This Professional analysis is a direct follow-up to my recent free article, “The Cheapest Battery Is Not the Cheapest Storage.”

That article argued that, as battery prices fall, $/kWh is becoming an increasingly incomplete measure of storage economics. But that raises the next question: if price alone is not enough, what should we be looking at instead?

This analysis takes the next step. The BESS Risk Migration Map 2027 shows where the major risks originate, who can control them, how contracts attempt to transfer them, and who ultimately pays when those protections fail.

The free article challenged the benchmark. This Professional analysis provides the framework for making better BESS decisions.

There is a paradox emerging in battery storage.

The technology at the heart of a BESS project is becoming dramatically cheaper, while the economics surrounding it are becoming more complex.

A €70/kWh battery can still be more expensive than a €90/kWh battery

Consider two otherwise comparable projects.

Project A acquires its BESS at €70/kWh. Project B pays €90/kWh. On a conventional procurement comparison, Project A has clearly secured the better deal.

Now suppose Project B has stronger degradation protection, pre-agreed augmentation economics, an OEM with a stronger balance sheet, clearer performance guarantees and an EPC structure that leaves substantially less integration risk with the project company.

Its operating strategy also sits comfortably inside the warranty envelope, while its contracted revenues are sufficiently predictable to support attractive project financing.

The €20/kWh difference has not disappeared. But it does not necessarily determine which project is cheaper.

If lenders perceive Project B as less risky, it may support higher leverage, a longer tenor, smaller reserve requirements or more favourable financing terms. Greater certainty around augmentation can reduce contingency requirements, while genuinely enforceable warranties backed by creditworthy counterparties can reduce the downside retained by the project company.

This creates an important feedback loop:

Risk allocation → bankability → cost of capital → lifetime storage cost.

That is why bankability should not be evaluated after a BESS has been selected.

Bankability is itself part of BESS economics. And it changes what “cheap” means.

The BESS Risk Migration Map

Rather than asking simply who is responsible for each risk, the Risk Migration Map follows four questions:

1. Where does the risk originate?

2. Who can control it?

3. Where is it contractually allocated?

4. Who ultimately bears the economic loss?

Source: Global Energy Markets Intelligence analysis. Actual allocation varies materially by project and contractual structure.

The map reveals something a conventional risk-allocation table can easily miss:

The party named in the contract is not necessarily the party carrying the economic risk. Contractual allocation and economic exposure are not the same thing.

Consider degradation. A performance warranty may appear to transfer degradation risk to the OEM. On paper, the owner is protected.

But suppose the battery is dispatched outside the permitted cycling envelope. The warranty may no longer respond.

The risk originated physically in the battery, was influenced by the commercial decision to dispatch it, appeared to have been transferred contractually to the OEM — and ultimately returned as a financial loss to the owner.

That is risk migration. And it occurs repeatedly in BESS.

Read more

Saudi Arabia’s latest battery storage procurement has triggered a familiar debate: what is the correct $/kWh?

Perhaps that is the wrong question.

The Kingdom’s latest program covers 2 GW and 8 GWh across four projects under a build-own-operate structure. The headline numbers immediately invite comparison with previous Saudi tenders and other large-scale BESS projects around the world.

But making that comparison quickly becomes complicated.

Should we use nominal or usable capacity? What exactly is included in project cost? How much capacity is installed to compensate for degradation? Is grid connection included? Financing? Development costs? And how do we compare a developer-financed BOO project with an owner-procured battery where some of those costs and risks sit elsewhere?

It is tempting to solve the problem by finding the correct numerator and denominator.

But the disagreement itself points to something more fundamental.

$/kWh is useful for comparing batteries. It is much less useful for comparing the economics of storage.

And as battery markets mature, that distinction will matter increasingly.

The $/kWh trap

There is nothing inherently wrong with $/kWh.

It gives us a simple way to track equipment costs, compare technology trends and understand just how dramatically battery prices have fallen.

The problem starts when we treat it as a measure of project economics.

Consider the denominator.

A reported kWh could refer to installed nominal capacity, beginning-of-life usable capacity, contracted capacity at the meter, or something else entirely.

Those distinctions matter because batteries are not static assets.

They degrade. Auxiliary systems consume energy. Charging and discharging create losses. Temperature and cycling patterns affect performance.

Developers therefore have to decide how they will maintain the storage capability required by the project.

Some install additional capacity from the beginning. Others plan augmentation later. Some may accept declining capacity because their revenue model does not require constant output throughout the project life.

So perhaps the most useful question is not:

Nominal or usable? It is: Usable when?

A battery required to deliver a specified amount of energy on day one is economically different from one required to maintain that same capability in year fifteen.

Yet both may appear in a database as a 500 MW / 2,000 MWh BESS.

The headline capacity is the same. The storage service is not.The cheapest battery may not deliver the cheapest storage

The numerator creates the same illusion of simplicity.

One BESS cost figure might include cells, modules, containers and power conversion equipment. Another includes full EPC. Another includes the substation and interconnection. Land, development, insurance and financing may sit inside or outside the number.

But there is an even more important difference: risk.

Consider two projects.

Under an owner-procured model, a utility might purchase the BESS and EPC while retaining responsibility for land, grid connection, financing and some long-term performance risks.

Under a BOO (Build, Own, Operate) model, the developer may have to develop, finance, construct and operate the asset while meeting contractual performance obligations for fifteen years.

Those are not simply two different ways of buying the same battery. They are different ways of allocating cost and risk.

And risk has a price. Someone carries degradation risk. Someone pays if augmentation is required earlier than expected. Someone carries availability, EPC interface and replacement risk.

Warranties may transfer part of that exposure to suppliers. Financing structures move other risks between investors, lenders, developers and offtakers.

Once those factors are included, the battery with the lowest upfront $/kWh does not necessarily produce the lowest-cost storage.

Imagine two competing projects

Suppose two developers compete for the same fifteen-year storage contract.

Developer A selects the lowest-cost battery system available.

Developer B pays more upfront but obtains better efficiency, slower expected degradation, stronger warranties and lower augmentation requirements.

On a simple installed $/kWh comparison, Developer A wins.

Now extend the analysis over fifteen years.

Developer A may need more augmentation. Lower efficiency means more energy must be purchased to provide the same discharged MWh. Weaker warranties may leave more performance risk with the project company.

Now add financing.

Developer B’s technology has a longer operating history and is better understood by lenders and insurers. It may therefore support more debt, lower financing margins and smaller contingency reserves.

Which project is cheaper?

At this point, the original battery $/kWh tells us surprisingly little.

The cheapest battery and the cheapest storage solution can be two very different things.

This matters for the next generation of battery technologies

The distinction will become even more important as new chemistries challenge LFP. Sodium-ion, for example, may eventually achieve very attractive cell economics. But beating LFP on cell cost will not be enough.

A new technology also needs bankable degradation curves, credible warranties, insurer confidence, operating history and financing terms that preserve its apparent cost advantage at project level.

A technology that is 15% cheaper at cell level but significantly more expensive to finance, insure or augment may not be cheaper at all once incorporated into a long-term storage project.

The real competition is therefore not simply:

chemistry versus chemistry on $/kWh.

It is:

one bankable lifetime storage solution versus another.

LCOS gets us closer, but not all the way

Levelised Cost of Storage is an obvious alternative.

LCOS gets us closer to the economic question because it considers costs over the life of the asset and relates those costs to energy delivered rather than simply capacity installed.

But replacing $/kWh with LCOS does not automatically solve the benchmarking problem.

Change the cycling assumptions and the result changes. Change round-trip efficiency, degradation, augmentation strategy, charging cost, asset life or discount rate and it changes again.

Two analysts can therefore calculate perfectly valid LCOS figures for similar batteries while still measuring different operating propositions.

The problem is not simply that we are using the wrong metric.

We may be benchmarking the wrong thing.

Benchmark the service, not the battery

The solution is to reverse the analysis.

Define the storage service first. Calculate the cost second.

Suppose an offtaker requires a battery to provide:

• a specified MW output;

• for four hours;

• at a defined grid connection point;

• with an agreed availability;

• at a defined minimum efficiency;

• under an agreed cycling regime;

• while maintaining the contracted capability for fifteen years.

Now there is something meaningful to benchmark. One developer might meet that obligation by oversizing significantly at the beginning. Another might build closer to the initial requirement and augment later. One may choose more expensive cells with slower degradation. Another may assume future replacement batteries will be considerably cheaper. A third may pay more for stronger warranties to transfer part of the long-term performance risk back to the manufacturer.

Those are different technical, contractual and financial strategies.

But crucially, they are strategies for delivering the same defined storage service.

Only then does comparing their cost become genuinely useful.

What Saudi Arabia really tells us

This is where the latest Saudi projects become more interesting than their headline $/kWh suggests.

The important development is not simply another datapoint showing that battery costs are falling.

It is the increasing use of procurement structures in which developers must optimize an entire long-term storage proposition.

Technology matters. But so do degradation, augmentation, efficiency, EPC execution, warranties, financing and risk allocation.

The winning project is therefore not necessarily the one that purchases the cheapest cells or reports the lowest installed $/kWh. It is the one that can combine those elements to deliver the required storage service reliably at the lowest risk-adjusted lifetime cost.

That is a fundamentally different competition.

Batteries are becoming infrastructure

For years, the battery industry’s central question was:

Can battery costs fall far enough to enable storage deployment at scale?

Increasingly, the answer appears to be yes. But that success creates a more sophisticated question.

As storage moves from relatively simple equipment procurement towards long-term infrastructure, the economics increasingly depend on much more than the price of the equipment.

Technology risk becomes financing risk. Degradation becomes contractual risk. Efficiency becomes operating cost. Augmentation becomes capital allocation. Warranty quality affects bankability. And procurement structure determines where many of those risks ultimately sit.

That is why increasingly sophisticated storage markets will need increasingly sophisticated benchmarks.

$/kWh will remain useful. It should.

Equipment costs matter, and simple benchmarks help us understand technology trends.

But a battery price is not the same thing as the cost of storage.

And perhaps that is the real lesson from the debate around the latest Saudi projects.

When experienced market participants can look at the same procurement and reach different $/kWh interpretations depending on scope, capacity definition and financing structure, we should not necessarily spend more time searching for the perfect headline number.

We should ask a better question.

Not: What did the batteries cost per kWh? But: What storage service is being promised, for how long, with which risks included and what does it cost to deliver it?

That number is harder to put in a headline.

It is also the benchmark that actually matters.

Global Energy Markets Intelligence examines the market structures, contracts and risks reshaping global energy markets.

Free subscribers receive structural market analysis. Professional subscribers receive deeper contract and risk analysis, market frameworks and decision-oriented intelligence.

Free explains the market. Professional helps you act on it.

We are currently spending trillions of dollars on extending our electricity networks in order to promote electrification and the use of renewable energy, but a changing climate may affect the amount of that infrastructure that is actually available when the power system requires it most.

The energy transition is based on one simple physical requirement, namely that a great deal more grid capacity is needed.

Wind and solar energy need to be linked, usually in areas that are far from the centres where electricity is used. The introduction of electric vehicles, heat pumps, the electrification of industry and data centres is causing new demands on the power supply. There will be an increasing requirement for electricity to be transmitted between different regions as renewable energy production varies with the weather. In many power markets the grid is already becoming a major limitation on further decarbonization.

The reply involves a massive investment in transmission lines, transformers and substations; the main issue being speed—how quickly can the necessary permits be obtained, the equipment manufactured and the infrastructure built?

There is, however, another question concealed within the investment boom.

What if the physical capacity of the grid becomes more dependent on the weather?

Take for example an overhead transmission line. We usually regard its capacity as being a fixed value—that is, the line can carry a particular quantity of electricity. In fact, however, this capacity is in part determined by the conditions surrounding it.

The conductor is heated. The ambient temperature, wind, and solar radiation affect how well the heat can be dissipated. When a conductor gets hotter, it expands and sags, and eventually reaches a limit as to how much current it can carry safely.

This leads to an uncomfortable situation when the heat is extreme. Electricity demand can increase sharply as the need for cooling rises, especially in economies that are becoming more electrified. At the same time, higher ambient temperatures can reduce the amount of current that some overhead lines are able to carry safely.

The system therefore may require more transmission capacity at the very time when sections of the network have less available capacity.

This can take place without anything going wrong. It is not necessary for any pylon to collapse or for any cable to break. The line can still remain in operation.

The only thing that has changed is the extent of what the system can be asked to do.

And once usable grid capacity becomes weather-dependent, the consequences don’t stay in the engineering department. They begin to show up in congestion, curtailment, scarcity — and ultimately in the prices we are trying to forecast for the power market of 2040.

When the Grid Needs more Capacity and has less of it

The importance of this distinction lies in the fact that climate resilience is generally linked with physical damage. For example, we consider storms causing networks to be knocked down, wildfires posing a threat to transmission corridors or floods getting into substations.

Although those risks are real, they may draw attention away from a less dramatic type of climate risk. It is not necessary for infrastructure to fail in order for it to become economically important; changes in physical conditions can affect its usable capacity.

Now picture several days of intense heat in a future power system.

The need for cooling is causing consumption to rise. Although solar power may be plentiful in the afternoon, demand stays high as solar output decreases in the evening. As a result, the system is becoming more dependent on the transfer of electricity between regions, moving it from areas with an excess of renewable or dispatchable generation to those where demand is highest.

When the ability to transmit electricity is restricted at the same time, the effects start to spread across the market. The cheap power on one side of the bottleneck will not be able to get all the way to consumers on the other side. More costly power might then have to be generated locally. Renewable power generated in other areas may have to be curtailed. The costs associated with redispatch go up and electricity prices in different regions may become divergent. If the system is already under pressure, the constraint can lead to a situation of scarcity.

An engineering limitation has now turned into a market limitation.

And this relationship matters more as the energy transition progresses because transmission is becoming more important to the economics of electricity.

Wind and solar are tied to geography. The best renewable resources are not necessarily located close to the largest demand centers, and their production varies with weather. Transmission allows one region’s surplus to compensate for another region’s shortage. It allows cheap renewable generation to reach consumers and reduces the economic consequences of local variations in supply.

At the same time, electrification is moving more of the economy onto that network. Transport that previously depended on oil becomes an electrical load. Heating that previously relied on gas becomes increasingly dependent on electricity. Industry and data centers add further demand.

We are therefore making the economy more dependent on grid capacity while potentially making that capacity more sensitive to the physical conditions in which it operates.

Today’s Investment, 2070’s Weather

There is another reason why this should be given attention: the infrastructure currently under construction will be in use for a very long time.

A transmission line that was installed as part of the present-day grid expansion might still be in operation in the 2060s or 2070s; transformers, substations and other major network assets can likewise continue to be in service for many decades.

The decisions regarding their design are being made now, but the climate they undergo does not stay at today’s levels.

It is here that the problem becomes more subtle.

The electricity infrastructure has always taken weather into account. When specifying assets, engineers take into consideration temperature ranges, wind loads, flood levels and other environmental conditions. The problem is not that the industry has forgotten about climate or weather.

The problem lies in the probability of those conditions occurring over the entire lifetime of an asset.

A temperature which has in the past been regarded as exceptional could eventually cease to be so. The level of risk associated with flood protection based on historical conditions could be different several decades hence. The exposure to wildfire along a transmission corridor may also change.

There is therefore a special problem concerning the timing of infrastructure decisions. The decision to make an investment is taken only once, even though the physical environment keeps on changing afterwards.

After a transmission corridor has been constructed, it is expensive to alter its basic design. When a substation has been built, it is rare to move it because the flood risk has changed. And once thousands of transformers have been put in place throughout a distribution network, it becomes economically significant to replace them before the originally planned time.

The assumptions we make today can stay embedded in copper, steel and concrete for half a century.

When an Engineering Constraint Becomes a Market Constraint

This likewise alters the economics of resilience.

Suppose that today a more resilient grid design requires a greater cost but has a higher level of usable capacity when faced with more severe future conditions. The extra capital outlay is at once apparent.

The economic benefits are much more difficult to observe.

The advantages could include congestion which won’t take place in 2045, redispatch which will not be liable to be paid in 2052, renewable generation which won’t have to be curtailed, or an extreme regional price spread that never does materialize.

We know the cost of building resilience. The value of resilience is usually seen in the fact that a problem never occurred.

Because of that asymmetry, resilience is easily underestimated, especially when investment decisions are evaluated in relation to historical operating conditions.

The most inexpensive grid asset to construct at the present time need not be the cheapest one after forty or fifty years; but in order to show this at the stage of making an investment it is necessary to make assumptions regarding the physical conditions many decades ahead.

That is not merely an engineering issue any longer since it has an impact on generators, traders, retailers, and investors because the network decides which generation can reach which consumers and thus where electricity has value.

The installed transmission capacity and the economically usable transmission capacity are not always identical.

That difference is well worth paying more attention to when analysing the power market.

Is This Risk in Our Power Market Models?

Let’s look at a forecast for the electricity market over the long term for the year 2040.

The model includes extremely detailed assumptions regarding future generation and knows the amount of offshore wind, solar power, gas generation and battery capacity that will be available; it also models fuel and carbon prices, electricity demand, and possibly the individual transmission links between different areas.

The amount of power that can be transmitted can have a huge effect on the outcome; if you alter the capacity for transmitting electricity between two areas then the model will show different levels of curtailment, different capture prices for the renewable power generators, different battery revenues and different regional power prices.

What happens to the supposed transmission capacity in adverse weather conditions?

If the model raises electricity demand during a future heatwave without changing the capacity of the network, it only takes into account one aspect of the physical relationship and may fail to consider the other.

Demand is now affected by the weather, and so is generation. However, the grid linking the two can still be shown as a fixed number.

It is especially important during the relatively short period of time when the electricity system is experiencing the highest level of stress. In those hours scarcity revenues can be disproportionately affected, battery economics can be influenced, the value of flexible generation can be determined and the benefits of interconnection can be ascertained.

The question is therefore not merely if climate change reduces the average transmission capacity. It might not.

A more interesting question is this: does the weather change when certain amounts of grid capacity are available, and can a reduction in capacity occur during the hours when that capacity is worth the most economically.

That is a far more serious issue for power markets; it also indicates a straightforward test for long-term forecasts.

When you come across a 2040 or 2050 electricity-market model next time, check the assumptions regarding transmission between regions and consider whether that capacity is weather-sensitive.

Does the network’s capacity change when temperatures are extreme? Does the response of demand to such temperatures take place at the same time? And what effect does this have on congestion, curtailment and regional prices when both of these things occur together?

They are no ordinary technical details since they have an effect on the economics of the assets upon which we are spending huge amounts of capital.

It is certain that the energy transition will need more grid infrastructure, and there is indeed a strong urgency to accelerate its construction. However, the present wave of investment is leading to the creation of assets which are expected to last for many decades; we should therefore be cautious about evaluating the future grid solely in terms of kilometers of line or gigawatts of installed transfer capacity.

The most important figure is often the amount of those gigawatts that are actually available during the hours when the future power system places the highest value on them.

The line between installed capacity and usable capacity is the point at which climate resilience ceases to be just an engineering concern and becomes a power-market issue.

This points to a more general challenge for the next generation of power-market analysis.

We put in a great deal of effort into modelling the future composition of generation, future demand, future commodity prices and future storage capacity. It is possible that we also need to improve our ability to model the physical conditions under which the infrastructure linking all of these elements will in fact operate.

The energy transition doesn’t just require a larger grid.

It needs grid capacity that is still there when we need it most.

Picture two firms that are based outside the European Union.

The goods that they produce are broadly comparable; their products have similar levels of embedded emissions. Both companies operate in countries that have a carbon pricing mechanism, and in each case the carbon cost has already been taken into account before the products leave the factory.

They send those products to customers in Europe.

On first sight, you could probably expect their views on CBAM to be the same. They may not be.

There is one producer who keeps detailed records indicating the precise carbon price that was paid, the particular installation it relates to, the emissions it covers, the free allowances that were obtained, and whether any rebates or compensation lowered the actual cost.

The other one knows that it has paid a carbon tax or has bought emission allowances; the finance department possesses the invoices, the sustainability team has the emissions data, the tax department is aware of the rebates, and the plant has its operational records.

Yet there has never been any reason for anyone to link all those pieces together. With the introduction of the CBAM, that difference could have a financial value.

Here one can see that a relatively short provision of the CBAM Regulation—namely Article 9—turns out to be much more interesting than it at first seems.

The carbon price you paid is not necessarily the carbon price CBAM sees

The reason behind Article 9 is reasonable.

When a carbon price has already been effectively applied in the country in which the goods were produced, an authorized CBAM declarant may claim a reduction in the number of CBAM certificates which he or she is ultimately required to surrender.

That is to say, CBAM has a mechanism which is meant for identifying the carbon costs that have already been incurred outside of the EU.

But notice the wording.

The Regulation does not merely mention a country having a carbon price. It means a carbon price is effectively being paid. The two words carry a great deal of weight.

Imagine a steel producer functioning within an emissions trading system in which the allowances are traded at a rate of €40 per ton of CO₂.The commercial team could plausibly argue that we are already subjected to a carbon price of €40.

Yet imagine that the installation obtains a large fraction of its allowances without having to pay for them. What carbon price is in effect?

Now look at an aluminum smelter which is liable to a carbon tax of €30 per ton but which enjoys a reduced industrial rate or a refund scheme.

Isn’t the effective carbon price actually €30?

Consider the case of a company which produces fertilizer and is subject to a levy relating to carbon but also receives payment which offsets part of that liability.

The headline figure only tells half the story.

Article 9 stipulates that rebates or other types of compensation which reduce the carbon price must be taken into account; the European Commission’s draft implementing rules of May 2026 provide a much clearer picture of the direction in which things are heading by dealing with issues such as free allowances, reduced tax or levy rates, exemptions, refunds and various compensation mechanisms.

What results is a significant change in one’s point of view. For exporters, the relevant question is no longer:

What is the figure for carbon in our country?

It becomes:

What carbon price did this installation in fact pay for the emissions contained in the goods we are selling in Europe — and can this be demonstrated?

That is a considerably more difficult question.

The problem may be sitting between departments

It is here that many companies will realize that Article 9 is not mainly about carbon pricing. This is a problem relating to data and organization.

The sustainability team are aware of the emissions, the environmental trading team know the number of allowances that were surrendered, Finance know the amount that was paid, Tax know which refunds or reduced rates were applied and Operations know where the product was manufactured, while Sales know which products were sent to customers in Europe.

The EU importer also needs some information which may involve elements from all of them.

Each department could have records in perfect good condition. The problem is that those records were created for different purposes and may never have been designed to tell one coherent CBAM story.

This is important since Article 9 is not based on a country’s carbon-policy ambitions; instead it is based on evidence.

The authorized CBAM declarant must prove that the relevant embedded emissions were covered by a carbon price which was in effect paid in the country of origin, and the amended CBAM Regulation also sets out the certification requirements for the documentation used to support claims regarding carbon prices.

The draft implementing rules published by the Commission in May 2026 include a great deal more detail concerning proof of payment, attribution, rebates and compensation, currency conversion and certification.

A completely legitimate carbon cost that arises outside of Europe can still give rise to a practical challenge for the CBAM if the evidence cannot go with the product.

Think about what that means commercially

Let us go back to the two manufacturers. They have comparable emissions and have both paid for their carbon. However, Manufacturer A has established a chain of evidence which links the installation to the emissions, to the carbon-pricing mechanism, to the payments, to the free allocation, to the rebates and to the relevant reporting period. It is able to give its European customer information in a format that is suitable for the CBAM process.

Manufacturer B would not find it easy to carry out that action. Although the information is available it is scattered among different systems and departments.

The reason behind the difference is not necessarily their environmental performance; it is rather their readiness for CBAM. That in the end may result in a commercial difference.

European procurement teams are getting used to asking suppliers questions regarding embedded emissions. The kind of discussions in the future might go a step further:

What carbon price has already in effect been paid for those emissions?

And then the question that matters:

Can you demonstrate it?

At that moment, Article 9 ceases to be a technical provision in an EU regulation and begins to become involved in the economics of the suppliers.

There is another complication hiding in the calculation

Exporters also need to understand the connection between actual emissions data and default values.

The revised CBAM framework includes annual default carbon prices as well as claims relating to the actual and effective carbon prices paid.

When default values are used to determine the embedded emissions, the Article 9 reduction is linked to the appropriate annual default carbon price and not merely permitting the importer to substitute a specific actual carbon price claim made by the exporter.

It follows that judgments regarding emissions data and evidence on carbon prices must be made independently. A company cannot reasonably have one team responsible for deciding how it will calculate its embedded emissions while a different team at the same time considers the carbon-price deductions.

The two issues should be included in the same CBAM strategy.

One of the most important aspects of CBAM from a commercial point of view is that a requirement which at first sight appears to be concerned only with environmental reporting eventually extends itself to areas such as finance, tax, procurement, trading, sales, and contract management.

The cheapest carbon-price deduction may be the one you cannot prove

Mid-sized exporters are in a special situation with regard to risk.

A multinational industrial group has good reason to have dedicated CBAM systems, to employ specialist advisers, to carry out verification processes and to establish internal carbon-accounting infrastructure.

The case is different for a smaller producer.

Suppose that the domestic carbon price should, in principle, lead to a reduction in the amount of CBAM exposure linked to your exports.

One has to gather information from a number of departments, match the figures in the emission records with those in the financial records, identify the rebates and compensation, and get the required certification.

At some point, management will ask a very rational question:

What, when compared with the expense of proving it, is the value of this deduction?

It is in this area that Article 9 could have an unexpected competitive effect since the carbon price might be the same for the two companies but their ability to convert that carbon price into a CBAM reduction may not be.

Role of Governements

The ability to comply begins to have a monetary value. And this is not just a problem for exporters. There is also a strategic question for governments.

Emissions trading systems, carbon taxes, levies and other carbon-pricing mechanisms are being developed by countries all over the world.

Up to quite recently, those systems had mainly been designed with domestic aims in mind, such as reducing emissions, increasing revenue, encouraging investment or aiding the country’s transition strategy.

The introduction of CBAM involves yet another aspect of design.

How easily can the cost that domestic producers are bearing be shown to an importer in the EU and be accepted under Article 9?

It does not imply that countries should copy the EU ETS; in fact, the CBAM Regulation defines what constitutes a carbon price in a wider sense and this includes taxes, levies and fees as well as emissions trading systems.

Governments which have large exports to Europe are now in a position to consider the need for their carbon pricing and reporting systems to be compatible with CBAM.

An economic carbon price that is hard to prove internationally is less valuable to an exporter than one which can move along the supply chain with a clear record of evidence.

That is an interesting consequence of the CBAM which extends well beyond the borders of Europe.

2026 is the year to build the evidence, not 2027

There’s also a timing trap in this situation.

The CBAM system came into effect on 1 January 2026, but companies will not hand over their CBAM certificates in relation to imports made in 2026 during the year 2026.

Authorized CBAM declarants will start to buy certificates in 2027, the first CBAM declaration together with the corresponding surrender for imports in 2026 being ready by 30 September 2027.

For 2026 the certificate pricing is determined by the quarterly averages of the EU ETS auction prices and from 2027 the method of calculation changes to a weekly basis.

It might lead people to the mistaken belief that there is still a lot of time available. In fact, there isn’t.

The transactions which result in the future liability are taking place at the present time. The emissions data which is being generated right now is important. The carbon costs which are being incurred at the current time are significant. The free allocation, the rebates and the compensation that are in effect now are relevant. Moreover, the quality of the records created at this time could affect how easily companies are able to support their case later on.

Working out all that in 2027 from a retrospective point of view will be much more difficult than setting up the evidence gathering process at the time the transactions are happening.

Then I should ask an exporter today, what?

I shouldn’t begin by asking: Are you CBAM compliant? The question is so wide that it has no practical use. I would sit down with the people responsible for sustainability, finance, tax, operations and commercial relationships and ask something more specific:

Take me through the route that one ton of your product follows from the time it is installed to the European customer receiving it. Go on and then follow the carbon as it does so.

Where did it come from? What were the embedded emissions? Which carbon-pricing scheme was in effect? How much was actually paid? Were allowances given free of charge? Was there a lowered tax rate? Was any refund or compensation offered? Where is the evidence? Can the financial records be matched with the emissions records? And can the resulting information be provided to the EU customer in a format that fulfils its CBAM obligations?

So long as those questions can be clearly answered, the company will be in a strong position.

Should it take five departments, three spreadsheets, and a number of weeks’ worth of emails to respond to them, then Article 9 has already spotted a flaw in the company’s CBAM process.

The real lesson of Article 9

Article 9 is easily underestimated since it appears to be a kind of deduction mechanism.

I believe this reveals a great deal about the future direction of CBAM.

The initial stage of CBAM was mainly concerned with measuring carbon; the current phase, however, is more focused on attaching a financial value to it and on being able to justify the calculations.

For non-EU exporters that changes the situation. It is still essential to know your embedded emissions, but increasingly it is also necessary to understand the carbon economics associated with them. Since the question that European customers might ultimately be concerned about is not simply:

How much carbon is in this product? It may also be: How much has already been paid for that carbon — and can you prove it?

That is where environmental data becomes financial data. It is where compliance starts influencing commercial strategy.

And it is why Article 9 deserves much more attention from exporters than its relatively small place in the CBAM Regulation might suggest.

Paying a carbon price is one thing. Getting CBAM recognition for it is another.

For companies exporting into Europe, understanding the difference is becoming part of the cost of doing business.

If your organization is working through these questions, I support exporters, importers and commercial teams with practical CBAM advisory and tailored training. Translating the regulatory requirements into the data, processes and commercial decisions that matter in practice.

Regulatory note: This analysis reflects Regulation (EU) 2023/956 as amended and European Commission materials available in August 2026. References to the Commission’s May 2026 detailed rules on carbon prices paid in third countries refer to the draft implementing regulation published for stakeholder feedback and should not be read as final requirements unless and until the final act is adopted. This article provides general regulatory and market analysis and is not legal advice.

Any long-term energy contract is a strategic choice which will affect the organization’s commercial standing for years—sometimes even decades—into the future. If the agreement in question is a Power Purchase Agreement (PPA), an LNG Sales and Purchase Agreement (SPA), a long-term gas supply contract, or a renewable energy offtake, then the terms agreed upon today will still have an impact on profitability, operational flexibility, financing, and risk exposure long after the negotiation team has left.

Yet many negotiations begin with the wrong mindset.

Commercial teams frequently take hours and hours to improve their price models, to check over the language in the contracts, and to practice their negotiation strategies. Yet very little attention is given to the preparation that decides whether or not those strategies will actually be successful.

The best negotiators seldom manage to do better than anyone else simply because they are more determined, more persuasive, or better at bargaining; it is because they prepare in a different way that they achieve better results.

The following article looks at the reasons why the most successful long-term energy negotiations start well in advance of the first meeting, why price is almost never the real issue, how having internal agreement gives you negotiating power, why the alternatives you have determine your leverage, and the way in which careful contract design can result in agreements that still have value long after market conditions have changed.

The Biggest Mistake Is Thinking the Negotiation Starts in the Meeting Room

When someone thinks about negotiating a long-term energy contract, they usually picture two business teams opposite each other at a conference table, discussing the price until one of the parties eventually yields.

Reality is generally much less dramatic.

The major decisions are taken weeks or even months beforehand, before anyone goes into the negotiation room.

When the first draft of a contract comes on the table, experienced negotiators will already know precisely what they want to achieve, the points at which they are willing to make concessions and the ones at which they simply cannot.

The actual negotiation is merely the last phase in a far longer period of preparation.

This is exactly the point at which many organizations make the mistake.

Commercial teams take weeks to build financial models, to analyse forward curves, to go over legal clauses and to prepare their presentations. Yet surprisingly little time is devoted to asking a question that at first sight seems simple:

What would a successful agreement actually look like for us?

It seems obvious but in reality it usually isn’t..

The Biggest Mistake Is Thinking You’re Negotiating Price

It is a common practice for energy markets to boil down any commercial conversation down to one figure. So, what strike price should the PPA have? What fixed gas price is acceptable? And how much discount should be given against the market index?

These are important business questions.

Yet the questions they raise are seldom the ones that decide whether a contract will create value over the next ten, fifteen or even twenty years.

Long-term energy agreements involve more than just one issue.

They are carefully balanced systems from a commercial point of view since the length of the contract, the flexibility regarding volume, the method of pricing, the delivery obligations, indexation, the requirements as to collateral, the operational commitments, the clauses relating to changes in law and the rights to terminate all affect one another.

Changing one variable almost always changes the value of several others. The best negotiators recognize this from the outset.

Rather than inquiring about how they might negotiate a better price, they consider where additional value can be generated. This small change transforms the whole line of discussion.

Consider two counterparties negotiating a renewable PPA.

The developer’s top concern might well be to secure a contract that will last long enough to meet the requirements of the project lenders. The industrial buyer, on the other hand, is likely more focused on having annual flexibility to cope with varying production volumes. Neither of these objectives is more important than the other; they are just different.

Those differences create opportunities.

It is possible to have commercial trade-offs when the various parties place different values on the different parts of the agreement and neither side then feels as though it has lost.

The focus of the negotiations shifts from dividing value to creating it.

Before Negotiating with the Other Side, Negotiate with Your Own Organization

🔒 Continue Reading

If you’ve made it this far, you’ve already seen why most long-term energy negotiations fail before the first commercial meeting ever takes place.

For paid subscribers, the remainder of this article goes from preparation to execution. You’ll learn how experienced negotiators build leverage before negotiations begin, structure contracts that remain resilient during volatile markets, and uncover opportunities to create value that most commercial teams never even discuss.

Founding Subscriber Offer

Since this newsletter is new, I’d like to reward my earliest supporters.

The first 50 Founding Subscribers will also receive one personal Negotiation Strategy Review.

Whether you’re preparing for a PPA, negotiating an LNG SPA, reviewing a long-term gas supply agreement, or facing a difficult commercial negotiation, you can send me your challenge and I’ll provide practical feedback and recommendations.

This bonus is only available to my first 50 paid subscribers.

👉 Become a Founding Subscriber

In the remainder of this article you’ll discover:

• Why your strongest negotiating position often comes from the deal you’re prepared not to sign.

• How to stop arguing about forecasts and start designing contracts that survive uncertainty.

• Why presenting one proposal is often a mistake and what sophisticated negotiators do instead.

• The mindset shift that turns difficult negotiations into collaborative commercial problem-solving.

• The one measure that determines whether a contract was truly successful fifteen years after it was signed.

Read more

For much of the past two decades, the energy transition has been framed as a technological race.

Could solar power become cheaper than coal? Could offshore wind achieve industrial scale? Could batteries balance increasingly volatile electricity systems? Could hydrogen decarbonize heavy industry? Could biomethane replace fossil natural gas?

These questions have shaped government policy, corporate strategy and billions of dollars of investment. They have also reinforced a widely held assumption: once the technology becomes commercially viable, investment will naturally follow and infrastructure will be built.

That assumption is becoming increasingly difficult to defend.

The next phase of the energy transition is likely to be determined less by breakthroughs in engineering than by the ability of developers, investors and energy consumers to reach commercial agreements.

The central question is no longer whether a wind farm, biomethane plant or hydrogen electrolyser can operate. In most cases, the technology already exists. The more important question is whether someone is willing to commit to buying its output for fifteen or twenty years.

That distinction may appear subtle, but it changes almost everything.

Energy infrastructure requires enormous upfront investment while generating returns over several decades. Investors therefore care less about technical potential than about future revenue. A project can be technically sophisticated, environmentally desirable and politically supported, yet still fail to attract financing if its future cash flows remain uncertain.

Banks do not finance ambition. Infrastructure funds do not invest because governments publish ambitious targets. Capital flows towards predictable revenue. And predictable revenue is created through contracts.

The Energy Transition Has Entered a New Phase

The first phase of the energy transition was primarily about reducing technology costs.

Governments created early markets through feed-in tariffs, tax incentives, renewable energy auctions and direct subsidies. Manufacturers expanded production, developers accumulated experience and supply chains matured. As deployment accelerated, the cost of technologies such as solar photovoltaics and wind turbines fell dramatically.

The second phase focused on scale.

Renewable electricity became an increasingly important part of national energy systems. Utilities invested in transmission networks, storage and system flexibility. Corporate buyers entered the market through Power Purchase Agreements (PPAs), while policymakers began addressing challenges such as grid congestion, balancing and energy security.

The next phase is fundamentally different.

Success will depend less on building individual assets and more on creating integrated value chains in which electricity, renewable gases and low-carbon fuels develop together. That requires generation assets, pipelines, storage facilities, transmission infrastructure, industrial demand, certification systems and financing to evolve simultaneously.

Technology alone cannot coordinate that level of investment. Commercial agreements can.

Whether the project is a solar park, an anaerobic digestion facility or a hydrogen production plant, investors face the same underlying question:

Who will buy the output, under what conditions, and for how long?

Without a credible answer, financing becomes more expensive—or disappears altogether.

This creates a paradox that receives surprisingly little attention.

Much of the public debate continues to focus on reducing the production cost of low-carbon energy. Yet financing costs can be equally important. A project with slightly higher production costs but stable, contracted revenues may prove significantly easier—and ultimately cheaper—to finance than a technically superior project exposed entirely to volatile spot markets.

The competitive advantage is therefore beginning to shift. It is no longer enough to build efficient technology. Developers increasingly need to build commercial confidence.

Electricity Contracts Are Becoming Strategic Assets

The electricity market illustrates this transition most clearly.

For many years, Power Purchase Agreements were viewed largely as procurement tools. Utilities, industrial consumers and technology companies used them to secure renewable electricity at predictable prices while providing project developers with a stable source of revenue.

Today their importance extends much further.

Electricity demand is expected to increase substantially as transport, heating and industrial processes become increasingly electrified. At the same time, the rapid expansion of artificial intelligence is driving unprecedented investment in data centers, placing additional pressure on electricity systems that are already becoming more constrained.

Meanwhile, electricity prices have become more volatile as weather-dependent renewable generation represents a larger share of the generation mix.

For producers, this creates revenue uncertainty. For consumers, it creates cost uncertainty. Long-term contracts reduce both.

For renewable energy developers, a long-term PPA provides the revenue visibility needed to obtain financing. For corporate buyers, it offers protection against future price volatility while supporting increasingly ambitious decarbonization commitments.

However, the real value of these agreements extends far beyond locking in a fixed electricity price.

Modern power contracts allocate a broad range of commercial risks, including production profiles, balancing costs, curtailment, grid constraints, environmental certificates, credit exposure and regulatory change.

In other words, the contract is no longer simply an agreement to purchase electricity. It has become the financial architecture that enables the physical asset to exist.

This is becoming increasingly important as electricity markets grow more complex.

A solar farm produces electricity when the sun shines, not necessarily when an industrial facility or a data center requires power. Bridging that gap increasingly requires storage, flexible demand, complementary generation or sophisticated market arrangements.

As a result, electricity procurement is evolving from a purchasing exercise into a strategic business decision. Companies are no longer securing only a commodity. They are securing future access to reliable, low-carbon energy in an increasingly competitive market.

In that sense, long-term power contracts are beginning to function as infrastructure themselves.

Biomethane Is Leaving the Subsidy Era Behind

The same transformation is beginning to reshape the biomethane market.

For many years, biomethane projects relied heavily on government support mechanisms, including feed-in tariffs and production incentives. While these policies played an important role in establishing the sector, they were never intended to become permanent.

The market is now gradually moving towards commercial contracting.

That transition is particularly important because biomethane projects involve significant upfront investment. Developers must secure reliable feedstock supplies, construct anaerobic digestion facilities, connect to gas networks, comply with sustainability requirements and operate facilities for decades.

The commercial risks are therefore substantial.

Revenue increasingly depends not only on the market price of natural gas, but also on sustainability certificates, emissions savings, regulatory frameworks and the willingness of industrial customers to purchase renewable gas over long periods.

One agreement illustrates this new commercial model.

AstraZeneca recently signed a 15-year Biomethane Purchase Agreement with Future Biogas in the United Kingdom. The significance of the deal extends well beyond the delivery of renewable gas to one pharmaceutical company.

By committing to purchase biomethane over the long term, AstraZeneca is helping convert uncertain future revenues into predictable cash flows. Those predictable revenues provide lenders and investors with greater confidence that additional production capacity can be financed.

The contract is therefore doing more than supplying energy. It is enabling investment.

That distinction is becoming increasingly important as for instance Europe pursues ambitious renewable gas targets.

The European Union aims to increase biomethane production to 35 billion cubic metres annually by 2030—roughly five times current production. Achieving that objective will require far more than additional anaerobic digestion plants. It will require a commercial market capable of supporting billions of euros of private investment through predictable long-term revenues.

Europe wants to increase biomethane production five-fold by 2030. The technology largely exists. Feedstocks are becoming more readily available. Yet across Europe, and increasingly across global energy markets, developers are confronting the same question:

Who is willing to sign a fifteen-year contract?

The answer to that question may determine not only the future of biomethane, but also the pace of hydrogen deployment, renewable electricity investment and hundreds of billions of dollars in low-carbon infrastructure.

This article continues for paid subscribers with:

• Why Saudi Aramco could not proceed with one of the world’s largest blue hydrogen ambitions despite abundant natural gas and carbon capture capacity.

• How RWE’s Chemelot project illustrates Europe’s hydrogen investment dilemma.

• Why Microsoft, Google and Amazon are reshaping electricity markets through long-term Power Purchase Agreements.

• Why long-term commercial agreements—not technology—may become the defining competitive advantage of the energy transition.

Read more

When I launched this publication, my goal was simple: to provide thoughtful, independent analysis of the forces reshaping global energy, electricity, artificial intelligence, LNG, carbon markets and geopolitics.

Over the past months, this community has grown far beyond what I expected. Thank you for reading, subscribing, sharing my articles, and being part of this journey.

Today, I’m excited to share the next chapter.

From now on, this publication will offer both free and paid subscriptions.

Producing independent, evidence-based long-form analysis takes time. Every article requires extensive research, reading and writing to connect developments across energy markets, technology, economics and geopolitics.

Introducing paid subscriptions will allow me to dedicate even more time to producing the kind of in-depth analysis this publication was created for, while continuing to provide valuable content to all readers.

Free

A free subscription includes:

• One full flagship article every month

• A weekly Executive Briefing (the opening section of every premium analysis)

• Market updates and commentary

• Notification whenever a new article is published

Free subscribers will continue to receive valuable insights into energy, electricity, artificial intelligence, data centres, LNG, carbon markets and geopolitics.

Premium (€15/month | €150/year)

A paid subscription includes:

• One exclusive long-form analysis every week

• Around 50 in-depth analyses every year

• Independent research and analysis that goes beyond the headlines

• Full access to the complete archive

• Early access to every new publication

• Participate in subscriber discussions

Premium is designed for professionals, business leaders and decision-makers who want to understand the structural trends shaping global energy markets, artificial intelligence, industrial competitiveness and geopolitics—before they become tomorrow’s headlines.

If my articles have helped you better understand the forces shaping global energy, electricity, AI and geopolitics, I invite you to become a paid subscriber.

Your support makes it possible to continue producing independent, in-depth analysis every week—without advertising, clickbait or sponsored content.

Whether you choose to remain a free subscriber or become a paid member, thank you for being part of this community. Your readership, feedback and support have made this publication possible, and I look forward to continuing this journey with you.

Thank you for reading.

Best regards,

Kasper Walet

For most of the twentieth century, economic power depended on oil. Nations fought wars to secure it, industries were built around it, and foreign policy revolved around it. Oil was not simply another commodity; it was the foundation of modern economic and geopolitical power.

A similar transformation is now unfolding, but this time the strategic resource is different. The defining energy challenge of the coming decades is unlikely to be access to oil or natural gas. It will be access to abundant, reliable electricity.

This shift has received little attention. Public debate remains focused on climate targets, renewable energy, and net-zero commitments. While these goals are essential, they increasingly obscure a larger strategic reality: electricity is becoming the limiting factor for economic growth in the world’s largest economies.

Why AI Is Driving Electricity Demand

The reason is straightforward.

Nearly every technology expected to drive productivity in the coming decades depends on electricity. Artificial intelligence requires large clusters of processors running continuously in energy-intensive data centres. Electric vehicles shift energy demand to the grid. Green hydrogen production consumes significant electricity through electrolysis. Semiconductor fabrication, battery manufacturing, cloud computing, and advanced automation all require secure, continuous power.

What makes this transition fundamentally different from previous waves of electrification is its scale. For decades, electricity demand in advanced economies grew slowly. Energy efficiency gains largely offset economic expansion, enabling governments to plan for stable consumption. This assumption is now becoming obsolete.

The International Energy Agency projects that global electricity demand from data centres will more than double by decade’s end, with artificial intelligence driving much of this growth. The largest AI campuses under development are expected to require one to five gigawatts of continuous electricity, comparable to the consumption of entire metropolitan areas.

Electricity is no longer simply supporting the digital economy. It is becoming the digital economy. That changes the policy challenge completely.

Why the Future Requires More Electricity, Not Just Cleaner Electricity

Governments have focused on replacing fossil fuels with cleaner alternatives. The next, larger challenge is to build electricity systems that can supply significantly more power while maintaining reliability, affordability, and low emissions.

This is where simplistic debates about individual technologies begin to lose relevance.

There is no single technology capable of delivering the electricity system future economies will require.

Solar and wind generation are expanding rapidly and often provide the lowest-cost new electricity. Battery storage improves grid flexibility, and hydroelectric power remains a valuable low-carbon baseload source where feasible. Natural gas provides dispatchable capacity during peak demand or low renewable output. Emerging technologies such as enhanced geothermal systems, long-duration storage, and carbon capture may also contribute.

Each technology offers distinct advantages. Each also comes with limitations.

Wind and solar depend on weather, requiring significant investment in storage, transmission, and flexible generation. Hydropower is limited by geography and changing rainfall. Natural gas faces fuel-price volatility and geopolitical risks, while many emerging technologies are not yet proven at commercial scale.

This is precisely why nuclear power has returned to the centre of long-term energy planning.

Modern nuclear reactors, unlike most low-carbon technologies, generate large amounts of electricity continuously, regardless of weather, and operate for sixty years or more with predictable fuel costs. They do not replace renewables, nor do renewables replace nuclear. Both are increasingly seen as complementary in systems designed for reliability and decarbonisation.

Viewed through this broader lens, the question is no longer whether one technology should defeat another.

The more important question is whether countries can build electricity systems that are large enough, reliable enough and affordable enough to support the industries that will define the next generation of economic growth.

Why China Is Building More Nuclear Reactors Than Any Other Country

No country appears to understand that challenge more clearly than China.

While much of the West debates the optimal energy mix, China is undertaking the largest expansion of electricity infrastructure in modern history. It is building more nuclear reactors than any other country, deploying renewables, expanding ultra-high-voltage transmission, and investing heavily in large-scale energy storage.

At first glance, this appears to be another chapter in China’s decarbonisation strategy.

It is something considerably more ambitious. Beijing is preparing its electricity system for an economy led by artificial intelligence, advanced manufacturing, electrification, and digital infrastructure. Reliable electricity is now viewed as more than an environmental goal or public utility.

It is being treated as strategic economic infrastructure. That distinction matters.

Historically, countries with abundant energy gained more than just lower costs; they attracted industries, investment, and technological leadership. A similar dynamic may now be emerging with electricity.

China’s strategy suggests that the competition is no longer centred on producing cleaner electricity alone. It is about ensuring that electricity never becomes a constraint on economic growth.

That may prove to be one of the defining competitive advantages of the twenty-first century.

So far we’ve explored why electricity demand is accelerating and why China is investing at unprecedented scale. The second half of this analysis examines what these developments mean for industrial competitiveness, AI infrastructure, nuclear strategy and the future balance of global economic power.

Read more

For over fifty years, the Middle East has influenced the global economy through oil. Oil financed the rise of modern Gulf states, transformed small desert settlements into financial centers, and made the region essential to the world’s energy system. However, another resource, often overlooked, may be even more strategic. Unlike oil, it cannot be traded internationally, stored long-term, or replaced by technology. Yet without it, the Gulf’s economic transformation would not have been possible. That resource is water.

The Gulf is most often associated with energy.

Images of oil fields in Saudi Arabia, LNG terminals in Qatar, and the skylines of Dubai and Abu Dhabi define the region. For decades, the Middle East has been viewed through the lens of hydrocarbons. Oil generated significant wealth, funded major infrastructure, and transformed small economies into some of the world’s fastest-growing commercial hubs. However, this narrative overlooks another key foundation of that growth.

It is one of the most remarkable economic transformations of modern history. Yet another critical story receives far less attention. Modern Gulf economies were built on more than oil. They were also built on water.

While every society depends on water, the stakes in the Gulf are unique. Much of the Arabian Peninsula receives less than 100 millimeters of rainfall annually, has almost no permanent rivers, and experiences summer temperatures above 45 degrees Celsius. By most natural measures, these conditions should make large urban populations and energy-intensive industries unsustainable.

Yet these populations and industries continue to thrive.

Saudi Arabia’s population has increased from fewer than 4 million in the early 1960s to over 35 million today. The United Arab Emirates has grown from small coastal settlements into a global center for finance, logistics, aviation, and tourism. Entire industrial cities have developed where only desert existed a few generations ago.

Oil financed this transformation, but oil alone could not have sustained it. Every refinery, airport, industrial complex, data center, and residential neighborhood ultimately depends on a resource far scarcer than hydrocarbons.

Fresh water.

Understanding how the Gulf addressed this challenge explains one of the region’s greatest achievements. Equally important, it highlights a significant long-term vulnerability.

It also reveals one of its greatest long-term vulnerabilities, as the region’s growth depends on a resource that cannot be assumed to last forever.

The Hidden Resource Beneath the Desert

Many assume the Gulf’s water story began with desalination, but its origins date back thousands of years.

Long before desalination plants lined the Gulf coast, vast quantities of freshwater accumulated beneath the Arabian Peninsula during much wetter climatic periods. These underground reservoirs, known as fossil aquifers, were formed when rainfall slowly penetrated deep geological formations tens of thousands of years ago.

Unlike renewable groundwater systems, these aquifers receive almost no replenishment under current climatic conditions, making their depletion increasingly significant.

Practically, they function much like oil reservoirs. They can be extracted, but they cannot realistically be replaced.

Throughout much of the twentieth century, these ancient groundwater reserves supported expanding agriculture and growing populations. When oil revenues surged in the 1970s, governments gained the means to exploit these reserves on an unprecedented scale. Huge circular irrigation systems transformed sections of the Saudi desert into green fields visible from space. Wheat production rose sharply, and dairy farming expanded into areas previously unsuitable for agriculture.

For a period, Saudi Arabia even became one of the world’s largest wheat exporters. This was an extraordinary engineering achievement. However, it relied on a resource that was never truly renewable.

As agricultural expansion succeeded, ancient groundwater reserves were depleted more rapidly, increasing the region’s dependence on a diminishing resource.

Eventually, policymakers recognized that this model was unsustainable, prompting a gradual shift in agricultural policy. Domestic wheat production was reduced, as food could be imported. Water could not.

This realization marked the start of a broader transformation, as the region confronted the limits of its previous water model.

Instead of extracting freshwater from beneath the desert, Gulf countries increasingly began producing it from the sea. Desalination appeared to solve the region’s greatest natural constraint.

In reality, this marked the beginning of a new era, where water became less dependent on geology and increasingly reliant on energy, technology, and infrastructure, with significant implications for the region’s future.

This distinction may prove even more important, as it highlights water as the region’s most strategic resource.

When Water Becomes Infrastructure

For much of the twentieth century, the Gulf’s water story appeared to be one of engineering triumph. As fossil groundwater became inadequate for growing cities and industries, governments turned to the sea. Advances in desalination, supported by abundant oil and gas, enabled large-scale freshwater production. Technology increasingly replaced natural sources.

This was a significant achievement.

Within a few decades, countries that once relied on scattered wells and ancient aquifers developed some of the world’s largest desalination facilities. Today, most of the Gulf’s drinking water comes from seawater, enabling cities like Dubai, Abu Dhabi, Doha, and Riyadh to expand despite extremely harsh climates.

To many, desalination seemed to solve the region’s water challenges. In reality, it shifted the problem. The Gulf did not eliminate water scarcity; it exchanged one dependency for another.

Instead of relying on ancient groundwater reserves, modern economies became dependent on industrial infrastructure. Freshwater was no longer something supplied primarily by nature. It became something manufactured through electricity, chemicals, pipelines, pumping stations and highly sophisticated engineering systems.

Water quietly became another industrial product.

That distinction may sound subtle. In practice, it fundamentally changes how businesses should think about resource security.

Natural aquifers continue to exist even during political crises. Industrial infrastructure does not.

Every cubic meter of desalinated water depends on uninterrupted electricity supplies, functioning transmission networks, operational treatment plants, specialized maintenance and secure access to the coastline. Remove any one of those elements and freshwater production begins to suffer.

The Gulf’s remarkable economic transformation therefore rests on an infrastructure system that has become every bit as strategic as its oil terminals, LNG export facilities and electricity grids.

Perhaps even more so. Because unlike oil, water has no substitute.

The New Energy-Water Economy

This is where the story becomes particularly interesting.

For decades, energy and water were largely treated as separate policy discussions. Energy ministries focused on electricity generation and fuel supply. Water authorities focused on treatment, distribution and consumption.

Increasingly, those distinctions are disappearing. Desalination consumes enormous quantities of electricity. Electricity generation itself often depends on reliable water supplies. Hydrogen production requires both. Advanced manufacturing requires both. Data centers require both.

What once appeared to be separate infrastructure systems are gradually merging into one interconnected resource network. That changes the economics entirely.

The future competitiveness of many industries will increasingly depend not simply on access to affordable electricity, but on access to electricity and water simultaneously.

This becomes particularly relevant as Gulf economies diversify beyond hydrocarbons.

Artificial intelligence is driving unprecedented investment in hyperscale data centers. Green hydrogen projects are being announced across the region. Advanced manufacturing, chemicals and semiconductor production all require highly reliable electricity alongside secure water supplies.

Ironically, the industries expected to define the Gulf’s post-oil future are making water infrastructure more important than ever. The transition away from hydrocarbons is not reducing the strategic importance of water. It is increasing it.

Infrastructure Is Becoming the New Strategic Asset

Another important consequence often goes overlooked.

Historically, strategic infrastructure in the Middle East referred to oil fields, export terminals, and pipelines. Today, desalination plants are equally critical. They are no longer just utilities but essential national infrastructure.

Their importance extends beyond drinking water. Desalination plants support industrial production, logistics, healthcare, tourism, agriculture, and nearly every sector vital to Gulf economies.

This shift also changes how investors view infrastructure. Desalination is no longer seen only as a utility business but increasingly as strategic infrastructure, comparable to electricity transmission networks or natural gas pipelines.

Its value is not limited to water production; it enables the entire economy to function. As a result, resilience is as important as efficiency.

Simply building larger desalination plants is no longer sufficient.

Governments now require redundancy, storage capacity, diversified electricity supplies, cyber resilience, and physical protection against natural and geopolitical disruptions.

The focus is shifting from water production to water security, marking a significant change.

Security is ultimately what infrastructure investors, industrial companies, and governments value most.

A Different Kind of Resource

Water is gradually becoming a competitive resource, not just an environmental one. For decades, companies evaluated investment locations based on labor costs, taxation, logistics, and energy prices. Now, long-term water resilience is becoming an essential consideration. Semiconductor fabrication plants, hydrogen production facilities, and hyperscale data centers cannot easily relocate if freshwater becomes limited.

These investments are intended to operate for decades. Companies need assurance that electricity and water infrastructure will remain reliable throughout the assets’ lifespan.

Water is shifting from an operational concern to a strategic priority in the boardroom. This may become one of the most significant resource changes in the coming decades.

The Gulf now demonstrates that modern economies depend on highly integrated infrastructure systems, where energy, water, and industrial competitiveness are inseparable.

The Real Strategic Shift

For decades, geopolitical risk in the Middle East was largely viewed through a single lens: oil.

Governments tracked crude exports through the Strait of Hormuz. Financial markets responded to tanker disruptions. Energy companies assessed political instability mainly for its impact on global hydrocarbon supply.

That framework is no longer sufficient.

The region’s future will still rely on energy, but increasingly, energy itself will depend on a less visible resource: water.

This represents a fundamental shift in how businesses should think about a new strategic risk.

Unlike oil, water cannot be easily imported when domestic supply is limited. Unlike natural gas, it cannot be rerouted through another pipeline. Freshwater is now an industrial product, with its availability relying on electricity, desalination, transmission infrastructure, and geopolitical stability working as one system.

That has profound implications for business.

For decades, companies assessed new investments by comparing labor costs, taxes, logistics, and energy prices. Now, long-term water resilience also deserves consideration. This is why water is quietly becoming a boardroom issue.

This is not due to concerns about running out of drinking water, but because reliable water access now determines the reliability of electricity systems, industrial competitiveness, and overall supply chain resilience.

The implications extend well beyond the Gulf.

Many of the world’s fastest-growing economies face similar challenges. Northern Africa, parts of India, Australia, Chile, Southern Europe, and the southwestern United States all experience rising electricity demand, increasing water stress, and rapid industrial electrification.

As these trends continue, access to reliable water may shape industrial competitiveness just as inexpensive energy shaped industrial development in the twentieth century. Only this time, the defining resource may not be oil.

A New Resource Economy

There is perhaps an even broader lesson emerging.

Throughout modern economic history, technological innovation seemed to reduce dependence on natural constraints. Oil replaced coal. Global trade lessened reliance on local production. Digital technologies made economies less dependent on physical resources.

Water reminds us that some constraints never fully disappear. Technology can delay them. Engineering can reshape them. Capital can overcome them temporarily. Ultimately, every economy depends on a few fundamental resources.

The Gulf’s extraordinary transformation demonstrates both the power of human innovation and its limits.

For more than half a century, engineering achieved what previous generations considered impossible. Cities flourished where almost no permanent settlements had existed before. Entire industries emerged in one of the harshest climates on Earth. Millions of people built prosperous lives in places once considered uninhabitable.

This achievement should not be underestimated, nor should its increasing complexity.

For most of the past two decades, the debate around renewable energy focused on a single question: can renewables replace fossil fuels? Increasingly, that is becoming the wrong question. Solar and wind are now among the cheapest sources of new electricity generation in many markets. Battery costs continue to fall. Renewable deployment continues to accelerate. The more important question is no longer whether renewable electricity can be generated. It is whether it is available when it is actually needed.

For years, critics of renewable energy asked the same question:

What happens when the wind isn’t blowing and the sun isn’t shining?

The answer was usually fossil fuels. Today, that answer is increasingly becoming batteries.

Solar and wind power have become extraordinarily cheap. In many markets, they are now the lowest-cost source of new electricity generation. At the same time, battery costs have fallen dramatically, creating a combination that is beginning to reshape electricity systems around the world.

For the first time, round-the-clock renewable electricity is becoming commercially viable at scale.

This shift could not come at a more important moment.

Electricity demand is entering a new era of growth. Artificial intelligence, electrification, hydrogen production and industrial decarbonization are all driving unprecedented demand for reliable power. At the same time, geopolitical tensions continue to remind governments and businesses that energy security cannot be taken for granted.

Against this backdrop, the conversation is moving beyond a simple question of whether companies buy renewable energy.

The more important question is becoming whether renewable energy is available when it is actually needed.

That is the essence of 24/7 matching.

From Annual Accounting to Hourly Reality

For most of the past two decades, corporate renewable energy procurement has been based on annual accounting.

A company consumes electricity throughout the yea-r and purchases an equivalent amount of renewable energy through certificates, guarantees of origin or power purchase agreements. On paper, annual consumption and annual renewable generation are balanced.

This approach played a critical role in scaling renewable investment. It created demand, supported project financing and accelerated the deployment of solar and wind capacity around the world. However, electricity systems do not operate on an annual basis. They operate hour by hour.

A manufacturing facility may consume electricity at midnight while a solar farm generated its electricity months earlier. An annual accounting framework may classify both as renewable, but from a system perspective the facility may still be relying on fossil generation during those hours.

As renewable penetration increases, that distinction becomes increasingly important. The challenge is no longer simply adding more renewable generation to the grid. The challenge is ensuring that clean electricity is available when demand occurs. This is where 24/7 matching enters the picture.

Rather than asking whether a company purchased enough renewable electricity over the course of a year, 24/7 matching asks a far more precise question:

How much of a company’s electricity demand was matched by carbon-free electricity during every hour of operation?

Why This Is Really About Risk

The discussion around 24/7 matching is often framed as a sustainability issue. In reality, it is equally an energy risk management issue.

Electricity markets settle hourly. Prices move hourly. Supply shortages emerge hourly. Reliability challenges occur hourly. Risk therefore exists hourly.

A company whose electricity consumption profile differs significantly from its renewable generation profile remains exposed to market volatility regardless of how many annual renewable certificates it purchases.

This is particularly relevant for industries that operate continuously. Data centers, semiconductor manufacturers, chemical plants, steel mills and other energy-intensive facilities cannot simply stop operating when renewable output falls.

The mismatch between generation and demand creates exposure to balancing costs, spot market prices, capacity constraints and ultimately security-of-supply risks. Viewed through this lens, matching is not primarily an environmental metric. It is a hedge.

The more closely renewable supply aligns with actual consumption, the more effectively a company can manage both carbon exposure and energy price risk. As renewable penetration increases across electricity systems, understanding this relationship becomes a strategic necessity rather than a sustainability aspiration.

Batteries Are Changing the Equation

For years, storage was the missing piece. Solar generation peaks during daylight hours. Wind generation fluctuates with weather conditions. Matching these resources to continuous demand was technically possible, but often economically challenging.

That equation is changing rapidly. Battery costs have fallen at a pace few anticipated a decade ago. Developers are increasingly combining solar, wind, battery storage and flexible demand management into integrated portfolios designed to provide power across a much larger share of the day.

Renewable energy is no longer merely an intermittent resource. It is increasingly becoming a dispatchable one.

That distinction may prove to be one of the most important developments in the energy transition. Because once renewable electricity can be shifted in time, the discussion moves away from generation and towards availability. And availability is what ultimately matters to businesses.

The Emerging Competitive Advantage

The implications extend well beyond technology companies. As carbon reporting frameworks become more granular and regulations such as CBAM continue to evolve, the ability to demonstrate when clean electricity was consumed may become increasingly valuable.

What began as a sustainability discussion is gradually becoming a competitiveness discussion. Companies capable of demonstrating a stronger relationship between production activities and clean electricity consumption may enjoy advantages not only in carbon reporting, but potentially in market access, customer relationships and future regulatory compliance.

The implications may be particularly significant for exporters competing in carbon-conscious markets. Electricity procurement, emissions reporting, production records and trade compliance are becoming increasingly interconnected. That trend is unlikely to reverse.

There is also a broader geopolitical dimension emerging. Not all countries will participate equally in the economics of 24/7 renewables. Regions with abundant solar and wind resources, combined with access to storage and transmission infrastructure, may gain significant advantages in attracting future investment, industrial production and digital infrastructure.

The competition is no longer simply about who can generate renewable electricity. Increasingly, it is about who can deliver reliable renewable electricity when it is needed.

Negotiating for an Hourly World

As interest in 24/7 matching grows, many companies are discovering that traditional renewable PPAs may no longer answer the questions that matter most.

For years, negotiations largely focused on two variables: price and volume. How much renewable electricity would be delivered, and at what cost? In an hourly world, however, timing increasingly becomes just as important.

Consider a company that signs a large solar PPA because it offers the lowest price. On paper, the contract may fully cover annual electricity consumption. In practice, however, most of the generation occurs during daylight hours while a significant share of the company’s consumption takes place during evenings, nights and winter months.

The result is a contract that looks highly attractive in a board presentation, but leaves the company exposed to exactly the periods when electricity prices can become most volatile.

Increasingly, buyers are discovering that a megawatt-hour is not always just a megawatt-hour. When it is delivered matters. This is starting to change the nature of negotiations.

Questions that rarely appeared in renewable energy contracts a few years ago are becoming increasingly important. How much of the generation profile aligns with actual consumption? What happens during prolonged periods of low renewable output? Who bears the cost when generation and demand fail to match? How is battery storage dispatched, and who controls those decisions?

These are no longer technical questions reserved for energy specialists. They are commercial questions.

Imagine a manufacturer operating around the clock. One supplier offers a highly competitive solar contract, while another proposes a more expensive portfolio combining solar, wind and battery storage. Traditionally, the cheapest offer might have won. Increasingly, buyers are discovering that the second option may provide significantly greater protection against balancing costs, price spikes and supply volatility.

The cheapest electricity is not always the lowest-cost solution. The same dynamic is beginning to emerge around battery storage.

For many companies, storage is no longer simply an engineering consideration. It is becoming a contractual one. Decisions around charging schedules, dispatch priorities, performance guarantees and revenue sharing can materially affect both matching performance and economic outcomes.

In many respects, renewable energy contracts are gradually evolving into flexibility contracts. The objective is no longer simply to secure renewable electricity. It is to secure renewable electricity when it is actually needed.

Will This Only Matter for Large Corporates?

Today, 24/7 matching is primarily being driven by large electricity consumers.

Technology companies, hyperscale data centers and energy-intensive industrial facilities have both the scale and the resources to pursue highly sophisticated procurement strategies. They also face growing scrutiny from investors, regulators and customers regarding their energy consumption and emissions profiles.

But that does not mean smaller companies can ignore the trend.

Historically, many developments in energy procurement have followed a similar pattern. Renewable PPAs, carbon accounting and science-based targets all began with large multinational companies before gradually becoming mainstream.

24/7 matching may follow a similar path. As storage costs continue to decline and procurement products become more sophisticated, many of the benefits currently available to large buyers are likely to become accessible to a much broader range of companies.

The timeline may differ by market and industry, but the direction of travel is increasingly clear. Hourly matching is unlikely to remain a niche procurement strategy reserved for a handful of technology giants.

It may ultimately become the next logical evolution of corporate renewable energy procurement.

The Future Is Hourly

The renewable energy transition has entered a new phase. The first phase focused on building renewable generation. The second focused on scaling deployment and reducing costs. The next phase is about integration.

As batteries become cheaper, grids become smarter and electricity demand becomes increasingly electrified, the value of renewable energy will no longer be measured solely by how much is generated. It will increasingly be measured by when it is available.

For corporate buyers, that represents far more than another sustainability trend. It is a question of energy security, risk management, competitiveness and resilience.

The countries, industries and companies that master 24/7 renewable electricity first may gain a significant advantage in attracting future investment, data centers, hydrogen projects, advanced manufacturing and AI infrastructure.

Because ultimately, the first phase of the energy transition was about generating clean electricity. The next phase is about making it available exactly when it is needed.

And the organizations that understand that distinction early may gain an advantage that extends far beyond sustainability reporting.

In 2008, traders were paying more than €20 for a CER. A few years later, many of those same credits were effectively worthless. The collapse was so dramatic that younger carbon market professionals sometimes forget how quickly confidence can disappear once a market loses faith in both the quality of the commodity and the balance between supply and demand.

I remember that period well.

Having spent almost four decades working in energy and environmental commodity markets—from power and gas to emissions trading, renewable certificates, Guarantees of Origin, LNG and carbon markets—I have learned that markets rarely fail because of a single mistake.

They fail when several weaknesses reinforce one another. That is why I find the current debate surrounding Article 6.4 increasingly fascinating. Most discussions focus on methodologies, governance frameworks, corresponding adjustments and environmental integrity.

Those issues are important.

But I am increasingly convinced that the biggest threat facing the Paris Agreement Crediting Mechanism (PACM) is not the quality of future credits. It is the market’s confidence in future demand and future scarcity.

And history suggests those two issues deserve far more attention than they currently receive.

PACM Is Attempting Something No Commodity Market Has Ever Done Successfully

Every successful commodity market starts with a scarcity story. North Sea gas. European power markets. EU Allowances. LNG. Even crude oil.

Investors commit capital because they believe future scarcity will support future value. Scarcity creates price signals. Price signals attract investment. Investment creates liquidity. Liquidity creates markets.

PACM is attempting something very unusual. It is trying to launch a new commodity market while simultaneously debating how many credits from the old market should remain valid. As a market proposition, that is uncomfortable.

Imagine launching a new oil market while informing investors that a giant strategic reserve may be released at any moment. Investors would immediately ask the obvious question:

Why should I expect scarcity?

That is precisely the question Article 6.4 investors are beginning to ask.

The Carbon Market Community May Be Looking in the Wrong Direction

Much of the current discussion focuses on the quality of future credits. That is understandable. The CDM left behind legitimate concerns regarding additionality, baseline methodologies and environmental integrity.

But quality is only one part of a functioning commodity market. The carbon market community is obsessed with the quality of future credits. I am increasingly concerned about the quality of future demand.

Because the highest-quality carbon credit in the world is worth very little if nobody needs to buy it.

This is the question that receives surprisingly little attention. Who exactly will generate large-scale demand for Article 6.4 credits? The EU ETS almost certainly will not. The UK ETS appears unlikely. California has shown little interest. China remains focused on domestic compliance.

Many corporate buyers are increasingly shifting their attention toward carbon removals rather than traditional reduction credits.

At the same time, governments appear increasingly attracted to bilateral Article 6.2 agreements that offer greater control than a centralized UN mechanism.

Which leaves a simple but uncomfortable question.

Where will the demand come from?

If future demand remains uncertain, why are so many market participants assuming strong future prices? In every commodity market I have worked in, demand uncertainty eventually translates into price uncertainty. Carbon markets are unlikely to prove different.

The Market Everyone Wants to Forget

The CDM was one of the most ambitious climate finance mechanisms ever created. At its peak, CERs traded above €20 per ton. Billions of dollars flowed into developing countries. More than two billion CERs were ultimately issued.

Today, many observers explain the collapse of the market as a classic oversupply story. That explanation is incomplete. Commodity markets survive oversupply all the time. Oil markets survive it. Gas markets survive it. Power markets survive it.

Prices fall. Investment slows. The market eventually rebalances.

The CDM collapsed because oversupply coincided with a collapse in confidence.

Questions emerged around additionality. Would some wind projects have been built anyway? Would some hydro projects have proceeded without carbon finance? Were industrial gas projects exploiting methodological loopholes? As those questions accumulated, buyers became increasingly selective. A CER was no longer simply a CER.

Trust began to disappear. And once trust disappears, liquidity usually follows.

When Buyers Stop Trusting the Commodity

The concentration of CER issuance amplified the problem. China alone accounted for more than half of all CER issuance. Together, China and India represented the overwhelming majority of supply.

Many of these projects undoubtedly delivered genuine emission reductions. But perception matters in commodity markets.

As concerns surrounding additionality, project economics and baseline assumptions became associated with some of the largest project categories, the reputation of the market as a whole deteriorated.

By the end of the CDM era, buyers were no longer asking how many CERs were available. They were asking whether they trusted them. That distinction proved fatal.

Once a commodity loses fungibility, liquidity begins to disappear. And once liquidity disappears, confidence often follows.

The Billion-Ton Shadow Hanging Over Article 6.4

This is where the debate becomes particularly interesting.

Under the Paris Agreement transition arrangements, certain CERs generated from projects registered after 1 January 2013 may remain eligible toward the first generation of Nationally Determined Contributions.

The exact number remains heavily debated. Some estimates suggest several hundred million credits. Others point to a broader legacy inventory approaching one billion tons that could continue influencing market expectations.

In my view, the precise number is almost irrelevant. Markets do not price certainty. Markets price possibility.

Imagine you are developing a new Article 6.4 project. Perhaps a methane reduction project, a forestry program, an industrial decarbonization project or a carbon removal facility.

Your investment case depends on future carbon prices.

Would you commit capital if you believed a substantial inventory of low-cost legacy credits might eventually compete with your project? Would your lenders? Would your shareholders? Or would they wait?

That is the real issue. The threat is not necessarily the arrival of hundreds of millions of CERs. The threat is the market’s belief that they might arrive.

Markets Trade Expectations Long Before They Trade Commodities

This is where many policy discussions diverge from market reality. Commodity markets do not wait for oversupply to materialize. They react to the expectation of oversupply.

The moment traders believe a large inventory may enter the market, future prices begin adjusting. The commodity does not need to be delivered. The expectation alone is enough.

Forward curves weaken. Financing becomes more difficult. Risk premiums increase. Investment decisions are delayed. The market begins repricing long before a single additional credit is issued.

This is why the CER overhang matters. Not because every CER will qualify. Not because every CER will be used. But because every market participant knows they exist.

A Bigger Risk Than Oversupply

The challenge facing PACM is not merely one of supply. It is one of identity. The mechanism is trying to establish itself as the next generation of international carbon markets. It wants to distinguish itself from both the CDM and the credibility challenges that have affected parts of the voluntary carbon market.

Yet it remains tied to the legacy of the very system it was designed to replace. Fairly or unfairly, CERs carry historical baggage.

For many investors, developers and corporate buyers, the acronym still evokes memories of oversupply, questionable additionality and collapsing prices.

The moment market participants begin asking whether Article 6.4 is simply “CDM 2.0”, confidence becomes harder to build.

Carbon markets are ultimately trust markets. Without trust, liquidity rarely follows.

The Collision Course with Carbon Removals

This debate becomes even more important when viewed through the lens of carbon removals.

The next generation of climate markets will increasingly depend on technologies such as CCS, Direct Air Capture, BECCS and other engineered removals.

These projects are expensive. Many require carbon prices measured in hundreds of dollars per ton. Investors will only commit capital if they believe durable and credible price signals exist.

A market overshadowed by uncertainty regarding legacy credits sends precisely the opposite signal. Ironically, a mechanism designed to mobilize future climate investment could end up discouraging some of the very technologies needed to achieve net zero.

The Real Risk Is Not Oversupply. It Is Irrelevance

Most commentators assume PACM’s greatest challenge will be environmental integrity.

I am not so sure. My suspicion is that the biggest challenge over the next decade will be relevance. If developers conclude that prices will remain weak, they will look elsewhere. If governments prefer Article 6.2 agreements, they will look elsewhere. If corporate buyers prioritize removals, they will look elsewhere.

Markets rarely disappear overnight. More often, they are gradually bypassed.

Liquidity migrates. Investment migrates. Attention migrates.

And eventually the market discovers that being available is not the same as being necessary.

Have We Really Learned the Lessons of the CDM?

The architects of Article 6.4 have spent years strengthening methodologies, governance and transparency. Those reforms matter.

But they address only one of the three pillars upon which every successful commodity market rests: Quality. The market is still waiting for convincing answers regarding the other two: demand and scarcity.

The CDM did not fail because the world stopped caring about climate change. It failed because buyers lost confidence in the commodity. PACM may well avoid many of the methodological mistakes of the CDM.

The more important question is whether it can avoid the market mistakes. Because markets that fail to attract confidence do not necessarily collapse.

Sometimes they are simply bypassed.

The Lesson Enron Still Teaches Us

This year marks twenty-five years since the collapse of Enron.

For many people, Enron remains synonymous with accounting fraud and corporate misconduct. It is remembered as one of the largest corporate failures in modern history and a case study in governance failure taught in business schools around the world.

However, viewing Enron solely as an accounting scandal overlooks its broader significance as a story about markets.

The company helped transform energy trading from a largely physical business into a sophisticated financial marketplace. It pioneered new trading models, introduced innovative products and demonstrated how energy could increasingly be treated as a financial asset rather than simply a physical commodity.

For a period, Enron was celebrated as the future of energy trading, until its collapse.

Enron’s collapse demonstrated more than executive misconduct; it revealed that complexity had surpassed transparency. Investors, counterparties, and regulators often struggled to understand the associated risks.

Innovation advanced more rapidly than governance.

Twenty-five years later, this lesson remains highly relevant. While another Enron is not emerging, energy trading is once again experiencing significant transformation.

When Energy Trading Became Financial

Over the past two decades, energy markets have evolved into something remarkably sophisticated. Electricity, natural gas, emissions allowances, renewable certificates and power derivatives are increasingly traded through complex financial structures. Trading algorithms execute decisions in milliseconds. Positions span multiple jurisdictions and regulatory regimes. Geopolitical developments can transform market fundamentals overnight.

Most participants view this evolution as a sign of maturity. In many respects, they are right.

Markets have become more liquid. Risk management has improved. Price discovery is more efficient. Participants have access to tools and information that previous generations of traders could scarcely imagine.

Complexity Creates Blind Spots

However, history indicates that as markets become more sophisticated, complexity often introduces blind spots, not necessarily because individuals act maliciously. More often because systems become so interconnected that risks emerge in places nobody expected.

Financial history is filled with examples. The foreign exchange market was considered one of the world’s most liquid and sophisticated financial markets before manipulation scandals emerged. LIBOR was regarded as a cornerstone of the global financial system before investigators discovered widespread benchmark manipulation.

The global financial crisis exposed risks hidden within structures that many participants believed they understood.

This pattern is consistent: the greatest vulnerabilities rarely arise from well-monitored risks, but from those that are not fully understood.

For this reason, the ongoing evolution of energy trading warrants greater attention. Modern energy markets are increasingly functioning as financial markets, not solely as commodity markets.

Traditionally, discussions around financial crime focused on banks because banks sat at the center of financial flows. Today, however, energy traders operate in environments characterized by enormous capital movements, sophisticated trading strategies, cross-border transactions and increasingly automated decision-making.

The distinction between commodity and financial trading is becoming less clear, while the geopolitical environment grows more complex.

For decades, globalization simplified many aspects of international trade. Supply chains expanded. Market access increased. Regulatory frameworks gradually converged.

Currently, many of these trends are reversing.

The Collision of Markets, Technology and Geopolitics

Sanctions regimes continue to expand. Trade restrictions are becoming more common. Energy security has returned as a central political objective. Governments are intervening more aggressively in strategic sectors. As a result, energy trading firms increasingly operate in an environment where commercial decisions can rapidly become compliance issues.

A cargo now represents more than just a shipment, and a counterparty is more than a trading partner. Transactions that seem routine today may raise sanctions concerns in the future.

The primary challenge is not inadequate risk management by firms, but the increasing complexity of these risks. As geopolitical fragmentation adds complexity, technological advancements are also accelerating the pace of change.

Few developments illustrate this better than the rise of algo trading.

Algorithms increasingly play a significant role across energy markets. They process information faster than humans, identify opportunities faster than humans and execute transactions faster than humans.

While this often improves market efficiency, it also introduces new vulnerabilities. The main challenge is that increasingly complex systems are becoming more difficult to supervise, explain, and understand.

Financial regulators have spent years investigating algorithmic trading practices in equity, foreign exchange and derivatives markets. Questions surrounding spoofing, layering and other forms of market manipulation have become familiar features of financial regulation.

Energy markets are now facing many of the same challenges. As algorithms interact, market behavior can evolve in ways that are increasingly difficult for humans to predict.

Complexity leads to opacity, which in turn creates risk. Often, these risks remain undetected until a problem arises.

Why Governance Is Struggling To Keep Up

A significant shift is that many organizations continue to address these issues as separate disciplines. Market abuse, sanctions compliance, algorithmic governance, and data governance are often managed by different departments.

Increasingly, however, these risks intersect.

A sanctions issue can quickly become a trading issue, while a data governance failure may lead to surveillance failures. Algorithmic decisions can raise market abuse concerns. Previously isolated risks are now components of a larger, increasingly interconnected system.

None of this means energy markets are inherently more dangerous than they were before. Nor does it suggest that another Enron-style event is inevitable. The comparison should not be overstated.

Today’s markets are significantly more transparent than those of the late 1990s. Regulatory oversight is stronger. Risk management frameworks are more sophisticated. Market surveillance capabilities have improved dramatically.

Twenty-Five Years After Enron

Anniversaries often provide valuable opportunities for reflection.

Twenty-five years after Enron’s collapse, energy trading is once again entering a period of extraordinary transformation. Artificial intelligence is entering trading operations. Algorithmic participation continues to expand. Carbon markets are attracting growing financial interest. Geopolitical fragmentation is reshaping global energy flows. Market structures are becoming increasingly interconnected. Innovation is accelerating.

History indicates that periods of rapid innovation are when governance is most critical. For energy companies, the key lesson is that increased market sophistication demands equally sophisticated governance.

The primary risk is not deliberate rule-breaking by firms, but rather the widespread underestimation of how closely energy trading now mirrors the financial markets that regulators have spent decades overseeing. Those markets rarely discover their vulnerabilities voluntarily. They usually discover them through a scandal. Which raises an uncomfortable possibility.

If energy trading continues to become more financial, complexity increases, and technology and geopolitics reshape markets, the next major energy trading scandal may not be a distant event.

It may already be occurring within the market today.

Asia’s Ukraine Moment

Significant developments are occurring beyond the Strait of Hormuz.

Across Asia, governments are rapidly reassessing long-standing economic assumptions. Initiatives that previously advanced slowly are now being expedited, with energy projects receiving approval in weeks rather than years.

The reason is clear: countries are recognizing their vulnerability.

Europe experienced this realization after Russia invaded Ukraine. For years, European economies depended heavily on Russian gas, assuming economic interdependence would guarantee stability. Then the war came, pipelines became weapons, and Europe discovered that energy dependence is never merely economic. It is geopolitical leverage.

Asia is now experiencing a similar awakening.

The recent crisis in the Middle East and threats to key shipping routes have compelled governments to confront a difficult reality. Much of Asia’s economic growth still relies on imported fossil fuels transported through vulnerable maritime choke points. The infrastructure supporting modern development suddenly appears fragile.

Governments have responded with notable speed.

Indonesia’s president described the crisis as a wake-up call and initiated accelerated electrification, including a major shift toward electric motorcycles. Vietnam’s largest conglomerate replaced plans for a major LNG power plant with a renewable energy project. South Korea and the Philippines announced substantial solar initiatives, while Egypt advanced major solar investments. Japan resumed discussions on restarting nuclear power plants to achieve energy self-sufficiency.

The Politics of Energy Have Changed

This moment is distinguished not only by the rapid policy response, but also by the collapse of the old political divide over energy.

For years, renewable energy was viewed as a divisive issue. Some advocated for urgent climate action, while others raised concerns about costs, subsidies, and reliability. But recent energy shocks have fundamentally altered the debate.

The argument for renewables is no longer centered solely on emissions. It is now about resilience, sovereignty, and maintaining economic stability in a world of fractured supply chains and geopolitical uncertainty.

A country can sanction oil. It can blockade gas shipments. It can weaponize pipelines. But nobody can blockade sunlight. Nobody can embargo the wind.

Once renewable infrastructure is established, the energy supply becomes extraordinarily resilient. That understanding is beginning to reshape strategic thinking around the world.

China and the Rise of the Electrostates

No country understood this earlier than China.

For years, external observers interpreted China’s renewable energy expansion mainly as climate policy. The country invested heavily in solar panels, batteries, electric vehicles, and grid infrastructure, while also maintaining high coal consumption. To many, the strategy appeared contradictory.

But Beijing was thinking beyond emissions targets.

Chinese leaders recognized that countries dominating the next energy system would possess enormous geopolitical influence. They also understood China’s vulnerabilities. The country imports vast quantities of fossil fuels, much of which passes through maritime choke points such as the Strait of Malacca, routes ultimately protected by the US Navy. For Beijing, reliance on imported energy has always represented a strategic risk.

So China spent two decades building something different.

Today, China manufactures most of the world’s solar panels and dominates battery supply chains, electric vehicle production, and the processing of critical minerals essential for the energy transition.

Some analysts now describe China as an “electrostate” — a nation whose economic and geopolitical influence increasingly rests on electrification rather than fossil fuel extraction.

That shift may define the next era of global power.

For more than a century, geopolitical influence flowed through oil fields, pipelines, shipping lanes, and petrodollars. But the emerging global order may reward something entirely different: control over electricity systems, batteries, semiconductors, renewable infrastructure, and critical minerals.

In that world, the dominant powers may no longer be petrostates. They may be electrostates.

The New Energy Trilemma

This transition, however, creates a new dilemma for the rest of the world.

Countries want to reduce dependence on Middle Eastern oil and Russian gas. Yet building renewable infrastructure often requires dependence on Chinese manufacturing.

Europe and Southeast Asia now face three competing pressures simultaneously: decarbonize rapidly, maintain affordable energy, and avoid replacing one strategic dependency with another.

There are no easy answers.

But the direction of travel is becoming increasingly clear.

Every major energy shock in modern history has accelerated alternatives. The oil crises of the 1970s drove investment into nuclear energy and efficiency. Russia’s invasion of Ukraine accelerated Europe’s renewable transition. Instability in global shipping routes may now be pushing Asia toward electrification at a scale few anticipated.

Why This Time Feels Different

What distinguishes this moment is that viable alternatives are finally ready.

Renewable technologies are no longer experimental or niche. Solar and wind can now be deployed at massive scale. Battery prices continue to decline. Electric vehicles are becoming economically competitive.

Governments are discovering that the transition no longer requires ideological justification because the technologies increasingly make financial and strategic sense on their own.

For decades, the move away from fossil fuels appeared to be a political ambition constrained by economic reality. Now economic reality itself may be driving the transition. Not because governments suddenly became greener. But because the world became more dangerous.

From Intermittency to System Design

For most of the past decade, the energy transition debate revolved around one central weakness of renewables: intermittency.

Solar generation disappeared at night. Wind output fluctuated with weather conditions. Fossil fuels remained indispensable because they could provide dispatchable electricity whenever demand required it. Regardless of how rapidly renewable capacity expanded, critics consistently returned to the same argument: renewables could never fully replace conventional baseload generation because electricity systems require reliability, not merely low-cost power during favourable weather conditions.

That argument is now becoming considerably more complicated.

According to the latest IRENA report on 24/7 Renewables, hybrid systems combining solar, wind and battery storage are increasingly capable of delivering what the industry refers to as “firm” renewable electricity — power available on a near-continuous basis rather than only when weather conditions cooperate.

Only a few years ago, this still largely belonged to the realm of future ambition.

Today, projects in Abu Dhabi and Australia are already demonstrating what this looks like in practice.

The Al Dhafra project in the UAE, for example, combines 5.2 GW of solar PV with 19 GWh of battery storage to deliver a firm 1 GW of continuous clean electricity — effectively operating like a large thermal power station.

That is a remarkable development.

Not because renewables have suddenly solved every reliability challenge overnight, but because the economics are evolving far faster than many expected.

Battery storage costs have collapsed over recent years, while solar and wind costs have continued declining simultaneously. IRENA estimates that battery storage costs fell by roughly 93% between 2010 and 2024. The Financial Times recently reported that utility-scale battery costs alone have declined by more than 50% since 2022.

That cost trajectory changes the discussion fundamentally.

For years, the debate focused primarily on renewable generation itself. Increasingly, the discussion is shifting towards the economics of flexibility, storage and system integration.

A few years ago, the central question was whether renewables could technically replace fossil generation.

In some markets, the question is already becoming whether renewables can provide electricity competitively on a 24/7 basis. That is a profoundly different conversation.

The Geography of 24/7 Renewables

At the same time, it is important not to oversimplify what is happening. 24/7 renewable electricity is not equally viable everywhere.

Abu Dhabi and Australia benefit from exceptionally favourable solar conditions, with abundant sunshine throughout the year. Southern California enjoys similar advantages. But large parts of North-West Europe, the UK and the northern United States operate under very different climatic realities. Winter solar yields in these regions remain structurally weak, making solar-only systems economically impractical for significant parts of the year.

That distinction matters because it introduces an increasingly important geopolitical dimension to the energy transition: not all regions will participate equally in the economics of 24/7 renewables.

In many ways, some of the largest long-term opportunities may ultimately emerge in currently underutilised parts of the Global South. Regions across North Africa, the Middle East, Latin America and parts of Sub-Saharan Africa possess exceptionally strong solar resources that remain largely untapped at industrial scale. Combined with declining storage costs and expanding transmission infrastructure, these regions could eventually become major exporters not only of renewable electricity, but also of energy-intensive products such as green hydrogen, ammonia and low-carbon industrial materials.

That possibility fundamentally changes how energy competitiveness may evolve over the coming decades.

Because if renewable electricity increasingly becomes cheapest and most reliable in regions with abundant natural solar and wind resources, energy-intensive industries may gradually begin clustering around those geographies.

The planned electricity interconnection between Saudi Arabia and Greece already offers a glimpse of how this future may develop. The project aims to transport renewable electricity generated in the Middle East into Europe through large-scale subsea transmission infrastructure, linking regions with abundant renewable resources directly to industrial demand centres.

The energy transition may therefore not simply reshape how electricity is produced. It may reshape where future industrial competitiveness itself is located.

Beyond Renewables Versus Fossil Fuels

This is also where the debate becomes considerably more sophisticated than the simplistic “renewables versus fossil fuels” narratives that dominated much of the last decade.

The future electricity system is unlikely to depend on standalone technologies. Increasingly, the economics improve when solar, wind, storage, interconnectors and flexible demand are treated as one integrated system rather than separate infrastructure components.

Wind generation, for example, partly offsets Europe’s winter solar weakness because output often strengthens during autumn and winter months. At system level, the complementarity between wind and solar materially reduces the scale of storage required compared with relying on either technology individually.

Transmission infrastructure may ultimately prove equally important.

Once renewable electricity becomes easier to transport geographically and increasingly easier to store, renewable infrastructure starts behaving less like intermittent generation and more like dispatchable energy systems.

China already appears to understand this dynamic exceptionally well.

The country is simultaneously scaling renewable generation, battery storage and ultra-high-voltage transmission infrastructure at extraordinary speed. In April alone, China reportedly installed almost 4 GW / 14 GWh of storage batteries while continuing to expand thousands of kilometres of HVDC transmission lines across the country.

That is no longer incremental deployment. That is system redesign.

The Final 15% Problem

Still, despite the excitement surrounding 24/7 renewables, the most difficult part of the transition remains largely unresolved.

The challenge is not achieving high renewable penetration during favourable periods. The real challenge begins in the final stretch towards very high system reliability.

One of the most important findings in the IRENA report is that costs rise sharply once systems attempt to move from high renewable availability towards near-perfect reliability. Delivering 85% renewable availability is fundamentally different from delivering 99.9% reliability during prolonged periods of low wind and low solar output — particularly during so-called “dunkelflaute” events in Europe, where weather conditions can simultaneously suppress both wind and solar generation for extended periods.

That distinction matters enormously because electricity systems are not designed around average conditions. They are designed around periods of maximum stress.

And this is where many of the more simplistic narratives surrounding battery storage still collide with economic reality.

Even in highly renewable systems, backup infrastructure, reserve capacity, balancing mechanisms and dispatchable generation remain critical components of grid reliability. Long-duration storage may eventually reduce part of this dependency, but current battery economics become increasingly challenging as reliability targets approach near-continuous supply.

Gas peaking plants illustrate the complexity particularly well. These assets are designed for rapid response rather than efficiency, allowing grids to respond quickly to short-term imbalances. But relying on them extensively during prolonged renewable shortfalls creates a difficult trade-off: the more they operate, the more they undermine part of the emissions reductions the system is attempting to achieve.

In reality, electricity systems have always depended on portfolio approaches rather than single technologies. Reliability has historically been achieved through combinations of generation diversity, reserve margins, interconnectors, dispatchable capacity, flexible demand and redundancy. The difference now is that renewables and storage are increasingly becoming economically credible participants within that reliability mix rather than depending entirely on fossil-fuel support systems.

And that may ultimately be the most important shift underway.

Germany’s Energy Storage Stress Test

The energy transition is no longer only about replacing fossil generation with renewable generation. It is increasingly about redesigning how electricity systems themselves operate.

Germany is already becoming one of Europe’s most important real-world stress tests for this transition. Not because battery systems are failing — quite the opposite — but because storage is gradually evolving from a supplementary technology into system-critical infrastructure.

As that happens, the economics become far more complex. Grid access starts becoming conditional rather than guaranteed. Congestion increasingly shapes revenues. Locational value matters more than installed megawatts. Merchant volatility begins interacting simultaneously with regulation, transmission constraints and political intervention.

For infrastructure investors, this fundamentally changes the investment case.

Battery storage increasingly resembles a risk management and optimisation business disguised as infrastructure.

At the same time, several major long-term challenges remain underdiscussed. Battery degradation is one of them. Purchasing the battery is increasingly becoming the easier part of the equation. Maintaining long-term performance, managing augmentation costs and eventually replacing ageing systems may prove significantly more financially demanding than current headline CapEx figures suggest.

The Energy Transition’s Next Phase

Still, despite all the complexity, one thing is becoming increasingly clear: the renewable energy debate is quietly changing.

For years, the discussion centred on whether renewables threatened energy security. Increasingly, the discussion is shifting towards how quickly storage, flexibility, transmission infrastructure and integrated system design can scale economically.

That is a profound shift.

Because once renewable electricity becomes increasingly dispatchable in parts of the world, the implications extend far beyond decarbonisation itself. They affect industrial competitiveness, geopolitical energy dependence, data centres, AI infrastructure, grid economics and ultimately the future structure of electricity markets themselves.

The next phase of the energy transition will likely not be defined simply by who builds the most renewable capacity. It may increasingly be defined by who best understands flexibility, optimisation, storage economics, transmission infrastructure and system integration. Because the future electricity market may no longer primarily reward generation itself. It may reward the ability to make renewable electricity reliably available exactly when it is needed most.

What This Means for Corporate Executives

For corporate executives, the implications of this shift extend far beyond energy policy or sustainability reporting.

What is emerging is not simply another phase of renewable deployment, but the gradual redesign of the economics of electricity itself.

For decades, industrial competitiveness was heavily shaped by access to stable fossil fuel supply chains, pipeline infrastructure and conventional power generation. Increasingly, future competitiveness may depend on something very different: access to low-cost renewable resources, storage capacity, transmission infrastructure and system flexibility.

That transition will not unfold evenly.

Some regions will benefit from structural advantages in solar and wind resources. Others will increasingly depend on interconnection, storage optimisation and market integration to remain competitive. Entire industrial value chains may gradually reorganise around regions capable of delivering abundant, reliable and low-cost clean electricity at scale.

For business leaders, this creates both strategic opportunities and significant risks.

Energy can no longer be treated merely as an operational cost assumption sitting in the background of corporate strategy. It is increasingly becoming a defining factor in long-term industrial competitiveness, supply-chain resilience, location decisions and capital allocation.

The companies that navigate this transition most successfully will likely not be those making the boldest net-zero announcements or simply purchasing the largest volumes of renewable power.

They will be the ones that best understand how the economics of electricity systems themselves are changing.

Because the next phase of the energy transition will not only be about generating clean power. It will increasingly be about who can secure reliable, flexible and competitively priced electricity in a world where energy systems are being fundamentally redesigned in real time.

Premium research access coming soon

Over time, these public essays will be complemented by a premium research tier focused on deeper analysis of energy systems, infrastructure economics, industrial competitiveness and geopolitical market shifts.

Founding Members will receive:

— Exclusive long-form research

— In-depth market briefings

— Complimentary access to private quarterly webinars

— Early access to future reports and sector deep dives

Public essays will remain free. Additional details on premium research access and Founding Memberships will follow soon.

For years, major companies developed climate strategies based on a future scenario that climate science is now moving away from.

This scenario, known as RCP8.5, was initially developed within scientific circles as a high-end stress test to examine outcomes under very high greenhouse gas emissions. Outside of science, it became the prevailing narrative for climate risk.

Governments used RCP8.5 to justify emergency climate policies. Regulators incorporated it into stress-testing frameworks. Banks and insurers modeled financial exposure with it. Consultants based ESG strategies on it. Corporate boards approved significant transition spending using its assumptions. Media coverage amplified its most severe projections, embedding them in public perception.

After more than a decade at the center of climate discussions, RCP8.5 is now being phased out.

This change is not due to the end of climate change or reduced risks from global warming. Rather, the scenario’s assumptions are now widely viewed as implausible by many scientists developing the next generation of climate models.

This distinction is significant, particularly for companies.

Why scientists no longer consider RCP8.5 plausible

This shift has occurred gradually. Researchers have long cautioned that RCP8.5 should not be viewed as a realistic business-as-usual scenario. It assumed rapid coal expansion, exceptionally high fossil fuel use, limited technological progress, and atmospheric CO₂ levels reaching about 1400 parts per million by century’s end.

Achieving this trajectory would have required a significant acceleration of coal use for decades, despite the global rise of renewables, technological advances, and stronger climate policies.

Researchers previously noted that reaching RCP8.5 would require constructing more than one new coal plant daily and sharply increasing global coal consumption. Even under pessimistic assumptions, many considered this pathway unrealistic.

Despite this, RCP8.5 became central to modern climate communication.

One reason is that extreme scenarios attract attention. Studies using RCP8.5 projected greater economic damages, stronger warnings, and more dramatic headlines. Organizations associated with Tom Steyer and Michael Bloomberg funded key climate-risk studies based on this scenario. This created a feedback loop among scientific modeling, political urgency, media coverage, and institutional momentum.

Over time, the line between what was possible and what was probable became less clear.

The shift in Climate Modeling

The scientific community is now reconsidering its approach. The new climate scenario framework from the Coupled Model Intercomparison Project, which supports future Intergovernmental Panel on Climate Change assessments, no longer includes SSP5-8.5, the successor to RCP8.5, as a core pathway. This is because, given current technology, renewable energy costs, policy trends, and emissions data, the scenario is no longer seen as plausible.

This represents a significant change, but it does not signal that risks have been eliminated. Scientists involved in retiring RCP8.5 continue to warn that warming above 3 degrees Celsius remains possible and dangerous. They argue that even 3 to 3.5 degrees of warming would carry severe consequences and stress that physical climate risks remain highly material. The removal of the worst-case scenario does not invalidate climate risk. It recalibrates it.

Why companies must reassess Carbon Management

For companies, this shift requires a necessary and challenging reassessment.

Many organizations integrated RCP8.5 assumptions into risk management, transition planning, carbon pricing, infrastructure assessments, and long-term capital strategies. In many boardrooms, the scenario shifted from an exploratory stress test to an implicit baseline for the global economy’s future.

This is important because scenarios influence capital flows. They determine which assets receive financing, which industries attract investment, which technologies gain subsidies, and which business models are considered viable long term. Strategic assumptions must change with them.

This does not mean companies should abandon climate targets or ignore transition risks. In fact, retiring RCP8.5 requires more sophisticated climate governance.

The issue with previous climate strategies was not modeling extreme risks; stress-testing low-probability, high-impact events is valid. The problem was allowing an extreme tail-risk scenario to become the main narrative for long-term planning.

That distinction is now becoming increasingly important for investors, auditors, regulators, and boards.

Climate Scenario Risk becomes a Business Risk

A growing number of financial institutions are beginning to recognize that climate scenarios themselves can create strategic distortions. If transition pathways are modeled around implausibly extreme assumptions, companies may overestimate regulatory escalation, underestimate the persistence of fossil fuels, misprice industrial competitiveness, or allocate capital inefficiently. At the same time, firms that swing too far in the opposite direction and dismiss climate risk altogether may find themselves dangerously exposed to physical disruptions, tightening regulation, or technological disruption.

The challenge now is balance.

The new generation of climate scenarios reflects a more complex reality than the simplistic binaries that dominated much of the past decade. The future is unlikely to be either total climate catastrophe or rapid net-zero utopia. Instead, it will probably involve a messy combination of warming, adaptation, technological progress, geopolitical tension, uneven policy implementation, and prolonged coexistence between fossil and renewable energy systems.

Growing gap between Climate Ambition and Economic Reality

That reality is politically uncomfortable because it exposes the widening gap between climate ambition and economic reality.

For thirty years, international climate conferences have promised rapid decarbonization while global fossil fuel consumption continued rising. Emerging economies continue prioritizing industrialization, energy security, and economic growth. The idea that the entire global economy would fully eliminate fossil fuels within a few decades increasingly appears economically and geopolitically improbable.

The simultaneous removal of both the most catastrophic warming scenario and the most optimistic 1.5-degree pathway reveals how deeply climate modeling and political communication have become intertwined. Had the most extreme scenario been abandoned years ago on scientific grounds alone, average projected warming across official pathways would have fallen substantially, potentially weakening political urgency around the energy transition. By removing both extremes at the same time, institutional narratives remain relatively stable.

Whether intentional or not, the effect is politically convenient.

The Real Lesson for Business Leaders

For companies, however, the political debate matters less than the strategic implications. The real lesson of RCP8.5 is not that climate science failed. Nor is it that climate risks were invented. The real lesson is that scenario selection itself has become a material governance issue.

Boards can no longer treat climate scenarios as neutral technical exercises delegated entirely to consultants or sustainability teams. They are strategic assumptions with enormous implications for capital allocation, risk exposure, regulatory positioning, and long-term competitiveness.

The companies that navigate the next decade most successfully will not be those that abandon climate strategy. They will be the ones capable of distinguishing between plausible futures, exploratory stress tests, political narratives, and economically grounded transition pathways.

Because the era of simplistic climate storytelling is ending.

And for business leaders, that may be the most important transition of all.

Hi,

TTF’s extended trading hours are quietly changing the balance of power in global gas markets. For years, Asian, Middle Eastern, African and North American gas firms had to react to a market running on a European clock. That advantage is disappearing fast.

Global LNG players can now engage with TTF pricing in real time:

• managing TTF–JKM exposure continuously

• reacting faster to LNG flows and volatility

• and influencing price formation directly

That changes how trading firms compete. The edge is shifting from geography to speed, coordination, and global positioning. Most market participants are still adapting.

I’m hosting a live webinar on what this means in practice for traders, analysts, and gas market professionals across regions.

As a subscriber, you can join at a special rate of €350.

👉 If you’d like to secure your place, just reply or email me at walet@maycroft.com and I’ll send you the details.

Places are limited to keep the session practical and interactive.

Best regards

Kasper Walet

A Market built on uncertainty, but not structured for it

For a market built on long-term outcomes, carbon markets still struggle with something surprisingly fundamental. It is not a lack of demand, nor is it an absence of capital willing to engage. Even risk, which is often cited as the central issue, is not in itself the limiting factor. What continues to hold the market back is how that risk is framed, structured, and ultimately embedded into contracts.

Carbon projects, particularly those based on nature, are inherently uncertain. They unfold over long time horizons, depend on environmental conditions, and are exposed to evolving regulatory frameworks and methodologies. This uncertainty is not a flaw in the system; it is an intrinsic part of it. Investors and buyers understand that. They are accustomed to working with uncertainty, and in many markets, they actively seek it out where it can be properly understood and priced.

When uncertainty is simplified too far

Problems start when uncertainty is simplified so much that it no longer matches how projects really work. Agreements are often based on expectations that assume more predictability than is realistic. Timelines may be too optimistic, obligations may not match real operations, and it is often unclear how changes from the plan will be managed.

In a market where these changes are normal, this leads to a basic disconnect.
At its heart, the issue is not too much risk, but risk that is not clearly defined. If risk cannot be described clearly, it is hard to price. This is what makes investors cautious.

Gap between projects and contracts

This disconnect is made worse by a bigger structural problem. Carbon projects are still changing in how they are designed, carried out, and monitored, but contracts are often written as if all uncertainties are already solved. This creates a gap between how projects work and how deals are written.

In this context, a contract is not just a legal tool; it shows how a project is expected to perform. When this does not match reality, trust in the agreement, and in the project itself, starts to fade.

Deals are structured to close, not always to deliver

There is also a practical side to this. Deals need to get done, so contracts are often written to make agreement easier instead of fully reflecting the real complexity. Risk may seem balanced, assumptions are made to fit timelines, and some uncertainties are not clearly defined.

In the short term, this approach helps transactions go through. But over time, it causes problems, especially when projects start and the gap between what was agreed and what actually happens becomes clear.

What Capital actually needs

What investors really need is not to remove uncertainty, but to have clear ways to manage it. They do not expect fixed results; they want structures that show how projects will act in different situations. This means clear responsibility, realistic timelines, and clear plans for dealing with delays or problems.

In other words, contracts should not try to remove uncertainty, but should make it understandable.

A market that is growing faster than yts structures

This issue matters more as the market grows. Buyers are getting more experienced, with better buying processes and higher expectations for quality and delivery. Moving from one-time purchases to longer partnerships means agreements also need to change.

Contracts are no longer just about assigning responsibility. They are now the main way to define how delivery, teamwork, and risk-sharing will work.

Why this matters for growth

This issue affects more than just single deals. Many projects that will drive future growth, especially large nature-based solutions, need big upfront investments and take a long time to complete. These projects cannot get large-scale funding if the contracts do not match how they really work.

At that stage, the main barrier is not whether the project is possible, but whether its structure gives investors confidence.

The Real Takeaway

The real challenge is not to make things simpler, but to deal with complexity more openly. Contracts should change from just helping transactions happen to clearly describing how projects should perform over time. This is not about adding more rules, but about making sure expectations, risk, and delivery match how projects actually work.
In the end, carbon markets are not held back by a lack of ambition or interest. The real problem is the gap between how projects work and how deals are set up.

Contracts are where this gap shows up.

Until contracts start to match reality more closely, growing the market will stay harder than it should be.

For many years, energy deals followed a familiar pattern: buyers sought supply security, sellers wanted predictable revenue, and pricing structures, though complex, were generally understood. Even in volatile markets, alignment was typically sufficient to close deals.

This balance is now shifting

Across power, gas, hydrogen, and broader energy transition markets, deals are not disappearing, but they are becoming more difficult to close. Negotiations take longer, positions are more entrenched, and agreements that were effective a few years ago are no longer sufficient.

This is not due to disagreement on market direction, but rather a lack of consensus on how risk should be priced.

More variables, less certainty

One of the clearest changes is the growing number of variables in any given deal.

Where pricing was once largely driven by supply, demand, and a handful of indexation mechanisms, it is now shaped by a much wider set of factors. Carbon pricing is becoming embedded in cost structures. Policy frameworks are evolving in unpredictable ways. Market volatility, particularly in power and gas, has increased both in frequency and intensity.

Recent market disruptions have reinforced that shift.

Sharp price spikes, liquidity squeezes, and periods where traditional hedging relationships broke down have left a lasting impression on market participants. Even where conditions have stabilized, the memory of how quickly markets can move and how difficult it can be to manage exposure in those moments has changed behavior.

The events in European gas markets in 2022 show this clearly. Prices didn’t just go up; they changed in ways that most models and risk systems couldn’t handle. Scenarios once thought extreme became real in just weeks. For many, that experience changed how they look at risk.

Each of these factors can be managed on its own. But together, they create uncertainty that’s much harder to plan for.

The result isn’t just more complicated pricing. The bigger question is: who is willing to take on which parts of that uncertainty?

Buyers are more cautious

On the demand side, buyers are getting more selective.

Long-term commitments used to be the foundation of many energy deals, but now people see them differently. It’s harder to lock in prices for years when future costs, especially carbon, are unclear. Even when buyers want to commit, they focus more on flexibility, options, and protection against losses.

This change isn’t just theory—it comes from real experience. Recent market shocks have shown how fast risks can grow and how hard it is to get out of deals once you’re committed.

That changes the dynamic of negotiations.

Buyers are no longer just looking for supply. They are looking for structures that limit exposure — and those structures are not always compatible with what sellers need.

Sellers are under pressure to lock in Value

At the same time, sellers face a different set of constraints.

Projects, particularly in newer segments such as hydrogen or low-carbon fuels, often depend on long-term revenue certainty to move forward. Without visibility on future cash flows, reaching a final investment decision becomes difficult. That typically requires contracts that provide a degree of price stability.

But price stability has become harder to guarantee. Input costs are less predictable. Policy support mechanisms are still evolving. And the range of possible future price outcomes is wider than it used to be. In that environment, sellers are less willing to absorb risk without compensation.

This creates a gap. Buyers want flexibility. Sellers need certainty.

Closing that gap is where deals are increasingly getting stuck.

Mismatch is structural, not temporary

It would be easy to see this as a cyclical issue ,a function of recent volatility that will settle over time.

But the underlying drivers suggest something more structural.

Energy markets are becoming more interconnected, more policy-driven, and more exposed to factors outside traditional supply-and-demand dynamics. Carbon pricing, in particular, introduces a material, inherently uncertain cost component. As mechanisms like CBAM begin to attach carbon costs directly to trade, that uncertainty becomes embedded not just in production, but in cross-border transactions.

This does not just make deals more complex. It changes the way risk is distributed across the value chain. And that redistribution is unlikely to reverse.

Negotiation is becoming more about structure than price

One of the less visible shifts is the evolution of negotiations themselves.

Historically, price was often the central point of discussion. Today, structure matters just as much, if not more. How pricing adjusts over time, how risks are shared, how flexibility is built into agreements: these elements are becoming central to whether a deal can be agreed at all.

Two parties may broadly agree on the market outlook and still fail to reach an agreement if they cannot align on how to handle uncertainty.

That is where many negotiations now stall.

Not because the economics are fundamentally misaligned, but because the structure does not allow both sides to manage their exposure in a way that is acceptable.

Deals are not disappearing. They are being repriced

Despite these challenges, deals are still being done. But they are being done differently.

In some cases, this means shorter contract durations. In others, more complex pricing mechanisms or greater reliance on indexation. In some markets, it leads to delays, as participants wait for more clarity before committing. In others, it accelerates innovation in contract structuring.

What is consistent across all of these is that the underlying economics are being reassessed. Deals are no longer just about agreeing on a price. They are about agreeing on how that price will evolve under uncertainty.

The real takeaway

Energy deals are not getting harder to close because markets are unclear. They are getting harder to close because the range of possible outcomes has widened and because counterparties are struggling to agree on how to share that risk.

That is not a temporary challenge. It reflects how energy markets themselves are changing. The real question is no longer whether there is demand or supply. It is whether both sides can structure a deal that still works when the assumptions behind it begin to move.

Because in today’s market, the difficulty is not finding a counterparty. It is agreeing on who carries the risk once the deal is signed. And increasingly, that question is not resolved in principle.

It is resolved in detail , in how contracts are structured, how pricing adjusts over time, and how exposure is allocated between counterparties.

That is where deals are now won or lost. And it is where the next layer of complexity and opportunity sits.

The expansion of TTF trading hours looks like a routine market upgrade. More screen time, more flexibility, better alignment,the kind of change that usually gets filed under operational improvement.But this one runs deeper.

In any market, the clock is not just a schedule. It determines when liquidity gathers, when decisions get made, and who has the advantage of acting first. For a long time, even as European gas became tightly linked to global LNG flows, pricing still revolved around a distinctly European rhythm. Activity elsewhere in the world adjusted around that center of gravity.

That structure is now dissolving. By extending its trading hours, TTF is shifting towards a system where prices aren’t determined by just one region being open. It’s becoming a non-stop process that happens across different time zones, without a specific starting point. What was once a series of reactions from different regions is now starting to look like one long, continuous conversation.

A global conversation in real time

This change means that price formation is no longer limited to a single area, but is instead shaped by a constant flow of information and activity from around the world. As a result, the traditional sequence of regional market openings is giving way to a more fluid and dynamic process, where buyers and sellers can interact and negotiate prices at any time.

Even now, the activity in TTF doesn’t just follow a European schedule. When the US teams start their day, the trading volumes and price changes start to happen faster—a clear sign that the influence on pricing is becoming more global, and not just limited to what the structure would suggest.

Empowerment of global traders

That shift matters because it changes who can influence outcomes. People trading outside of Europe, especially those dealing with LNG across many areas, are no longer limited by time. They can change their positions, reduce risk, and react to price changes as they happen, instead of reacting after it’s too late.

As they become more able to respond quickly, they also become more able to influence the market. This means they can make decisions and take actions at any time, giving them more control over their investments and allowing them to stay ahead of the game. With the freedom to act whenever they want, they can make the most of new opportunities and protect themselves from potential losses.

Impacts on TTF-JKM arbitrage

This is where the impact becomes tangible. As trading hours between Europe and Asia begin to overlap more meaningfully, the relationship between TTF and JKM stops being something that is traded in fragments. It becomes something that can be managed continuously.

For traders running cross-benchmark positions, that changes the game. The difference in price between TTF and JKM can now be seen in real time, without needing to account for time gaps between regions. This means that positions can be adjusted quickly as the relative value of these prices changes—whether that’s due to ships moving LNG, changes in shipping costs, updates on the weather, or shifts in demand in different areas. That reduces execution friction and increases competition.

Efficiency over geography

When everyone can act simultaneously, opportunities for profit don’t last long. What was once a chance for people in the right time zones to make a profit becomes a faster and more efficient trade, where being quick and doing things well matters more than being in the right place.

At the same time, it makes a new approach possible. Instead of treating TTF and JKM as two markets that periodically reconnect, traders can increasingly manage them as part of a single, integrated system. Exposure can be shifted dynamically between basins, rather than rebalanced after the fact. Hedging becomes more precise, but also more active.

The realities of Liquidity and Volatility

It would be easy to assume that longer hours automatically translate into deeper markets. In reality, liquidity doesn’t expand so neatly. It tends to cluster, even in systems that operate almost around the clock. Other energy benchmarks show that most meaningful price formation still concentrates in specific periods, regardless of how long the market remains open. Extending the day may spread participation, but it doesn’t guarantee that depth increases uniformly.

You can really see the difference in how prices change throughout the day. When there are fewer interruptions, the market can adjust to new information more slowly. Instead of big price swings when the market opens, the reactions happen over a longer time. This creates a different type of volatility—it’s not about sudden spikes, but more about the market constantly adjusting.

The rise of automated trading

There’s another level to consider. Not all the extra activity is going to come from people making trades. When things are slower, a bigger part of the transactions will be done by automated systems. These systems will be following set plans, managing risks, and reacting right away to new information. This means that some parts of the trading day might become really fast and more robotic, especially when there aren’t as many people buying and selling.

A new global benchmark

When you look at all these changes together, you can see that something bigger is happening. The TTF is not just a local standard that people from around the world pay attention to anymore. It’s becoming a benchmark that shows how different regions interact with each other in real time.

The evolution of the market creates new opportunities for more people to get involved and participate actively. Companies that work across different continents can now more easily include European gas in their business plans, which helps them manage risks and make strategic decisions across different regions. This also affects other related markets, as the relationship between TTF and JKM prices now involves currency exchange rates, adding a new level of complexity and potential for profit.

Conclusion: A Decentralized Future

The overall effect is subtle but significant. By extending trading hours, Europe has reduced the influence of its own time zone over price formation. The price of gas in Europe is going to be determined by a lot of different decisions made all over the world. It’s not going to happen all at once, or just in one place. Instead, it’s going to be the result of many people interacting with each other over time, and they’re not all waiting for the same market to start trading.

This means that the value of gas will be constantly changing, as people make new decisions and react to what’s happening in the market. It’s a complex process, but basically, the price of gas will be shaped by a continuous flow of decisions made by people all around the globe.

👉 If this matters to your work

I’ll be running 2 seperate live online webinars on 27-28 May suited for each time zone, exploring what this shift means in practice for:

• TTF–JKM trading

• LNG arbitrage

• liquidity and volatility

• and trading strategy

Read brochure

From Policy to Pricing Shock

For years, the European Union’s Carbon Border Adjustment Mechanism was treated as a future policy . Something to analyze, debate, and gradually prepare for. That framing is now outdated.

With the start of the pricing phase, CBAM has moved from policy into the market. At the same time, free allowances under the EU Emissions Trading System are being phased out, exposing European producers more directly to carbon costs. Taken together, these changes do more than adjust incentives.

They reprice trade.

This is not a regulatory shift. It is a pricing shock that will move through supply chains, contracts, and investment decisions far faster than most expect.

A Level Playing Field that isn’t Level

At its core, CBAM links imports to the EU carbon price. Products such as steel, aluminium, fertilizers, cement, hydrogen and electricity will increasingly reflect their emissions intensity in their cost structure. On paper, this creates a level playing field between domestic and imported goods.

In reality, it creates differentiation. Because while the mechanism is uniform, the starting point is not. Producers operate with very different emissions profiles, energy costs, and regulatory environments. Some exporters already face carbon pricing and can partially offset CBAM exposure. Others do not.

The result is not convergence. It is divergence.

Real adjustment will happen outside Europe

The most important effects of CBAM will not be felt in Brussels. They will be felt in production decisions across Asia, the Middle East and beyond. For electricity in places like the West Balkans.

However, adaptation will not always mean full decarbonization.

In practice, many producers are likely to respond more selectively. We may see the emergence of parallel production strategies, where cleaner, more efficient facilities are developed specifically to serve European markets, while older, higher-emission plants continue to supply regions without carbon constraints. From a global emissions perspective, that is a redistribution rather than a reduction.

From a commercial perspective, however, it is entirely rational. It allows exporters to preserve market access without fully restructuring their asset base and to optimize margins across different regions.

That is how markets tend to adapt when faced with uneven regulation.

CBAM will be fought in contracts, not policy

The real impact of CBAM will not be determined by how it is written, but by how it is negotiated.

Carbon costs introduce a new variable into pricing. One that is both material and uncertain. The EU carbon price moves, and the policy itself is still evolving. That uncertainty has to be allocated somewhere, and it will be absorbed through contracts.

Buyers will try to limit their exposure. Sellers will try to pass it through. And in many cases, exporters will have more leverage than expected.

Where supply is tight, or alternatives are limited, exporters may succeed in pushing the full carbon cost onto European importers. In that scenario, CBAM does not function as a penalty on foreign producers. It becomes a cost that is ultimately borne within Europe.

This is the part that is often overlooked. CBAM does not determine who pays. Markets do.

European industry faces a more complex reality

CBAM is often framed as a mechanism to protect European industry. That interpretation is incomplete.

While it reduces the advantage of high-emission imports, it also removes part of the protection European producers previously enjoyed through free allowances. This increases direct exposure to carbon pricing at the same time as global competition is being reshaped.

The result is not a simple gain in competitiveness. It is a more complex environment in which European firms must manage higher costs while competing with producers that may be adapting in more flexible ways.

Markets will move before policy settles

One of the defining features of markets is that they do not wait for regulatory clarity.

As CBAM costs become more visible, sourcing decisions will begin to shift. These changes will not necessarily be abrupt, but they will accumulate. Contracts will be renegotiated, supply chains adjusted, and pricing structures redefined.

In sectors such as steel, aluminium, fertilizers and cement, even relatively small cost differences can alter competitive positioning. Over time, these incremental adjustments can lead to more structural changes in trade flows. Once those shifts begin, they tend to reinforce themselves.

The real takeaway

CBAM is not just another layer of climate policy. It is a mechanism that embeds carbon directly into pricing and in doing so, changes how power is distributed in global trade.

The outcome will not be decided by regulation alone. It will depend on who can adapt production, who can structure contracts, and who ultimately has the leverage to pass costs through the system.

Because CBAM is not just about carbon. It is about pricing power.