At its 50th annual general meeting on 27 August, NTPC’s chairman and managing director, Gurdeep Singh, told shareholders the company was raising its ambitions considerably. NTPC now targets 149 GW of installed capacity by 2032, up from around 91 GW today, and 244 GW by 2037. Backing this is a cumulative capital expenditure plan of roughly ₹16.86 lakh crore (US$176.4 billion) spread across thermal, hydro, pumped storage, renewables, battery storage, coal mining and nuclear power, according to a media report.

The composition matters more than the headline number. Of the 149GW planned by 2032, 60GW is meant to be renewable. NTPC is also positioning itself as India’s largest single contributor to the country’s nuclear ambitions, aiming for around 30GW towards the national target of 100GW by 2047, alongside its 2.8GW Mahi Banswara project already under construction in Rajasthan and 34 additional sites under evaluation.

👉 Read the full story: https://www.indoen.com/news/ntpcs-us1764-billion-roadmap-shows-indias-power-money-is-outrunning-its-r

Texas is facing an unusual energy-system paradox.

On one side, ERCOT is integrating large volumes of wind and solar generation while transmission constraints continue to produce significant curtailment in particular regions and at particular resources.

On the other, hyperscalers and other large industrial loads are creating an entirely new electricity-demand challenge. Data centers are no longer a marginal issue for U.S. grid planning; Energy Central itself has recently highlighted the implications of rapidly growing data-center demand for resource adequacy and grid infrastructure.

This raises a different question from the conventional debate about adding generation:

Before building everything from scratch to serve new loads, how much better could we utilize energy infrastructure that already exists?

That question became the starting point for my recently published system and site assessment of ERCOT.

Curtailment Is Large — But the Statewide Number Is Not the Most Important Number

An S&P Global Market Intelligence analysis published on May 5, 2026 by Dan Thompson and Tony Lenoir examined renewable curtailment as a potential surplus-energy opportunity for Texas data centers.

That observation prompted me to investigate the issue at system, resource and site level.

The evaluated Modo/ERCOT dataset indicates approximately 8.34 TWh of wind and solar curtailment in 2024, consisting of roughly 5.26 TWh of wind and 3.08 TWh of solar generation. An S&P Global estimate for 2025 arrived at 9.8 TWh using a different methodology. The figures therefore should not simply be merged, but both indicate that the issue is material.

Yet the statewide TWh figure is not the most important result.

Curtailment is not a virtual reservoir containing 8 or 10 TWh of electricity that can be accessed anywhere in Texas. It occurs at particular Resource Nodes, during particular dispatch intervals and behind particular transmission constraints.

In the evaluated 2024 dataset, the West, South, North and Far West weather zones accounted for approximately 89.3% of identified curtailment.

For project development, the relevant question therefore changes from:

How much renewable electricity is curtailed in ERCOT?

to:

Where, when, how often and at what power level is generation repeatedly unable to reach the market?

That is a much more useful engineering question.

From TWh to MW: The Los Vientos Example

Resource-level analysis illustrates the difference.

The most-curtailed wind resource in the evaluated 2024 dataset, LV2_LV2 / Los Vientos, recorded approximately 196.45 GWh of curtailed energy across 4,430 affected hours.

Across those affected hours, this corresponds to approximately 44.35 MW of average unavailable injection.

This does not mean that 44 MW was continuously available throughout the year. Curtailment is variable, and no flexible load should be dimensioned simply by dividing annual curtailed energy by affected hours.

Nevertheless, the result provides a useful first engineering boundary.

It suggests that a modular flexible load in the range of 40–50 MW deserves detailed investigation at such a location. The actual utilization factor would have to be established through five-minute ERCOT data, including HSL, Base Point, actual injection, prices and binding constraints.

This is where “curtailment” stops being merely a statistic and begins to become a potential infrastructure resource.

The Utilization Gap May Be Larger Than Reported Curtailment

There is another issue that deserves more attention.

Public curtailment statistics do not necessarily represent the entire difference between meteorologically available renewable generation and electricity ultimately injected into the grid.

For ERCOT, several quantities must be distinguished:

Meteorological potential → High Sustainable Limit (HSL) → Base Point → actual injection

The difference between HSL and Base Point can indicate visible dispatch reduction. But the difference between meteorological potential and HSL is more difficult to interpret.

A low HSL may result from technical unavailability, operating limitations, conservative declaration or preventive non-activation. Without plant-status and meteorological information, those causes cannot be uniquely separated.

For this reason, my analysis deliberately does not classify every missing MWh as curtailment. A robust reconstruction requires meteorological expected output, HSL, Base Point and actual injection at high temporal resolution.

Germany provides an interesting illustration of why this distinction matters.

During observations of clear summer days in 2026, realized German PV output around midday sometimes represented only about 40% of installed PV capacity.

That observation alone does not prove that the remaining capacity was deliberately switched off. Module orientation, inverter sizing, temperature, regional conditions, behind-the-meter consumption, maintenance and other technical factors can contribute to the difference.

But a persistent gap under favorable irradiation raises an important system question:

How much technically available renewable generation never appears in conventional curtailment statistics because its limitation occurs before measured grid injection?

This distinction matters far beyond Germany or Texas.

If renewable capacity is expanding faster than the infrastructure capable of transporting or productively consuming its output, installed GW increasingly become an incomplete measure of system performance.

What If the Load Goes to the Constraint?

The conventional response to grid congestion is transmission expansion.

Transmission remains essential. But it is not the only possible response.

If a flexible industrial load can be located electrically upstream of a recurring binding constraint, it may consume energy that would otherwise be curtailed before that energy attempts to cross the constrained interface.

This does not mean that flexible loads can generally replace transmission.

They cannot.

Any claim of avoided or deferred network investment requires a nodal counterfactual demonstrating that the load is located on the correct side of the relevant constraint, operates during the relevant intervals and can reduce consumption when system conditions require it.

But where those conditions are satisfied, flexible load becomes more than demand.

It becomes a grid-utilization instrument.

From Flexible Load to Energy Logistics

This is the problem for which I examined NRG4NOW.

NRG4NOW is not intended as a single storage technology. It is an open, standardized energy-logistics architecture connecting energy sources, storage modules, conversion equipment, transportation, grid interfaces, energy hubs, module identity and adaptive orchestration.

Compression and the Tube Storage Tank Module (TSTM) are application modules within that larger architecture.

The basic concept is to treat energy partly as a logistics flow.

A compressor can act as a directly controllable electrical load behind a constraint. Electrical energy is converted into a transportable molecular-energy inventory. That inventory can then be stored locally or moved using pipelines, road, rail or other logistics infrastructure.

At the destination, it can support different conversion pathways depending on the application.

The significance of this architecture is not that it “stores electricity” in the conventional battery sense.

It is that it provides another possible route around a spatial and temporal mismatch:

Instead of requiring every MWh to cross the electrical bottleneck at the instant it is generated, part of the energy can leave the constrained area through another infrastructure system.

That proposition is what now needs to be tested economically and operationally.

BESS and Molecular Storage Address Different Time Scales

This should not be interpreted as an argument against battery energy storage.

BESS is exceptionally valuable for fast electrical response, frequency services, ramp management and short-duration energy shifting.

The ERCOT assessment instead treats different technologies as complementary layers.

A flywheel can address milliseconds to minutes. Batteries can address seconds to hours. Compressors can provide productive controllable load. Molecular inventory can address much longer periods and can also be physically transported.

That distinction becomes especially relevant for data centers.

A hyperscale data center is not a two-hour load. It requires continuous energy availability.

The system problem therefore extends beyond moving an afternoon renewable peak several hours into the evening. It involves connecting variable generation with continuous demand across different locations and much longer time horizons.

Data Centers Add Another Interesting Dimension: Cooling

Pressure-based energy logistics may also provide another useful service.

When high-pressure gas is expanded, cooling or expansion work can potentially be recovered. My ERCOT assessment therefore identifies data centers, cold storage and gas-processing facilities among possible users of this co-product.

This is not free energy. Any project must account for the complete thermodynamic balance, including pressure, temperature, mass flow and auxiliary electricity.

Nevertheless, it changes the economic question.

The value of an energy-logistics system may not consist of a single storage arbitrage spread. Potential revenue or avoided-cost streams can include curtailment-energy utilization, compression services, storage capacity, energy logistics, electricity generation at destination, cooling, expansion work and resilience.

A viable project would likely require several of these streams rather than depending on one.

Brownfields May Be Part of the Answer

Location remains decisive.

My preliminary screening examined five Texas brownfield sites: Rio Pecos, Oklaunion, Coleto Creek, San Miguel and Sandow.

The purpose was not to declare a winning site. It was to determine whether existing industrial locations could offer combinations of grid infrastructure, gas infrastructure, transportation access, land and permitting history that justify more detailed investigation.

Among them, Rio Pecos emerged as a particularly interesting candidate for a capture-oriented pilot because of its location in West/Far West Texas, historical electrical infrastructure and proximity to pipelines.

But significant questions remain: ownership, actual pipeline pressure and available capacity, electrical interconnection conditions, environmental status and the cost of reusing existing infrastructure all require verification.

A brownfield is valuable only if the infrastructure that matters can actually be reused.

The Next Step Is Pre-FEED, Not Construction

The principal conclusion of the assessment is deliberately restrained:

Go to Pre-FEED — not Go to Construction.

Before an investment decision, the concept requires at least:

• 24–36 months of five-minute ERCOT data for candidate Resource Nodes;

• identification of binding constraints and shift factors;

• compressor vendor performance curves and quotations;

• verified pipeline pressure, diameter and available capacity;

• certified engineering and installed-cost estimates for the storage system;

• grid and interconnection studies;

• brownfield environmental and title due diligence; and

• commercial term sheets with generators, offtakers or data-center operators.

The proposed Pre-FEED therefore follows two tracks: direct coupling to a highly curtailed renewable resource, and development of a brownfield energy hub.

A Different Question for the Data-Center Boom

Texas will need new generation. It will need transmission. It will need storage. And it will need flexible demand.

These are not mutually exclusive choices.

But as electricity demand from hyperscalers grows, another metric deserves greater attention alongside installed GW:

utilization of the generation and infrastructure that already exist.

If renewable generation is repeatedly available in the wrong place at the wrong time, simply adding more generation does not by itself solve the underlying architecture problem.

The more interesting question may therefore be:

Can we move the demand to the energy — and, where necessary, move the energy without moving the electricity?

That is the hypothesis the ERCOT assessment is intended to test.

The complete 18-page system and site assessment, including methodology, resource-level curtailment data, technology comparison, preliminary economics, brownfield screening, risk matrix and proposed pilot-development plan, is publicly available on Zenodo:

Ryszard Dzikowski — The Invisible Gap in the Texas Power System: Economic and Site Assessment
Full report — DOI 10.5281/zenodo.22310345

"These count among the changes that Florida education officials asked science textbook publishers to make in the summer of 2024 that either watered down or eliminated content about the climate crisis, an investigation by WUSF + The Hechinger Report has found."

"Not changes that were required to bring the textbooks in line with the [existing] state science standards," said Glenn Branch, deputy director of the National Center for Science Education, a nonprofit that tracks how climate is taught in classrooms across the country.

"These revelations come as the state is quietly updating its science standards for the first time since 2008." Academic standards outline what knowledge + skills a student should master in each grade + subject; the existing science standards mandate that students be taught about human-caused climate change in several high school electives—including earth science, marine science, + environmental science—and leaves room for the subject to arise in several other classes.

"But it’s unclear whether Florida’s updated science standards will include education about climate change, which has already shaped the lives of many of the state’s 3 million students. The reasons are obvious, but state education officials did not respond to repeated questions on the topic.

Governor Ron DeSantis officially removed references to climate change from state statutes in May 2024. Morally, censorship ranks right up there with book burning. In a burning world, no less. These officials ought to end up in a certain level in Hades.

By Kennedy Maize

One of the largest proposed data center developments in the U.S. — Project Jupiter, named after the largest planet in the solar system — is causing some turmoil in New Mexico, including a ruling by the state’s high court halting review of an air quality permit for the project in Doña Ana County on the Mexican border. The county is the second most populated in the Land of Enchantment, with Las Cruces the county seat (population 118,112).

Some local residents have protested the siting of the data center, citing air quality and water consumption as reasons to oppose the project. A spokesman for Gov. Michelle Lujan Grishham has said she “takes seriously the concerns Doña Ana County residents have raised about Project Jupiter — including on air quality and groundwater use — and expects any data center operating in New Mexico to meet the state’s rigorous environmental standards and use water responsibly.” 

A partnership of Oracle and Open AI, Project Jupiter is a data center campus, with four possible centers. The first, with on-site generation, is a 2.45-GW project powered by Bloom Energy fuel cells, a change from the original plan to use diesels and gas combustion turbines. Oracle says the change will reduce water use, a key issue, and eliminate most air emissions of oxides of nitrogen, as fuel cells do not generate electricity by burning fuel. Using methane, they produce CO2 and trace amounts of NOx.

The state court ruling on Aug. 23 delayed an air quality hearing set for Sept. 14 and ordered the Office of the State Engineer to put a hold on a permit allowing water from a specific local well to be used for the data center’s construction. Construction on the project continues. Oracle says it hopes to have the project in service in the first half of next year.

Opposition to the project last fall focused on the use of gas-fired combustion turbines. Oracle in April announced that they were switching to fuel cells. In a news release, Oracle said, “This updated power design will replace Project Jupiter’s previously planned gas turbines and diesel generators and consolidate the facility into one single microgrid campus.

“Fuel cells generate electricity without combustion, meaning the Bloom microgrid is highly efficient with low emissions and water use. Compared to its previously planned gas turbines, Project Jupiter with the Bloom microgrid will reduce NOₓ emissions by approximately 92% and will use a negligible amount of water.” 

The fuel cells will still use natural gas in their electrochemical process, but not in the quantities needed for combustion, around 15-25% less gas than combustion turbines of the same electric output. Project Jupiter will also use closed-cycle cooling, reducing water needed to cool the banks of computers processing the flood of data that flows in and out of the centers.

A gas pipeline issue is also on the table. Source NM news service reported, “In a petition to the state Supreme Court, the Santa Fe-based clean energy group New Energy Economy argued that such a hearing could be premature because the pipeline intended to feed the fuel cell system has not yet gained the necessary approval to be built. In fact, New Mexico Commissioner of Public Lands Stephanie Garcia Richard has twice shot down its developers request to build a portion of it on state trust land, and recent federal regulatory filings show it may not come online until early next year.”

The local concerns about the project have drawn the attention of the region’s representative in Congress. Democratic Rep. Melanie Stansbury raised water consumption issues with the state engineer, who mostly found no problems with the purchase of an existing water right to supply water used during construction.

State Engineer Elizabeth Anderson responded that last October, the owner of the water right filed an application for “an emergency replacement well” and a state engineer “visited the well site, confirmed that the well was in use but was suffering from casing failure, authorized drilling the replacement well and directed the owner to publish notice of the application pursuant to OSE’s standard notice procedures.” The notice produced “more than 30 protests.”

That prompted Stansbury to post on Bluesky last Wednesday that the protests “have not yet been adjudicated,” and “no formal hearings appear to have been held regarding these protests,” and “no other water permits have been filed to address the long-term operational needs of the project, and no clear and consistent information has been provided to the public regarding water use of the project post-construction.”

Stansbury called on the state to “conduct a thorough review and adjudication of the project’s current and proposed water use before further proceeding — including consultation with New Mexico’s Tribal Nation, acequias, and senior water users.”

Acequias are community-operated irrigation canals found in Colorado and New Mexico. According to Wikipedia, “Acequias are filled by snow melt and rain to water orchards, gardens, and other agricultural fields. Other than watering crops, acequias have deep cultural significance for many Indigenous and Native communities in New Mexico and Colorado.”

The Quad Report, covering energy policy and politics 

It is seven o’clock on a cold, windless evening: demand is still high, solar output has disappeared, an interconnector is constrained and every available source of flexibility is suddenly valuable.

That hour may last four hours. It may last forty, or become a multi-day weather event.

We often discuss energy storage as though it were a single answer to all of these problems. It is not. A battery that smooths short fluctuations, a system that shifts solar electricity into the evening, and an asset designed to cover several windless days provide fundamentally different services.

Yet electricity markets, procurement programmes and investment models do not always recognise those differences. They can count megawatts while overlooking time.

That is the central finding of my new executive briefing, The missing market for time, based on a structured review of 50 interviews from my Climate Confident and associated podcast archives.

The conclusion is not that technology no longer matters. It plainly does. The more interesting conclusion is that long-duration energy storage is not waiting for one decisive invention. In many cases, it is waiting for power systems to define the service they need, value it properly, contract it over an investable period and create a credible route from procurement to operation.

Battery storage is booming. Long duration is not

Storage is already one of the fastest-moving parts of the energy economy. According to the International Energy Agency’s Global Energy Review 2026, 108 GW of battery storage was deployed worldwide in 2025, 40% more than in 2024. Installed capacity is now eleven times higher than in 2021.

That is amazing progress. It can also obscure the problem.

The IEA says most projects still cluster around two hours, although durations are beginning to lengthen. Those systems can shift solar output, provide balancing services and reduce peaks. But success in short-duration batteries does not mean the market for assets covering ten hours, several days or longer is advancing at the same rate.

The scale required across the broader storage category is substantial. The IEA estimates that global capacity must reach 1,500 GW by 2030 to support the tripling of renewable generation while maintaining electricity security. Batteries provide most of that growth in its scenario. This is not, however, a 1,500 GW target for long-duration storage.

Even the term “long-duration” is unsettled. A US National Renewable Energy Laboratory review found definitions ranging from more than two hours to seasonal storage, with ten hours a common threshold. Buyers can discuss Long Duration Energy Storage (LDES) without agreeing on the problem it must solve.

Start with the uncovered period. Model what remains after transmission, interconnection, demand response, renewable diversity, short-duration storage and firm generation have all been considered. Then specify the necessary duration, location, response speed, cycling pattern and reliability.

The correct unit of analysis is not “a storage project”. It is the system condition that must be covered.

Electricity markets are good at pricing energy. Time is harder

In my recent Climate Confident conversation with Julia Souder, CEO of the Long Duration Energy Storage Council, her central argument was that markets still struggle to price time.

Wholesale markets can put a visible price on electricity delivered now and reward short-term balancing or reserve. Fewer provide stable, duration-sensitive revenues for dependable availability across a prolonged period of system stress.

An LDES asset can potentially provide energy arbitrage, capacity, congestion relief and ancillary services. On a presentation slide, these can be assembled into an attractive “revenue stack”. In the real market, however, the asset may not have access to every service, may not receive payment from every beneficiary, or may lack sufficient certainty about future revenues to support financing.

Value exists. A bankable cash flow may not.

The US Department of Energy’s 2025 commercial-liftoff analysis reaches a similar conclusion. It considers capacity markets, long-term bilateral contracts, cap-and-floor mechanisms, targeted tenders and more transparent system modelling among the potential routes to scale.

The striking point is not that one design has won. It is that technology improvement and market design must proceed together.

Targets do not finance projects. Contracts do

Governments and utilities increasingly recognise the need for storage. Recognition is welcome, but a target is not a transaction.

A developer cannot finance a project with a press release announcing a future gigawatt goal. Investors need to understand construction risk, performance, counterparties and lifetime revenues.

Procurement design therefore matters enormously.

If a tender is written around a familiar short-duration product, longer-duration technologies may be excluded before their system value is compared. If selection is dominated by initial capital cost, an asset with a longer useful life, more cycles or lower replacement costs can appear uncompetitive even when it offers a better lifecycle result.

Procurement should be technology-neutral and performance-specific. Buyers should define the service, require evidence, allocate risk explicitly and allow qualified resources to compete.

Where merchant markets cannot yet support financing, competitive long-term contracts may be needed to bridge the gap. These should retain demanding availability and performance obligations. Public support should help discover prices, build operating evidence and reduce risk, not guarantee every project a return.

The goal is a repeatable asset class, not an endless parade of demonstrations.

A signed contract is not an operating asset

Grid connection queues are long. Permitting can take years. New designs may depend on immature supply chains. Utilities demand exacting reliability and service arrangements, often before manufacturers have accumulated enough production and operating evidence.

Technologies bring different constraints. Compressed-air storage has site requirements. Flow batteries trade energy density for long cycle life. Hydrogen incurs substantial losses when electricity is converted to hydrogen and back. Thermal storage can be compelling for industrial heat, but depends on the duty and integration pathway.

That variety is a strength. It also makes the idea of declaring “LDES is ready” or “LDES is not ready” largely meaningless.

Ready for what, where, for how long and against which alternatives?

The archive evidence supports readiness in the plural. Some technologies are commercially credible for defined applications now. Others still need cost reductions, operational proof or supply-chain development. None should be selected through a technology beauty contest detached from the system requirement.

Five decisions that would move the market

For senior energy leaders and policymakers, the practical agenda is clearer than the technology debate suggests.

First, model the residual flexibility gap. Identify the hours or days that remain difficult after other resources have been included. Do not begin with a preferred storage chemistry.

Second, specify the service in time. Duration, location, availability, recovery time and cycling requirements should appear in operational language that procurement teams and investors can use.

Third, create a route to investability. Targets must become competitive tenders and contracts with sufficient revenue certainty, measurable performance and a credible allocation of risk.

Fourth, make deliverability an investment gate. Grid access, planning permission, manufacturing capacity, testing, warranties, skilled labour and long-term service should be assessed before an award, not left as implementation details.

Fifth, govern a portfolio rather than a favourite technology. Storage must be compared with transmission, flexible demand, interconnection, firm clean generation and renewable overbuild. The objective is not to maximise storage. It is to deliver the required reliability at the lowest credible system cost.

The market is moving, but not evenly

The 108 GW of battery capacity added in 2025 shows that storage can scale rapidly once technologies, revenues and customer needs align. Around 80% of those additions were utility-scale, according to the IEA. Durations are gradually increasing too, with more projects reaching four hours or beyond.

But four hours is not forty. The commercial momentum behind lithium-ion systems should not be mistaken for proof that every longer-duration pathway has crossed the same threshold. Interviews in my archive point to larger projects and accumulating performance data, but much of that evidence comes from technology providers and has not been independently audited.

Industrial applications are broadening the opportunity too. My conversation with Rondo Energy CEO John O’Donnell explored electric thermal storage as a way to convert renewable electricity into dependable industrial heat. That is not interchangeable with every grid-storage application, but it illustrates a crucial point: storage becomes valuable when it is designed around a specific service and connected to a real operating need.

Moving energy through time, and through space

Return to that difficult hour after sunset.

Storage can move plentiful electricity from an earlier period into it. But storage cannot solve every constraint. Sometimes the required electricity exists at the same moment in another region. The obstacle is the network between them.

This is the complementary infrastructure challenge at the heart of the energy transition:

Storage moves energy through time. Grids move energy through space.

The IEA estimates that meeting the global renewable goals agreed at COP28 requires not only 1,500 GW of storage by 2030, but also 25 million kilometres of new or modernised electricity grids. If grids and storage lag behind generation, its modelling shows more curtailment, higher prices and almost 40% more coal generation than under full implementation.

I will return to that second half of the equation in another executive briefing in the coming weeks, examining what prevents electricity networks from expanding and adapting at the pace the transition requires.

For now, the storage lesson is direct. We do not merely need more capacity. We need power markets and institutions capable of identifying which hours matter, paying for dependable service and turning technical capability into assets that can be financed, connected and operated.

That is the focus of my new executive briefing, The missing market for time. Drawing on evidence from 50 interviews, it sets out a practical decision framework for leaders responsible for energy planning, procurement, investment and delivery.

Read The missing market for time.

The next phase of the energy transition will be defined not simply by how much clean electricity we produce, but by whether we can deliver it at the right place and the right time.

This article was first published on TomRaftery.com

Our tradition in the electricity sector is to remain tethered to the past.

And, to save face, we simply patch up the flaws of strategies that have left Brazil trailing behind the other BRICS nations in terms of $/kWh costs.

My suggestion is to completely change the game.

Of course, this wouldn't be an easy decision, given the vested interests involved. But if competitiveness is the primary goal, we need that kind of clarity.

Anyone deeply involved in the electricity sector knows full well that Brazil is a world leader in electricity theft, offers incentives for intermittent energy sources that cause grid bottlenecks (leading to curtailments), and enables a host of projects of questionable merit when viewed through the lens of cost-efficiency—among a long list of other issues.

A crucial question is on the table. What do we want? To cement our reputation as losers, or to take the initiative and aim for efficiency, just like the many countries currently ahead of us?

Do we have the courage and the willingness to break with the status quo, or will we just let things drift?

BEFORE THE BARREL, THERE WAS THE MAP

Perhaps the story did not begin in Venezuela at all.

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Perhaps it began before Donald Trump had even returned to the White House.

On 7 January 2025, two weeks before his second inauguration, Trump stood before reporters at Mar-a-Lago and spoke about two places that appeared to have almost nothing in common.

Panama.

Greenland.

One was a tropical republic containing one of the most consequential artificial waterways ever constructed.

The other was an immense Arctic island covered mostly by ice.

Trump wanted greater American control over both.

Asked whether he could rule out military or economic coercion, he refused. He justified his interest in terms of American economic security.

Much of the commentary treated the remarks as another Trumpian tantrum: imperial nostalgia, provocation, perhaps simply another spectacle produced for an insatiable political audience.

Perhaps that interpretation was too easy.

Because Panama and Greenland were not random territories.

They were geography.

Panama contains a passage.

Greenland commands position.

Panama joins two oceans.

Greenland stands between North America, Europe and an Arctic maritime system whose strategic importance is increasing as Russia consolidates its northern infrastructure and China deepens its interest in polar resources and routes. Greenland itself has long been strategically important to American defence and contains significant mineral potential.

The object was not necessarily possession of the land itself.

It was the strategic geography the land commanded.

That distinction matters.

The old empire planted a flag beside the resource.

The contemporary great power can achieve much of the same strategic effect by influencing the corridor through which the resource travels, the port at which it arrives, the refinery capable of processing it, the financial system through which it is paid for, or the government authorised to sign the concession.

A canal.

A strait.

A pipeline.

An offshore platform.

A maritime boundary.

A mineral-processing chain.

A refinery.

A contract.

https://germantoroghio.substack.com/p/maduros-kidnapping?r=8hatoy

The de-escalation that briefly took Brent below US$86 a barrel in late August did not last. Iran’s Revolutionary Guard said on 2 September that two oil tankers had struck naval mines while transiting the Strait of Hormuz, just days after a Saudi Aramco tanker, the Sidr, was hit by projectiles with two crew fatalities, and a Liberian-flagged supertanker was struck off Oman.

US Central Command responded with strikes on Iranian air-defence, radar and mine-laying sites, while Tehran retaliated with missiles towards US bases in Jordan and Bahrain, most of which were intercepted.

👉 Read more:
https://www.indoen.com/news/oil-markets-whiplash-as-mines-missiles-and-drones-hit-two-fronts-at-once