CVC Mandate: A Theory of Corporate Advantage

Your molecule. Your reservoir. Your edge.

Lilia Chechel|The Fifth Chair·October 2026·40 min read

The views expressed are my own. This article draws on publicly available sources and does not constitute investment advice.

Around 2020, several European oil majors began telling investors that their future lay in becoming integrated energy companies. Alongside oilfields and refineries would sit renewables, hydrogen and other businesses serving a lower-carbon economy. As a direction of travel, it seemed understandable: companies that had spent decades supplying energy would invest in the ways it would be supplied next.

The difficulty was deciding how much of their existing advantage would travel with them. Experience in building complex projects, handling molecules and serving industrial customers could be valuable, but not equally valuable in every new market. Each brought different competitors, financing requirements and ways of making money. As hydrocarbon profits recovered and some transition investments disappointed, shareholders challenged the allocation. BP sharply reduced its transition ambitions, while TotalEnergies continued building an integrated electricity business. The same opportunity had produced opposite answers.

For corporate investment, the question is therefore more demanding than which technologies might shape the future. It is which of those technologies a particular parent can help turn into a successful business, and what it stands to gain by doing so. A sector can belong in the energy transition without belonging in every energy company’s investment mandate. An investment mandate, in other words, is not a list of sectors but a theory of corporate advantage.

Oil and gas provides the case study for working through that distinction. Before considering where its capital is best deployed, however, it helps to understand what these companies already own, how they earn their money, and why their owners might want them to pursue something different.

The industry at a glance — and why it ventures at all

Oil and gas is the largest industrial complex on earth. It supplies more than half of all the energy humanity uses, turns over around $6 trillion of revenue a year, directly employs on the order of 12 million people, and underpins the budgets of dozens of governments. It is a resource business first, a commodity business second, and a cyclical, capital-heavy business third — those three facts explain most of its behaviour. And it is dominated not by the household names of the stock market, such as ExxonMobil, Shell or BP, but by the state.

Different owners, different cycles, different mandates

The first point is the one most often missed. State-owned NOCs (National Oil Companies) control ~60% of reserves and over half of production; the seven listed supermajors hold under 13%; and only ~7% of world reserves are freely open to private companies. Saudi Aramco, the world’s most valuable oil company, floated just 1.5% of its shares — the state kept the rest.

This matters for corporate investing because a venture arm serves its parent, and the parents are very different institutions. Many deliberately stay state-owned or private, for concrete reasons: sovereign control, confidentiality (in the case of the traders), patient capital, freedom from quarterly and ESG pressure, or simply being too small to list. Each type of parent optimises for something different — and brings a different agenda to its venture arm:

Ownership is not a technicality; it changes what a company is for — and therefore what its investment arm is for.

The second point is where a company sits on the value chain, because the segments are counter-cyclical to one another. When crude is expensive, upstream producers earn enormous margins while refiners and marketers, who buy crude as their raw material, get squeezed. When crude is cheap, the reverse happens. This is the logic of the integrated major — an ExxonMobil, Shell or TotalEnergies that owns assets along the whole chain, so the downstream can cushion the upstream through the trough. Companies that sit in only one segment — a pure-play shale driller, an independent refiner, a midstream pipeline operator — are more exposed to their own slice of the cycle: higher-risk, but often higher-return. That exposure shapes what each company wants from the transition and from its investment arm — including, for some, a hedge against their own slice of the cycle.

Whatever its parent and wherever it sits on the chain, every company in the industry shares one underlying question: how long does the resource last?

Abundant, but not cheap

The reassuring news first: on any mainstream measure, the world is not about to run out. Proven oil reserves are around 1,570 billion barrels and proven gas around 210 trillion cubic metres — roughly fifty years of each at today’s output.

In 1980, the world’s proven oil reserves amounted to about thirty years of production at the time. Read as a countdown, that would have put the empty tank around 2010. Yet forty-five years of extraction later, the latest figures still show more than half a century’s production in proven crude reserves.

Reserves are not a fixed tank that only drains; they are an economic inventory that grows as prices rise and technology improves. The US shale revolution turned rock that was worthless in 2005 into the world’s largest source of oil growth within a decade, and made the United States — not Saudi Arabia — the world’s largest producer.

So the binding constraint is rarely the rock; it is above ground — price, policy, capital and access. Plentiful, however, is not the same as cheap. Much of the remaining resource is heavy, sour, deep or remote, and conventional discoveries are running at multi-decade lows. Meanwhile depletion is relentless: existing fields decline ~4% - 6% a year, so the industry must add the equivalent of a new large producer every few years just to stand still. The honest long-run worry is therefore not running dry. It is that each replacement barrel tends to be harder, dearer and more carbon-intensive than the one before it.

Scarcity, in other words, is not what pushes an oil company beyond the barrel. Something else does.

If oil is not running out, why look beyond the barrel?

Because the risk was never supply. It is demand, price and permission. Several forces push even the most hydrocarbon-committed group to look beyond the barrel:

  1. The growth is in electrons, not barrels. Total primary energy grows slowly, but electricity roughly doubles by 2050 according to IEA estimates, with AI adding a new source of concentrated demand. The fastest-growing energy market is one most oil companies barely sell into, yet it lands on exactly the grids and gas-for-power markets where they could compete.
  2. Oil demand may peak before the resource does. Electric cars and more efficient engines are slowly reducing how much oil the world needs, and the IEA expects demand to level off around 2030. If it then falls, some of the oil that companies own today may simply never be used.
  3. Carbon now carries a price and a liability. EU carbon pricing, the border adjustment on imports, and methane rules that decide market access from 2027 turn emissions into a cost line and a licence-to-operate question.
  4. The next barrel is dearer. Technology that lowers the cost of carbon of replacing depleted production is therefore worth real money. Investing in innovation does not always mean moving beyond the barrel; sometimes it means future-proofing it.
  5. Disruption is a tail risk worth watching. Well-funded efforts in fusion, next-generation geothermal, long-duration storage and space solar, to name a few, may or may not reach scale. An energy company that is not watching will be the last to know.

Those forces explain why looking beyond the barrel made strategic sense. They do not establish that any particular opportunity belongs in a venture portfolio, rather than in operations, a JV or a directly owned asset.

The transition meets the hurdle rate

As European majors expanded their transition ambitions around 2020, the industry was already emerging from a decade in which chasing production growth had repeatedly destroyed capital. The 2020 crash hardened the lesson; the 2022 price spike then made hydrocarbons look both indispensable and extraordinarily profitable. At the same time, renewable-power returns disappointed relative to the double-digit returns available in oil and gas.

The result was a new compact with investors: hold capital spending broadly in check, defend a dividend covered at a conservative oil price, and return surplus cash through buybacks that flex with the cycle. The dividend is the promise; the buyback is the shock absorber. At around $70 Brent, the leaders have generated total shareholder yields of roughly 7%-11%.

That created a difficult benchmark for transition capital. A dollar invested beyond the barrel was no longer competing only with another transition opportunity; it was competing with another well, another project, a buyback or cash returned to shareholders.

BP's February 2025 reset cut planned low-carbon investment by around 70% and raised annual oil and gas investment by roughly 20%; Equinor scaled back its renewables targets the same month; Shell softened its transition ambitions; ExxonMobil and Chevron had never made the same pivot into renewable power in the first place. The transition had not disappeared. For the listed majors, the hurdle rate had gone up.

State-owned companies, under less pressure to return cash, could choose differently: ADNOC, for one, launched XRG to invest internationally in gas, chemicals and low-carbon energy. Same transition, different owner, different answer.

Venture capital was not immune. In July 2026, BP proposed closing BP Ventures and agreed to sell stakes in more than ten portfolio companies to Verdane, retaining selected investments as part of a wider simplification of the group. TotalEnergies had taken a similar step in 2023, closing its venture arm and selling a portfolio of around 20 start-ups to the Paris-based investor Aster — even as it kept building its integrated power business. The wider climate-tech market had cooled too: Crunchbase reported a 46% year-on-year decline in cleantech and sustainability investment in the first half of 2025.

None of this proves that corporate venturing has failed. It does show that, when capital becomes scarcer, a venture portfolio must earn its place alongside every other use of the balance sheet.

That is the tension at the heart of the investment mandate. The strategic reasons to look beyond the barrel may be getting stronger, while the financial tolerance for investing without a clear advantage is getting weaker.

A CVC competing as a generalist investor, in markets where the parent contributes little beyond its cheque, risks becoming a momentum-chasing venture tourist. It must justify itself against specialist infrastructure, venture or PE funds, direct investment in the core business and, ultimately, returning the cash to shareholders.

Which raises the question this article is really interested in: where does an energy company bring something that other capital does not?

Carbon provides a useful first test. It creates several new markets around a molecule the industry already knows how to handle, but not every opportunity in those markets belongs on an operator's balance sheet, much less in its venture portfolio.

A priced molecule, and an operator’s edge

The world has decided — through regulation, corporate commitments, and capital markets — to put a price and a liability on carbon dioxide. That decision creates a new commodity (the tonne of CO₂ avoided, captured, stored, or removed) and a new set of infrastructure and markets to handle it. Building and owning pieces of that system is a real business. But it is an early, policy-dependent, and uneven business: some parts are bankable today, many are not, and the political tailwind that drives it is real but reversible.

The through-line is simple: the physical infrastructure business (capture, transport, storage) is real and scaling; the paper markets (credits, offsets) are real but small, volatile, and in a credibility clean-up. An operator should weight the former far more heavily than the latter.

Where an operator actually fits

The single most important idea here is that an oil and gas group is not a generic climate investor. It holds specific, hard-to-replicate assets that map onto specific value pools.

Just as important is where no special advantage exists. Novel materials chemistry, consumer-facing mobility, software, and most early-stage utilization science may be strategically relevant without being natural ownership plays. In those, an operator that plays at all may contemplate playing small and through others. CO₂ into a saline aquifer really is just reservoir engineering; running a chemical-recycling plant is not "just refining". Adjacency is not the same thing as advantage.

Where the moat is real: CO₂ storage as the toll road

Transport and storage is the business of moving captured CO₂ — by pipeline or ship — to a suitable rock formation deep underground, injecting it, and keeping it there permanently, for a fee.

Of every value pool in carbon circularity, this is the one where an oil and gas group’s existing assets, skills and balance sheet translate most directly into a defensible, annuity-like business. If capture is a commodity and air capture is a venture bet, storage is where the money and the moat actually sit for an energy group: in the pipe and the reservoir.

The mental model is the toll road. A storage operator builds expensive infrastructure once, signs long-term contracts with emitters that need somewhere permanent to put their CO₂, and then collects a per-tonne fee over the life of the asset. Once contracted, commodity-price exposure is relatively limited. The barriers to entry are not trivial: pore space, permits, subsurface skill, capital and public acceptance all matter, and customers cannot switch storage sites as easily as they can switch suppliers of a commodity product.

The rock may be abundant; permission is not

Storage itself is conceptually simple. CO₂ is injected roughly a kilometre or more underground into either a saline aquifer or a depleted oil and gas field. The geological capacity is vast. The harder constraints are often above ground: permits, pore-space rights, community acceptance and the confidence that a particular reservoir will behave as modelled.

The economics of owning the sink

Storage demand rests on three unusually sturdy legs, because storage is the indispensable final step in the carbon chain. Every tonne captured ultimately needs somewhere permanent to go.

Taken together, these mechanisms can turn geological storage from an environmental obligation into an infrastructure business: contracted demand from emitters, policy support around the revenue line, and public capital helping to absorb part of the first-mover infrastructure risk.

The brownfield advantage

A real benchmark: Santos’s Moomba project in South Australia stores CO₂ in depleted onshore gas fields. It cost about US$220 million to build and reports lifecycle storage costs under $30 a tonne. Because Moomba’s CO₂ is already separated at the gas plant, its reported costs largely avoid the expense of building a new capture process. Moomba earns Australian carbon credits rather than a US-style tax credit, but set an illustrative ~ $25-per-tonne lifecycle cost against the $85 per tonne available to an eligible US project under 45Q, or against a contracted service fee, and the potential economics are compelling. Large storage hubs are billion-dollar builds; Moomba shows how reusing existing oil and gas fields and infrastructure can cut the capital bill dramatically.

Every marquee hub is O&G-led

The table shows how heavily oil and gas operators feature in large-scale storage.

Hub / project Location O&G owners
Northern Lights Norway Equinor / Shell / TotalEnergies
Northern Endurance / Net Zero Teesside UK BP (op.) / Equinor / TotalEnergies
Aramis Netherlands TotalEnergies / Shell / EBN / Gasunie
Greensand Denmark INEOS / Harbour Energy/ Nordsøfonden
Bayou Bend Texas (US) Chevron (op.) / TotalEnergies/ Equinor
ExxonMobil / Denbury US Gulf ExxonMobil
Jubail Saudi Arabia Aramco / Linde / SLB
Habshan UAE ADNOC
Moomba Australia Santos / Beach

Northern Lights: the template worth studying

Northern Lights is probably the cleanest commercial architecture in the set. Equinor, Shell and TotalEnergies each hold a third of a joint venture that built an open-access, cross-border storage service.

CO₂ is liquefied at the emitter’s site, shipped to Øygarden on Norway’s west coast, then transported offshore and injected around 2,600 metres below the seabed. Phase 1, with capacity of 1.5 million tonnes a year, began injection in August 2025 and is fully booked; Phase 2 expands capacity beyond 5 million tonnes a year.

The architecture is instructive: shared capital, state support, multiple customers and expansion pulled by contracted demand rather than pushed by hope. The honest qualifier: the project closed only because the Norwegian state de-risked Phase 1 heavily. Storage done well arguably looks like Northern Lights.

The risks: permits, communities and injectivity

The technology is not the risk. The O&G industry has injected CO₂ for enhanced oil recovery for over fifty years. The execution risks cluster in three places, and each has a live example.

What does this mean for the CVC mandate?

Storage exposes an important distinction: strategic relevance is not the same as venture relevance. The storage asset itself has an infrastructure return profile: high upfront capital, long life and contracted cash flows. It therefore belongs more naturally in direct ownership, infrastructure capital, M&A or a JV than in a minority venture portfolio.

But around every toll road sits a layer of technology the operator may need and not own: monitoring that proves the CO₂ stays put, well-integrity and injection tools, CO₂ shipping and conditioning, and software that models how a reservoir will behave. These are genuine venture opportunities, and the operator's storage sites give portfolio companies something few generalist funds can offer directly: a real site to prove the technology and a first customer. The infrastructure is owned; the enabling technology is ventured.

Methane: the boring thing that makes money

Every other value pool asks the operator to enter some unfamiliar territory: to become a storage landlord, a carbon-credit originator or a new-molecule project developer. Methane abatement asks the opposite. It asks the operator to look at its own operations and recognise that one of the highest-return, fastest climate actions available to it can be executed with its existing people, on its existing assets and, in many cases, pays for itself without requiring a carbon price at all.

Methane is the operator’s own molecule. It already produces it, transports it, measures it and sells it. Abating emissions is, at root, stopping saleable product from escaping before it reaches the customer. That gives the operator a home-field advantage outsiders cannot replicate.

Two numbers explain why methane deserves disproportionate attention:

  1. It is the cheapest lever. The IEA estimates that around 30% of oil-and-gas methane emissions could be cut at no net cost — the recovered gas is worth more than the fix, often earning returns well above the hurdle rate O&G companies apply to new capital.
  2. It is the fastest lever. Methane is a short-lived but extremely potent greenhouse gas — cutting it delivers near-term climate benefit faster than almost any CO₂ action. And roughly 70% of energy-sector methane emissions could be eliminated with existing technology — no invention required.

Where the methane comes from

Natural gas is methane — typically 70% - 90% of it or more. And oil wells produce gas too: it comes up dissolved in the crude, like the bubbles in a fizzy drink. So wherever oil or gas is produced, processed or moved, methane can escape in three principal ways:

The scale of the prize

The problem is large and, alarmingly, not improving. Fossil-fuel operations emitted around 124 Mt of methane in 2025. That is roughly a third of all methane released by human activity — second only to agriculture, and broadly comparable to everything the world's cattle, sheep and other livestock emit. Because methane traps more than 80 times as much heat as CO₂ over its first twenty years, it punches far above its weight: methane as a whole is responsible for nearly 30% of the rise in global temperatures since the Industrial Revolution.

The measurement problem makes the operating opportunity larger than reported inventories suggest. The IEA estimates that energy-sector methane emissions are around 80% higher than governments report. In practical terms, operators are often losing more product than their own inventories show, which is precisely why better detection and measurement matter economically as well as environmentally.

Flaring makes the waste visible. Global gas flaring rose to around 167 bcm in 2025, the highest level since 2019. That is almost as much gas as Africa consumes in a year. Not all of that gas could have been economically captured, but the scale is a useful reminder: methane emissions are not merely a carbon problem; they are a product-loss problem measured in very large volumes.

Why the economics really are this good

In a CCS or DAC project, the tonne of CO₂ has no intrinsic market value — someone must be found and persuaded to pay for the environmental service. The whole business is manufacturing a buyer for an otherwise worthless tonne. Methane is the mirror image: the abated molecule already has a buyer. When a leak is fixed or a vent is captured and routed to the sales line, the "carbon benefit" and the "revenue" are the same physical event.

The cheapest fixes are mundane: swapping valves that run on gas pressure for ones powered by electricity or compressed air, tightening leaking valves and joints, and fitting covers that capture the gas escaping from oil storage tanks. Each typically costs a few hundred to a few thousand dollars and recovers gas continuously for years. Payback is often measured in months, not years.

Exhaust the cheap tranche first

The cost curve has a shape that dictates strategy. Abatement is cheap-to-free at the front (fugitive leaks, low-cost venting) and expensive at the tail (flaring at remote fields with no pipeline to carry the gas away, remote stranded gas needing pipelines or reinjection). The disciplined play is to exhaust the cheap tranche everywhere first — it earns money — and treat the capital-heavy tail as a conventional infrastructure decision.

The compliance forcing function: Europe tightens, the US retreats

Methane regulation is tightening, but unevenly. For an operator, the important distinction is between rules that reinforce an already attractive operating action and rules that are required to make the economics work at all.

In Europe, methane performance is increasingly becoming a market-access condition. The EU Methane Regulation requires more rigorous measurement, reporting, leak detection and repair, and tighter controls on routine venting and flaring. Its import provisions push that discipline beyond Europe itself: from 2027, importers must demonstrate equivalent monitoring and verification standards across their supply chains, with methane-intensity requirements tightening further towards 2030. For producers selling gas into Europe, methane therefore moves from an ESG metric to a commercial one.

The United States provides the opposite lesson. The US Waste Emissions Charge, enacted in 2022, set a fee of $900 per tonne on methane above set thresholds, rising to $1,500 by 2026. In 2025 Congress overturned the EPA rule needed to collect it and then postponed the charge itself until 2034. This is the cleanest live example of policy-reversal risk: a $900 - $1,500 per tonne price signal was switched off within three years of enactment.

The implication is straightforward. Methane abatement should not be underwritten primarily on a carbon price or penalty. The stronger case rests on two things that survive political change: recovered gas has intrinsic value, and low-methane supply increasingly supports access to demanding export markets. Regulation strengthens the economics; it should not be the only reason they exist.

Peers are already moving

The direction of travel is visible in what serious operators are already doing. ConocoPhillips, TotalEnergies, Snam and Eni are among the companies using OGMP 2.0-style measurement and reporting to demonstrate methane performance with greater rigour, while ExxonMobil and Aramco have used satellite-based monitoring services such as GHGSat to detect emissions at facility level.

The important shift is from periodic inspection towards continuous or near-continuous monitoring. Satellites, aerial surveys, fixed sensors and advanced analytics are turning methane from an annual reporting exercise into something closer to an operational control system.

What does this mean for the CVC mandate?

Methane draws a useful line for the mandate. The operator should fix the leak itself. The venture opportunity may sit one layer away, in the technologies that make that response faster, cheaper or more precise: sensing, satellite detection, continuous monitoring, quantification, analytics and automated leak identification. CVC earns its place where an external technology can strengthen a corporate advantage, not where it merely puts an equity wrapper around something the parent should already be doing. Fixing the leak is operations; finding it is venture.

Firm power: where the edge becomes more interesting

If methane is the operator’s molecule and storage its rock, the AI-and-data-centre demand shock has forced a third question onto the table, one that turns on both. But to understand where an oil and gas company might have an advantage in power, it helps first to understand what is becoming scarce.

Power is not one product

After roughly a decade of near-stagnation in the developed world, electricity demand is growing again, driven by electrification, industry, cooling and, increasingly, data centres. That changes the renewables challenge: they must now do two jobs at once, decarbonise existing supply and meet the growth of an expanding power system. Growing renewables in a flat system is largely a replacement problem; growing them in an expanding one is a replacement-and-growth problem, raising the premium on reliable capacity, not merely cheap energy.

Solar and wind have become extraordinarily cheap. Utility-scale solar now commonly produces electricity at around $30-$60/MWh, and onshore wind at around $30-$70/MWh, against roughly $45-$75/MWh or more for a new combined-cycle gas plant depending on the gas price. Solar alone now accounts for the majority of all new generating capacity being added globally, while renewables as a whole supply around 30% of global electricity.

But cheap energy is not the same thing as available power.

A solar plant typically operates at a capacity factor of only 10% - 25%, depending on latitude. Onshore wind runs at roughly 25% - 45% and offshore wind at 40% - 55%. Geothermal, by contrast, can operate at 80% or more, around the clock and regardless of weather.

That difference is easy to underestimate. At a 20% capacity factor, 1 GW of solar produces about 1.75 TWh over a year. At an 80% capacity factor, 1 GW of geothermal produces about 7 TWh, four times as much. But annual output is only part of the distinction. The more important question is whether those electrons arrive when the system needs them.

And timing increasingly determines value. A megawatt-hour of solar delivered at noon into a market already saturated with solar can be worth far less than a megawatt-hour delivered on a windless winter evening. At high renewable penetration, wholesale prices can fall to zero or below when solar and wind are abundant, while generators may have to be curtailed because the system cannot use or move their output. As the sun sets, often just as evening demand rises, the system must then find fast, flexible capacity to replace it.

So the paradox is that the success of cheap variable power creates scarcity somewhere else. As grids fill with solar and wind, the scarce product shifts from energy, abundant and cheap when the resource is available, towards firm capacity and flexibility: power available when called.

The familiar “cheapest source of energy in history” framing therefore describes the energy value of solar and wind in isolation. It says nothing about their capacity value to a system that must stay balanced every second, nor about their market value net of timing and integration. As a grid decarbonises, those three numbers diverge, and the divergence, not the headline LCOE, is where the money is made and lost.

Firm renewables are surprisingly scarce

The obvious answer might be simply to build more firm renewable generation. The difficulty is that genuinely firm renewable supply is surprisingly constrained.

Hydropower remains the world's largest renewable source, and reservoir hydro is one of the most valuable flexibility assets on a grid. But many of the best sites in North America and Europe were developed long ago.

Geothermal is even more revealing. It can run at capacity factors above 80%, yet conventional geothermal supplies well under 1% of global electricity, largely because suitable geology has historically confined it to a handful of locations. Bioenergy is dispatchable too, but constrained by feedstock scale, cost and sustainability.

That scarcity changes where value sits. The renewable opportunity is becoming less about another panel or turbine and more about the infrastructure and technologies that make variable generation useful: transmission, storage, flexibility and firm capacity.

Value is migrating from the generator to the things that make the generator useful.

The cost-of-capital trap

In a commodity-return business, the lowest cost of capital wins. Merchant renewables and, increasingly, EV charging are commodity-return businesses: the electrons and charging sessions are undifferentiated, so competitive advantage collapses onto who can finance, develop and commercialise the asset most effectively.

The natural long-term owners of operating, contracted renewable assets are low-cost-of-capital, long-horizon investors such as pension funds, sovereign wealth funds, insurers and dedicated infrastructure managers. They can accept steady, contracted, mid-single-digit-to-low-teens returns and compete primarily on their cost of funds.

An O&G group generally enters that contest with more expensive capital. An oil major bidding against an infrastructure fund or pension consortium for a solar portfolio is therefore bidding with more expensive money for an asset whose returns are capped by the market. It either loses the auction or risks winning by overpaying. No one out-competes lower-cost-of-capital buyers in their own asset class.

Higher returns in renewables have tended to accrue elsewhere: to those taking development risk by originating, permitting and building projects before selling them once de-risked to the low-cost owners (the “develop-and-farm-down” model); and to integrated players that combine generation with retail supply, trading, storage or flexible assets and capture more of the value chain actively managing price and shaping risk. Passive ownership of merchant generation, by contrast, has repeatedly proven vulnerable to value deflation.

The decisive question is therefore who actually earns an excess return. In commoditised generation it is generally not the party with proprietary technology. Durable advantage tends to lie in the lowest cost of capital, development and permitting capability, scarce grid-connection positions, and the origination muscle to secure creditworthy long-term offtake. The useful question is not simply “how cheap is the LCOE?” but where in this value chain is the durable advantage, and is it financial, positional or commercial?

A surge in electricity demand does not change that logic. It lifts power prices and PPA volumes for incumbent renewable generators too; it hands the oil major no advantage it did not already have.

What the surge does change is the value of firm, deliverable capacity. And this is where the power question becomes more interesting for an oil and gas company. If the scarce product is not simply another megawatt-hour, but one that can be delivered when required, some of the inputs begin to look familiar: the gas molecule, the reservoir for its CO₂ and the drill bit for geothermal heat.

Those are quite different propositions from simply buying renewable generation.

Data centres sharpen the problem

The AI build-out sharpens that scarcity further because, for the first time in the cloud era, power is becoming a binding input rather than an incidental operating cost. Data centres used about 1.5% of world electricity in 2024; the IEA expects their consumption to more than double by 2030 to around 945 TWh, slightly more electricity than Japan consumes today. The level is still relatively small; the growth rate is the shock.

The capital is arriving just as quickly. In 2025, global data-centre investment, at roughly $580bn, overtook the ~$540bn spent on global oil supply. A frontier data-centre campus can require hundreds of megawatts or even gigawatts, while grid connections, generation, transformers and permits can take years to secure.

In that setting, the scarce asset is not simply electricity. It is firm, deliverable power in the right place and on the right timetable.

The scarcity is real, and it is being paid for

The market is already putting a price on this scarcity. In parts of the US, power generators are paid not only for the electricity they produce, but also for committing capacity that will be available when the grid needs it. In PJM, the power market covering much of the US Mid-Atlantic and Midwest, the price of that capacity jumped more than ninefold for 2025/26, from $28.92 to $269.92 per MW-day, and rose again to the $329.17 price cap for 2026/27. In MISO, another major US power market, the summer capacity price rose roughly 22-fold to $666.50 per MW-day.

The system is paying for the ability to produce when power is needed. In PJM, the market monitor attributed around 40% of the latest capacity cost to rapidly growing data-centre load.

Two firm-power routes sit on the operator’s side of the fence in a way solar never did:

The case for — stated fairly

GE Vernova’s gas-turbine backlog and slot reservations reached 116 GW by mid-2026, with customers already booking delivery slots for 2031; Siemens Energy reported that data centres accounted for roughly 60% of its gas-turbine orders at one point in 2025. Scarcity of firm capacity is exactly the condition under which control of fuel, generation capacity and deliverability can command a premium rather than be competed to the bone.

The proof points are no longer hypothetical, and they come from the industry’s own leaders. ExxonMobil announced a ~1.5 GW gas plant dedicated to a data centre, off-grid, capturing more than 90% of its CO₂, with its chief executive calling low-emission gas “probably the only realistic game in town.” Chevron has gone furthest: in June 2026 it signed a 20-year power agreement with Microsoft for “Project Kilby,” a ~2.67 GW off-grid gas plant in West Texas. Carbon capture, where deployed, can also earn the 45Q credit, preserved and enhanced for certain uses in the July 2025 tax law even as wind, solar and hydrogen credits were curtailed.

Geothermal makes the right to win cleaner still, because there is no fossil molecule to defend. Fervo Energy cut its per-well cost from $9.4m to $4.8m using shale drilling techniques, and this year drilled its deepest well yet in just 21 days. It is backed by Devon Energy, and raised $1.89bn in a May 2026 IPO. The US Department of Energy says plainly that enhanced geothermal “use[s] techniques similar to those in oil and gas”. Here, unusually, one of the industry's core operating skills is embedded in the technology itself.

The case against — stated just as fairly

Start with the uncomfortable one: carbon capture on power has a poor operating record. Boundary Dam was designed to capture 90% of its unit’s CO₂ but has managed under 60%; Petra Nova was offline on 367 days in its first three years before being mothballed in 2020; Kemper County abandoned capture entirely after costs more than doubled to $7.5bn. Across sectors, a review by the critical think tank IEEFA found that ten of 13 flagship carbon capture projects had failed or underperformed, “mostly by large margins”.

The economics lean hard on subsidy. New gas plants with carbon capture produce power at around $70 - $120 per MWh — competitive only once the US 45Q tax credit is counted. And the data-centre owners buying the power rank their priorities as "speed, cost, carbon" — carbon last. Government support is also fickle: the same US administration that increased 45Q in 2025 cancelled billions of dollars of carbon-capture grants that same year. What policy gives, it can take away.

The demand itself may prove less firm than the order books imply: Microsoft has walked away from an estimated 2 GW of data-centre leases; the IMF and the Bank of England have both warned of an AI-driven market correction. An off-grid plant built for a single hyperscaler that later trims its footprint is a stranded-asset risk of exactly the kind that produced BP’s impairments. And turbine lead times of five to seven years make new gas capacity a 2030-and-beyond proposition.

What does this mean for the CVC mandate?

AI infrastructure illustrates why a theme does not determine the instrument. A model company, a data centre, a power plant and a grid connection may all sit inside the same AI story, yet each belongs to a different capital pool. The same is true here. A gas plant with capture, or a geothermal field, is project finance and direct ownership — not a venture stake. But the technologies that make firm power possible — next-generation drilling and well design, capture systems, reservoir modelling, flexibility software — are genuine venture territory, and the parent's rigs and sites are where they get proved. Fervo's backing by Devon Energy is the template: the corporate brings the drilling know-how and the test ground; the venture brings the technology.

How peers actually play it

So far, the argument has been about where an oil and gas group should have a right to win. The peer record tests that against what operators have actually done — and, more usefully, what worked, what stalled, and what had to be unwound. These are not tidy success stories. Read as a set, they confirm the central thesis with unusual clarity: the strongest investment plays are the ones built on genuine O&G capability — subsurface, storage, project delivery, captive volumes, trading — and the plays that stalled or were abandoned are the ones where a green ambition ran ahead of any real right to win. TotalEnergies adds an important qualification: that advantage need not come from the asset alone. In power, it can come from the operating model around it. These are not all venture investments; they show where the venture mandate should stop as well as where it might begin.

Occidental / 1PointFive — the DAC pure-play bet

Occidental has made the most aggressive corporate bet on direct air capture of any O&G company. It is building STRATOS, a ~$1.3bn commercial-scale DAC facility in West Texas, now due to start operations at the end of 2026. It stacked every layer of capital: it bought its technology partner Carbon Engineering for ~$1.1bn, brought in $550m from BlackRock’s infrastructure arm, and anchored the economics on the $180/tonne DAC 45Q credit plus a landmark 500,000-tonne, six-year offtake to Microsoft.

Worked: demonstrated that a first-of-a-kind commercial DAC plant could attract the capital and offtake required to get built, and that a credit-offtake market could be manufactured from AI-driven corporate demand. It also shrewdly leveraged its actual right to win — subsurface storage and EOR expertise in the Permian. At risk: DAC economics remain the most fragile in the field, with unit costs in the hundreds of dollars per tonne, a start-up already two years late, and acute exposure to any weakening of 45Q.

ExxonMobil — the Gulf Coast storage “toll road”

ExxonMobil made the biggest bet on being the infrastructure owner of the US carbon economy. The centrepiece was the July 2023 acquisition of Denbury for ~$4.9bn in all-stock, which handed it the largest owned CO₂ pipeline network in the US — over 1,300 miles, plus access to more than 15 onshore storage sites. It has signed six customers for roughly 9 Mtpa of transport and storage, against a stated potential of 100+ Mtpa.

Worked: Exxon executed exactly the play where an O&G group’s right to win is strongest — buying and owning the subsurface-and-pipeline infrastructure, then renting it out. Stalled: the gap between 9 Mtpa contracted and 100 Mtpa aspired-to is the whole story. Energy Analytics Institute framed it as a “Field of Dreams” question — will the emitters come? The strategic logic of the storage toll road may be compelling; the commercial question is whether enough traffic arrives. Incumbency in an empty network is a cost centre, not a moat.

Aramco — the captive-anchored mega-hub

Aramco is building one of the world’s largest CCS hubs at Jubail, Phase 1 designed to capture and store up to 9 Mtpa from 2028 — ~6 Mtpa from Aramco’s own gas plants and ~3 Mtpa from neighbouring industrial emitters — through a JV with Linde and SLB. Jubail is perhaps the clearest expression of the captive-anchor model: the hub is de-risked from day one because Aramco fills two-thirds of Phase 1 with its own CO₂, designed to avoid the empty-hub problem that dogs Exxon’s Gulf play. Build the first phase on controlled volumes, then layer third parties on top.

BP and TotalEnergies: same transition, different discipline

BP is the essential counter-example. From 2020 it committed to a rapid pivot into renewables, EV charging, hydrogen and a broader “integrated energy company” identity. In February 2025 it reversed course in what its chief executive called a fundamental reset, admitting the company had “chased too much” and gone “too far, too fast” and refocusing the group on oil and gas, narrowing its transition portfolio and moving parts of its renewables exposure towards more capital-light structures and partnerships.

The relevant lesson from BP is not that “going green” fails. It is that strategy can stretch beyond native advantage faster than the operating model, cost of capital and return discipline can follow.

TotalEnergies is the instructive exception — the major that has made the clearest financial case for integrated power. Total did not bolt renewables onto an oil company; it built an Integrated Power business as a co-equal pillar, and it did so with ruthless financial discipline. Its 2025 Strategy & Outlook targets a 12% return on average capital employed (ROACE) by 2030 — explicitly benchmarked to equal its upstream oil portfolio at $60 oil — on Integrated Power capex of just $3 -$4bn a year, and the company now expects the segment to turn free-cash-flow positive by 2028. In 2024 the segment generated $2.6bn of cash flow at a 10% ROACE; in the twelve months to March 2026 it earned impressive 9.3%, against 12.7% in its upstream business.

The mechanics matter: Total operates an integrated model in a few deregulated markets (US, Europe, Brazil), pairing renewables with flexible gas and batteries, selling ~70% under long-term contracts and 30% into spot to harvest volatility, and — crucially — recycling capital by "farming down" (selling ~50% of) renewable assets once commissioned and redeploying the proceeds — precisely the develop-and-farm-down, integrated model that the firm-power chapter identified as where excess returns in power are earned. In December 2024 it bought German developer VSB for €1.57bn while simultaneously selling 50% of a 2 GW Texas solar-and-storage portfolio to Apollo-managed funds.

The takeaway is simple: chasing renewable volume was not enough. Total treated power as a business with its own return hurdle.

Taken together, the cases suggest that a corporate right to win is only the beginning. The asset still needs demand, the project still needs an appropriate capital structure, and the economics still need to survive without heroic assumptions about policy or offtake.

Which brings us to what actually kills returns.

Where the investment case is most vulnerable

Everything so far has been about where the money might be. This section is about how it can disappear, even when the technology is promising and the strategy makes sense. For a corporate investment arm, strategic enthusiasm must not become a substitute for underwriting.

Carbon and transition investments can carry three risks at once: a market that depends on policy or a handful of buyers, a technology that has yet to prove its economics at scale, and a reputation exposed when promises run ahead of results. Worse, these risks can feed one another. A policy reversal weakens demand, the project misses its financial targets, and the resulting write-down becomes the reputational story.

A right to win is not a guarantee of a return. The question is what happens to the investment when one of its underlying assumptions fails.

The hockey-stick trap

There is one assumption that can do disproportionate work in a carbon investment case: the forward carbon-price curve. A business that loses money at today’s €85 carbon price can be made to look attractive simply by assuming the price rises to €150, €200 or €250 by 2035. Because the entire revenue line is geared to the carbon price, small changes in the assumed price produce enormous changes in the modelled return. The logic is seductive: if the world is serious, carbon gets more expensive, and the business gets more valuable.

It should be resisted. The same net-zero pathways have been missed repeatedly; the ambition that justifies the high price is exactly what has not materialised. And carbon prices have proven they can fall as well as rise — the UK ETS dropped to £31 in early 2024 before recovering. A forecast is not a floor.

The mechanism of ruin is operating leverage against a floating revenue line. A CCS plant or a DAC facility has largely fixed costs but a revenue line tied to a carbon price the market, not the operator, sets. A modest 30% - 40% carbon-price decline can take an asset from a 12% IRR to a covenant breach, because leverage that was safe at €85/tonne becomes distressed at €45. The single most important structural defence: fix the carbon price contractually — through long-term offtakes, Contracts-for-Difference, or fixed-value tax credits like 45Q — and size debt to a stressed price, not the spot.

The one-whale market

The durable-removal segment crossed 1 million tonnes of actual deliveries for the first time in 2025 — a rounding error against ~37 billion tonnes of annual global CO₂ emissions. And it is extraordinarily concentrated. Microsoft contracted a record ~45 million tonnes in 2025; the second-largest buyer, the Frontier coalition, has contracted ~1.8 million tonnes in its entire lifetime. Microsoft contracted that roughly 25 times over in 2025 alone.

As one analysis put it, “a market where one buyer controls 80 to 90 percent of global demand isn’t really a market. It’s a single-customer dependency.” When reports surfaced that Microsoft had paused new purchases, it exposed exactly how fragile the demand base is.

One tonne, two economics

One simple thought-experiment. Take one tonne of captured point-source CO₂, costing, say, ~$60 to capture:

So: turning CO₂ into fuel is chemically possible and commercially delightful. Physics will cooperate; it simply sends the hydrogen bill to whoever signs the offtake.

Same molecule, opposite economics. The question is not whether CO₂ can be turned into something valuable. It is how much energy must be put back in, what the resulting product competes against, and who pays the difference. Keep this picture in mind whenever a founder promises to turn waste CO₂ into something valuable.

Subsidy without a buyer is not a business

Hydrogen illustrates how quickly an attractive strategic theme can become an unattractive investment when demand is assumed rather than contracted. Green hydrogen remains capital-intensive and expensive relative to conventional alternatives, leaving many projects dependent on some combination of long-term offtake, regulation and subsidy.

The projects that have reached bankable structures show what matters. Saudi Arabia's $8.4bn NEOM green-ammonia project was built around a binding 30-year offtake agreement, allowing the project to be financed more like infrastructure than venture capital. By contrast, withdrawals from European Hydrogen Bank projects illustrated the opposite problem: subsidy can narrow the cost gap, but it cannot manufacture a creditworthy customer. Subsidy without offtake is not demand.

For an energy company, the distinction matters twice. Blue hydrogen draws directly on gas supply, processing, EPC and CO₂ storage capabilities; green hydrogen transfers much less of that operating advantage. And in either case, the scarce corporate capability may be less the molecule than the ability to originate long-term offtake and finance a complex project, skills the industry already uses in LNG.

The investment test is therefore not simply whether hydrogen will matter. It is who will buy it, at what premium, for how long, and what happens to the economics if policy support changes. That last question is not hypothetical: the same 2025 US tax law that increased the carbon credit for enhanced oil recovery brought the clean-hydrogen credit's eligibility deadline forward to 2027, potentially wiping out the economics of projects that had assumed a 2033 runway. One bill, opposite fates.

Renewcell: the technology worked, the market didn’t

Renewcell was the poster child of circular textiles: a Swedish pioneer that built the world’s first industrial-scale textile-to-textile plant and made recycled pulp used by H&M, Levi’s, Zara and Calvin Klein. One of its fibre-producer partners called it “the most advanced textile recycling innovator in the world”. It filed for bankruptcy in February 2024.

It did not fail on technology. It failed on demand conversion and economics: Some letters of intent never turned into orders. By late 2023 Renewcell itself warned that sales would not match the volumes implied by its offtake agreements, and roughly two-thirds of what it had sold was sitting with a sales agent awaiting onward sale. Mr. Chairman’s own verdict — “a testament to the lack of leadership and necessary pace of change in the fashion industry” — is a polite way of saying the brands didn’t buy what they had pledged to buy.

The lesson travels far beyond textiles: technical merit and customer interest are not bankable demand. Letters of intent and corporate pledges are not binding orders. A corporate venture investor should be especially wary of treating the parent’s commercial interest as proof of a market.

Cleantech 1.0 — what’s different, what’s the same

Peter Thiel’s verdict on the first cleantech boom, in Zero to One, was rather merciless “…So began the quest to cleanse the world. It didn’t work. Instead of a healthier planet, we got a massive cleantech bubble”. Investors poured more than $50 billion into thousands of cleantech companies between 2006 and 2012, and more than 40 solar manufacturers failed or went bankrupt in 2012 alone. Solyndra became the emblem: about $1bn of venture capital and more than $500m of government loans, gone as silicon-solar prices fell.

Much has changed. Today's investors are more specialised, capital structures can accommodate longer development periods, and regulation has created genuine compliance demand in markets that previously depended largely on voluntary adoption.

What is uncomfortably the same:

None of that means a venture has to work on today's economics. Betting on costs falling is part of venture investing. The danger is having to bet simultaneously on costs falling, carbon prices rising, subsidies surviving and customers paying a premium. The fewer things that have to go right at once, the stronger the investment case.

One failure mode deserves a final word, because it is where an operator’s edge is most real: execution and cost overrun. Cost overruns and schedule slippage on complex first-of-a-kind builds are a leading cause of infrastructure underperformance, and they are precisely the risk that decades of project-delivery experience exist to control. Not every risk in this field is exotic; some are the ordinary risks of building big things, and those the industry already knows how to manage.

The mandate test

The challenge of defining a corporate investment mandate ultimately comes down to four questions, each requiring a judgement about the parent, the opportunity and the capital deployed:

From opportunity to mandate: an illustration

The table applies this reasoning to the opportunities examined in this article. It illustrates a way of thinking, not an investment recommendation: the right answer depends on each company’s assets, ownership, objectives, cost of capital and risk appetite, and different companies may reasonably reach different conclusions.

Opportunity Where the corporate advantage may lie Potential investment instruments Potential CVC opportunities
CO₂ transport and storage Reservoirs, subsurface expertise, infrastructure and permits Direct ownership, JV, infrastructure or project finance Reservoir modelling, well-integrity, injection and monitoring technologies
Methane abatement Operating assets, captive demand and access to real-world testing sites Operational investment, procurement and commercial partnerships Sensing, satellite detection, measurement and analytics technologies
Firm power Gas supply, CO₂ storage, drilling expertise and offtake relationships Direct investment, project finance, JV or development partnership Next-generation geothermal, drilling, capture and flexibility technologies
Carbon markets Trading, origination, risk management and customer networks Trading operations and commercial contracts Verification, credit assessment and market-access technologies
Merchant renewables Potential advantage in development, trading and integrated power operations; limited advantage in passive ownership Development and farm-down, partnership Selective enabling technologies where a distinct corporate advantage exists
Frontier technologies Strategic insight and potential future capabilities, even where today's advantage is uncertain Selective minority investments, partnerships or staged commitments, sweat equity Long-term optionality in scalable technologies with credible financial potential

A mandate is as much a discipline of exclusion as a statement of ambition.

Closing word

The strongest corporate investment mandates do not begin by asking which themes are fashionable. They begin with a colder question: where does structural change collide with something the parent genuinely does better than the capital competing against it?

For an oil and gas operator, the answer is not “energy transition” in the abstract. It is concentrated in a handful of places where the rock, the pipe, the molecule, the permit, the operating footprint or the customer relationship actually changes the economics. Elsewhere, the disciplined answer may be partner, contract, observe or stay out. Back the crown jewels, not the fashion.

Yet some of the best investment returns come from technologies that initially look remote from the incumbent's core, and too strict a right-to-win test could screen out the very optionality corporate venture exists to create. So the discipline is not to ignore the frontier — only to size it honestly.

I was once told that surfing is a paddling sport. It stayed with me. Nobody films the paddling, yet it takes up most of the session, while the ride lasts seconds. A handful of waves can make the whole day. For a business accustomed to billion-dollar projects, exploring the frontier can feel like exactly that kind of unglamorous, tiring paddling. But a wave cannot be ridden from the beach. The ones who catch it are already at sea. So keep paddling — and do enjoy the views.

I have been approached multiple times by organisations seeking support in designing, reviewing and challenging their CVC mandates. Those conversations shaped the questions this article asks; its analysis draws only on public sources.

The recurring challenge is rarely finding attractive sectors. It is deciding which opportunities genuinely belong in a particular parent’s venture mandate, what the parent can contribute, and where independent judgement should say no.

Through The Fifth Chair, I advise corporate venture and investment teams on mandate design, investment thesis development, portfolio review and independent challenge, including when venture capital is not the right instrument.

Discuss your mandate with The Fifth Chair →

Author’s Note

All information in this article is drawn from publicly available sources. It does not use or rely on any confidential or non-public information. The views expressed are my own and do not represent those of any organisation with which I am or have been associated through advisory work, board representation, partnership, employment or any other contractual relationship. Companies are named for illustration only; no affiliation or endorsement is implied. The article is for general discussion and does not constitute investment, financial or legal advice. It was developed with the help of AI tools for research, drafting and editing. The argument, the judgement calls, errors and sarcasm, if any, are entirely my own.

Sources

Lilia Chechel
Lilia Chechel
Founder and Managing Partner

Independent investment challenge for VC, CVC and private capital. Get in touch.

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