nominal loading capacity at the port runs to around 4.5 million barrels a day; tested operational capacity is closer to four million. Under prolonged disruption, analysts estimate effective throughput approaching four million barrels a day. A substantial achievement, though still significantly below what the pipeline can now deliver.

The lesson is not that Yanbu doesn't matter. It matters enormously, and Saudi Arabia has moved fast to maximise it. The lesson is that the terminal, not the pipe, is where the system is actually constrained. The bypass exists; the export capacity to fully match it does not.

Drilled but uncompleted: the US shale question

US shale is frequently cited as the global swing producer that can offset Middle East supply disruption. The argument rests partly on inventory of drilled-but-uncompleted wells (DUCs) that can be brought online faster than new drilling. This speed advantage over conventional production is real.

But the infrastructure constraints apply here too:. Export capacity from the Permian and other producing basins has its limits. Similarly, throughput across the US LNG export terminals which are spread across the Gulf of Mexico coast and the Atlantic seaboard is already constrained. Global LNG shipping availability further determines how quickly additional US volumes can reach international markets.

In a fast-moving disruption, the shale ramp-up is a medium-term answer to a short-term problem.

Transit politics: Iraq and the limits of the corridor

The third case is less about physical infrastructure and more about political geography. Iraq exports the bulk of its oil through the Basra terminals in the northern Arabian Gulf . This is directly exposed to any Hormuz disruption with no meaningful bypass. The Kirkuk-Ceyhan pipeline offers an alternative route to the Turkish Mediterranean port of Ceyhan, avoiding the Gulf entirely. It has been effectively shut since March 2023, not due to physical damage, but due to a legal dispute between Baghdad, Ankara and the Kurdistan Regional Government over revenue rights and transit authority. International arbitration ruling found Turkey in breach of its Host Government Agreement. Turkey closed the pipeline in response. The infrastructure exists. The oil exists. The corridor exists. What does not exist is the political agreement to use it.

Access as infrastructure: the permission corridor

There is a fourth case that does not quite fit the same category as the others. The Petroline has physical capacity constraints. The DUC inventory has infrastructure bottlenecks. The Kirkuk-Ceyhan pipeline is closed by legal dispute. But the Hormuz corridor that has emerged since February is different. It is functioning infrastructure selectively accessible on terms set by Iran. It is not constrained by capacity, capital expenditure or contract dispute, but by political relationship.

Ships belonging to countries Iran designates as adversarial are excluded. Others can transit. In some cases, ships are paying corridor fees of up to $2 million per vessel. China's vessels were among the first to use this arrangement. Japan has since been granted access. The architecture is explicit: the Strait of Hormuz remains physically operational, but access has been repriced. Is has changed from a route open to all nations at the price of passage, to a conditional resource allocated by a regional power on geopolitical criteria. Tolling transit of waterways is not unusual. Egypt tolls the Suez and Panama has its canal too. But those waterways pass through those countries.

This is not merely a crisis measure. It is a demonstration that physical infrastructure security and the right to use it are separate problems. Access can be weaponised even when the infrastructure remains intact. The Russia gas crisis of 2022 established that price alone does not guarantee supply. The Hormuz corridor extends this further. Access is not simply cut off, but conditionally priced and politically filtered. That is a more difficult model to deal with. Some buyers can still transit, which divides the political response. This creates incentives for accommodation to avoid disruption now rather than diversification to avoid future exposure. Sovereign risk modelling for any asset exposed to this geography needs to be recalibrated accordingly.

BEYOND THE OIL SYSTEM

The infrastructure constraint runs through the entire energy system, and beyond it. The contract structure governing LNG trade compounds the geographic exposure. European buyers who secured US supply under FOB (free on board) contracts retain the right to redirect cargoes to the highest-priced available market. This is a flexibility that most Asian buyers lack. The majority of long-term Asian LNG contracts are oil-price-linked. Those pricing mechanisms create approximately a three-month lag between a post-Hormuz oil price rise and its full impact on contracted supply costs. Asian buyers now face both immediate physical tightening and a delayed but unavoidable repricing of LNG volumes. The asymmetry is structural, not temporary. It shapes both who bears the near-term cost and who has the flexibility to respond.

And the dependency extends beyond energy itself. One third of global seaborne fertiliser trade transits Hormuz. Since February, urea prices have risen from $400–490 to approximately $700 per metric tonne. This is a rise of between forty and seventy-five percent depending on grade and origin. China has restricted fertiliser exports to protect its own domestic agricultural market, removing a supply buffer that South Asian buyers had been relying on. Bangladesh, India, Pakistan and Sri Lanka face the steepest exposure. This disruption will affect food production timelines for the next agricultural cycle and food prices at retail level months after any resolution. The molecules that cannot move is not only hydrocarbons.

Helium keeps MRI scanners running and semiconductor fabs operational. It also transits Hormuz in significant volumes. Specialist chemicals and plastics that semiconductors cannot be manufactured without are similarly exposed. A disruption to molecular supply chains does not stop at the energy sector. It reaches into healthcare, food security and the digital economy — across much of the industrial base that advanced economies assume is insulated from energy market volatility.

The same concentration logic applies to the energy transition, though through different geography entirely. The hardware required, take solar panels, batteries, wind turbine components, for example, are built from critical minerals whose extraction and processing are as geographically concentrated as any oil export route. A lithium battery in a Chinese factory is not a lithium battery in a European energy storage system. The lithium, the processing chemistry, the shipping, each is a point of failure.

THE PRACTICAL TEST

When I was running operations in the Western Desert of Egypt, I was responsible for production of around 100,000 barrels of oil equivalent a day and the safety of 1,500 staff and contractors. Infrastructure was never abstract. That applied not only to the production facilities themselves, but to every link in the supporting chain. This included food trucks reaching remote desert locations, staff buses running reliably, the logistics that kept them safe and operational in an unforgiving environment. What that experience taught me was to plan not for what should work, but for what might not. Some plans hold under pressure. Others only hold on paper. Assume the worst, hope for the best is one way of thinking about it. Hope is not a method, is another.

At ADNOC, the stakes were both national and global. ADNOC is one of the world's largest national oil companies (NOC) and it shapes the country's energy future. When I was there, we had COP28 to be hosted in Dubai on the horizon, and the world watching how a major Gulf producer would navigate the energy transition. My role was to integrate energy supply reliability and energy transition planning not as competing priorities, but as a single challenge. This is responsible energy security.

The useful test for any energy system is to trace your supply chain from source to final use, and ask at every link: how many genuine alternatives exist. Not theoretical ones, but how many alternatives that can handle the volume, within the timeframe, at affordable cost? And what is your plan when even those are unavailable?

Most energy systems, when tested this way, look more fragile than the production figures suggest. The honest answer is that this question is not fully addressed.

That is what responsible energy security requires us to confront. Not just whether the barrels are there, but whether they can move when the system comes under stress. The Hormuz crisis has forced that question into the open.

Infrastructure cannot be conjured in a crisis. The time to ask whether your molecules can move, and what your plan is when they cannot, is before that day arrives. Returning frequently to ask ourselves those questions as the world changes around us is what responsible energy security actually requires.

Responsible Energy Briefing is published monthly. If you found this useful, consider sharing it with a colleague.

John MacArthur FREng FEI is Director of Highland Sustainability Limited, Visiting Professor at Imperial College London, and Honorary Chair of the London College of Energy Economics. He was previously Group Climate Change Officer at ADNOC and held senior leadership roles at Shell across carbon strategy, technology and operations.

Energy transitions don't happen in spreadsheets or conference panels. They happen at crisis chokepoints.

Twenty percent of global oil supply and twenty percent of global LNG trade pass through a strait twenty miles wide. Since 28 February, that strait has been operating on Iran's terms: selective, fee-based, and geopolitically filtered.

I know this geography intimately. As Shell's strategy manager in Dubai and later shaping energy transition at ADNOC in Abu Dhabi, security of supply was paramount but a Hormuz disruption at this scale felt like the scenario we planned for and quietly hoped we'd never see. The answer has arrived and it covers both oil and gas.

Oil: Iranian drones struck Ras Tanura. Aramco rerouted crude 1,200 kilometres west to Yanbu. Fujairah, the UAE's bypass terminal for approximately one million barrels a day of Murban crude, was struck and has since restarted. ADNOC has shifted to a wartime export posture centred on the Habshan–Fujairah corridor. The bypass infrastructure built in Abu Dhabi to answer the Hormuz question is now essential, not contingency.

Gas: Ras Laffan, which produces around twenty percent of global LNG supply, was struck on 2 March and again on 18 March. QatarEnergy has declared force majeure. The CEO says repairs will take three to five years. There is no pipeline bypass for LNG. Europe gets twelve to fourteen percent of its supply from Qatar. Asia depends on it across China, India, Japan and South Korea.

Three things that shouldn't be ignored:

1. Oil and gas are simultaneously at risk. This at the same chokepoint, at the same time. And it is not just crude and gas. Jet fuel, fertiliser, petrochemical feedstocks, helium for MRI scanners. The downstream dependencies of a modern economy pass through the same twenty miles.

2. Energy security and the energy transition are the same brief. Every investment in renewables, storage and electrification reduces exposure to chokepoints like Hormuz. The Gulf states understand this. UAE's Masdar and the wider pattern of Gulf sovereign reinvestment in clean energy reflect leaders who know transition is strategic, not optional. Decarbonisation is not a cost. It is a hedge.

3. Diversification beats redundancy. The Hormuz shock is accelerating a long-overdue reckoning with LNG source diversification. East African projects, such as those in Mozambique and Tanzania, and expanding capacity in the US, Canada, Trinidad and Argentina matter not just commercially but strategically. A world less dependent on any single chokepoint starts with investment decisions being made today.

Boards should treat security-linked decarbonisation as non-discretionary. Not only because of climate targets. Because of what happens when a strait twenty miles wide closes. You can't model your way out of geopolitical reality.

INSIGHTS

The infrastructure concentration genie is out of the bottle. Force majeure at Ras Laffan means three to five years of structural disruption. This not just a temporary shock to manage through spot markets. Oil bypass routes exist but are constrained: Kirkuk-Ceyhan by Turkish politics, Petroline's Yanbu terminal by export infrastructure. Fatih Birol, the IEA's executive director, described the crisis as "two oil crises and one gas crisis put together". He added that eleven million barrels of oil a day and 140 billion cubic metres of gas are disrupted across nine countries. Any snap-back assumption is difficult to predict in your risk model.

Iran is no longer running a chokepoint. It is running a toll gate with a geopolitical filter. Chinese vessels are transiting Hormuz after paying fees of up to $2 million; Japan has been granted access; countries the regime defines as "at war" cannot pass regardless of price. A market-based chokepoint resolves through price signals and rerouting. A permission-based strait does not. This week Iran confirmed it is the latter. Tehran's military spokesperson stated that "the authority to issue passage permits is ours". Iran's formal ceasefire conditions include recognised sovereignty over the strait. Every energy security framework built on the assumption that commercial logic eventually prevails needs rebuilding.

The Asian exposure is visible in commodity markets right now, not just in forecasts. Japan's trade minister confirmed at CERAWeek that eighty percent of Hormuz LNG flows to Asia. European contracts have held more stable because they draw on US FOB cargoes — FOB (free on board) meaning buyers can redirect flexible US LNG to wherever the market is tightest, a tool most Asian buyers don't have. Asian oil-linked contracts face a further cost wave on a three-month lag. The fertilizer cascade is already real: one-third of global seaborne fertilizer trade moves through Hormuz, urea prices have jumped forty percent since the closure, and China has restricted fertilizer exports to protect its own market. The Philippines declared a national energy emergency on 25 March with forty-five days of fuel reserves remaining; South Korea, which routes seventy percent of its crude through Hormuz, launched an emergency economic task force and suffered its largest-ever single-day stock market decline. This is not a future risk. It is a present emergency.

Responsible Energy Briefing: When molecules can't move — examines the physical infrastructure chokepoints that make the Hormuz situation consequential beyond the immediate crisis. Free to read.