In today’s episode, the Substack Shipping News follows the major project-fantasyland adventures of anti-oil, net-zero-carbon politicians in an apparent embrace of a multibillion-dollar oil pipeline in Canada.

An improbable storyline, you say?

Could the two camps really join hands to provide Canadian energy access to the global marketplace?

Judging by previous NDP and Liberal party adventures in the land of fossil fuel market maximization, the answer is no.

But stay tuned.

This week’s episode features Alberta’s latest pitch to get its oil riches to tidewater and into world markets beyond the United States.

Its northern option, having been sandbagged and derailed at every turn by governments, activists and Indigenous groups, even though it is the shortest to market and therefore the most cost-effective route, Alberta Premier Danielle Smith is proposing a southern B.C. pipeline option.

Starting in Bruderheim, northeast of Edmonton, and running to B.C.’s Roberts Bank, Alberta’s pipeline plan B 2.0 parallels the existing Trans Mountain corridor.

Expect it to encounter parallel opposition and grievance. Rehashing anti-enterprise battles that undermine the country’s productivity and prosperity has become a Canadian specialty.

Pipeline pipe dream aficionados will recall the parade of trials and tribulations that stalled the Trans Mountain pipeline expansion (TMX).

Economists and folk who value the efficient use of taxpayer dollars will lament the resulting waste of those dollars engineered by the federal Liberal government.

As a summary reminder, a TMX originally estimated to cost $5.4 billion ended up limping across the finish line at closer to $34 billion.

Another reminder: those were not private investment dollars incinerated; they are taxpayer dollars.

The same inflation multiplication players on the federal side are back at it. This time, however, with the spectre of an Alberta separation referendum clouding the horizon.

That has complicated the energy superpower tap dance for Net-Zero Carney Canada.

Difficult dance steps, indeed, for Prime Minister Mark Carney. More “catalyzing” cooperation and taxpayer investment in B.C. and Alberta initiatives required.

Thus, Carney Canada’s agreement with Alberta to pursue that southern pipeline route.

But not without ensuring that the premium for Canadian crude is further inflated by such federal requirements as the $16.5 billion Pathways Alliance carbon capture and storage project.

Then it’s on to B.C. to soften up the West Coast NDP oil and gas development grievance party with billions of federal taxpayer dollars directed at the North Coast transmission line and Roberts Bank port infrastructure investment.

However, not before the Canada-B.C. co-operative prosperity agreement extended the moratorium on oil tanker traffic along the province’s north coast and hammered another nail in the coffin of any future West Coast energy pipeline.

Remember, of course, that oil tankers sail past northern B.C. regularly to and from Alaska. But that is another land with different standards for what constitutes an energy superpower.

B.C. Premier David Eby also made it clear that he and his party were not supporters of any pipeline, even with the billions in new federal funding headed B.C.’s way.

He said the province would not oppose the southern route, primarily because the province does not have the authority to oppose it.

Back to Alberta’s pipeline plan B 2.0 and smiles for the camera from Carney and Smith as the two shake hands on the south coast pitch.

Estimated cost today: between $35 billion and $44 billion. Any guesses as to which one would be closer to the mark if and when any pipeline is started?

Judging by the TMX bill increase, Canadian taxpayers would be on the hook for something closer to $200 billion.

That taxpayer bill, however, is contingent on any pipeline getting built.

Controversy over Roberts Bank’s ability to accommodate an oil export mega-terminal has already begun.

Considering that the port’s Terminal 2 container terminal expansion took over a decade to win approval, the odds of getting anything else expanded, added or accelerated in this century are slim.

Little wonder then that Alberta’s pipeline plan B 2.0 has only token private investor involvement from Calgary-based Pembina Pipeline Corp.

What astute oil and gas investor in the wider world would gamble anything more on Canada and its overpriced and under-delivered energy superpower ambitions?

That is one net-zero category the country has locked up.

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For utility executives managing long-term fuel security, the unresolved maritime dispute between Thailand and Cambodia over the Overlapping Claims Area (OCA) is a critical case study in geopolitical risk. The area sits on an estimated billions of dollars in untouched oil and gas reserves, yet decades of political gridlock have kept it completely offline.

Why This Matters to Utility Leadership:

• Global Supply & Pricing Pressures: Because these massive domestic reserves remain locked away, both Thailand and Cambodia are forced to rely heavily on volatile liquefied natural gas (LNG) imports to fuel their power sectors. This sustained regional demand tightens the global LNG market, directly affecting international pricing and supply availability for utilities worldwide.

• Infrastructure and Investment Risk: The gridlock highlights how quickly regulatory and territorial friction can freeze vital energy infrastructure. As utilities navigate the energy transition, the OCA impasse serves as a stark reminder that resource geography is only as reliable as the political stability supporting it.

Unlocking the OCA could fundamentally shift regional power generation dynamics, but until diplomacy catches up with energy demand, it remains a structural bottleneck with global ripple effects. This story was featured in Yahoo, just under the banner. See Forbes: https://www.forbes.com/sites/kensilverstein/2026/07/07/cambodia-thailand-sit-on-billions-in-oil-and-gas-thats-untouchable/

When utility professionals think about grid modernization, the conversation naturally gravitates toward large-scale upgrades: high-voltage transmission lines, massive utility-scale storage, and centralized distribution management systems. We think big because our grids are big.

But a quiet infrastructure success story unfolding in rural Haiti turns this capital-intensive, top-down philosophy entirely on its head. It suggests that in highly volatile or capital-constrained environments, the ultimate grid architecture might not be a massive upgrade at all—but rather a modular network of "nickel-and-dime" mesh grids.

Bypassing the Centralized Bottleneck

In my recent coverage for Forbes--picked up by Yahoo Finance--I looked closely at how decentralized solar mesh grids are successfully delivering clean, affordable electricity to thousands of rural Haitian households. These are not mini-utilities or traditional microgrids that require centralized generation and a mini-distribution network. Instead, they connect small clusters of homes via localized, modular nodes. If one node or home drops off, the rest of the mesh network self-heals and keeps running.

For utility professionals, the structural takeaways from this model are profound:

• Radical De-Risking: Traditional grid extensions require massive upfront capital expenditure before the first customer flips a switch. Mesh grids scale organically. You build out a few homes at a time, matching capital deployment precisely with localized demand.

• Operational Resilience Under Strain: Conventional wisdom says infrastructure requires political stability. Mesh networks prove that localized, modular assets can thrive in environments of absolute instability precisely because they have no single point of failure. If it can maintain reliability in rural Haiti, the underlying architecture has cleared the ultimate stress test.

• The Capital Sequencing Blueprint: Perhaps the most scalable lesson is how these projects are funded. Developers utilized early-stage philanthropy to absorb the initial execution risk. Once the operational data proved the model's viability, it unlocked major follow-on funding from multilateral institutions like the World Bank and the IDB Lab.

The Macro Value of Micro-Networks

As global utilities face mounting challenges from extreme weather, physical security threats, and skyrocketing interconnection queues, the "all-or-nothing" approach to grid expansion is looking increasingly fragile.

Haiti’s mesh grid success isn't just a humanitarian milestone; it’s a technical proof of concept. It proves that a highly decentralized, modular power architecture can deliver 40% lower costs and unmatched resilience. For an industry staring down the barrel of a complex energy transition, it’s time to realize that sometimes, thinking small is the most strategic way to scale.

https://www.forbes.com/sites/kensilverstein/2026/07/01/despite-crippling-poverty-haiti-is-quietly-switching-the-lights-on/?ss=energy

Smart meters have been deployed for decades at U.S. electric, water, and gas utilities, delivering business value from the customer to the operations side. One persistent challenge: the cellular networks that underpin smart metering don't stand still. When networks evolve, spectrum gets refarmed, or coverage shifts, single-carrier SIMs cannot adapt. The result is truck rolls, lost telemetry, and rising operational costs compounding across millions of devices over a 15–20 year deployment lifecycle.

New SGP .32 eSIM (eUICC) standards enable full coverage with multiple profiles and future-ready connectivity — but they introduce a critical tradeoff: power-intensive network switching can compromise the battery life that smart meters depend on to remain operational for decades.

In this exclusive Energy Central PowerSession, a telecom industry analyst and a IoT connectivity subject matter expert will explain how the new standard resolves this tradeoff — enabling resilient connectivity without sacrificing battery life, managed via a unified connectivity management platform (CMP). We'll explore how a North American water utility deployed a new generation of meters across a geographically dispersed service area — including underground vaults and remote sites where physical SIM replacement is both disruptive and costly — and how the eSIM is paving the path forward.

 We hope you can join us for this live PowerSession on August 4th.
Panelists:

• Mike Smith, Moderator

• Steffan Sorrell, Chief of Research, Kaleido Intelligence

• Jerome Coppens, Product Director, IoT Connected Services, Semtech Corporation

Register Now

In January 2025, the LA wildfires became one of the most destructive weather events in American history—and LADWP, the largest municipally-owned utility in the United States, had to respond in real time…while simultaneously planning for the World Cup, the Super Bowl, and the 2028 Olympics.

This is how they did it.

In this episode, host Kinsey Grant Baker sits down with Zoraya Oliver-Griffin, LADWP's Chief Resiliency and Emergency Officer, to talk about what it actually takes to build a utility that can withstand anything. From standing up a state-of-the-art emergency ops center to stress-testing infrastructure through back-to-back global events, Zoraya breaks down how LADWP is turning hard-won lessons into a long-term resilience strategy—and why she thinks every major utility needs a role like hers.

Watch on YouTube

Listen on Apple

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Oak Ridge National Laboratory Credit: U.S. Department of Energy

If you are designing a car from scratch, there are certain essentials to begin with. You need to start with the wheels on the corners, for example.

But when it comes to building a nuclear reactor, things are different. There are hundreds and maybe thousands of ways of doing it. The constant is that you need fissionable fuel and a moderator to collect the heat and manage the neutron flux.

That embarrassment of choice — now reflected in the number of small modular reactors (SMRs) vying for market acceptance — may be why thorium reactors, which began with promise, have been left on the shelf.

The nuclear establishment, goaded by the Nuclear Navy’s Adm. Hyman Rickover, wanted light water technology. That is what the first 100-plus U.S. civilian reactors employed.

At the dawn of the civilian nuclear age, it was a straight contest between two fuels: uranium and thorium. Thorium is fertile but not fissile: It can’t start a chain reaction unless it is triggered by a small amount of the isotope uranium-235.

Once this happens, thorium becomes uranium-232 and fizzes wonderfully with a steady stream of neutrons, producing heat in the moderator, which is where the first steps in making electricity are taken.

That heat is captured to create steam that turns a turbine.

Thorium was used in part in the first power-producing, commercial nuclear reactor: the 60-megawatt Shippingport Atomic Power Station in Beaver County, Pennsylvania. With three different fuel assemblies, it ran for 25 years, starting in 1957. It used solid fuel, which was to become the standard for civilian nuclear power.

Meanwhile, at the Oak Ridge National Laboratory in Tennessee, under its director, physicist Alvin Weinberg, work went ahead on what would become a legendary fast-breeder thorium reactor, using a liquid fuel embedded in molten salt. It went critical in 1965 and operated for five years before it was closed by the Atomic Energy Commission (forerunner of the Department of Energy) in a political move.

A fast reactor uses extra neutrons to create new fuel and burn up radioactive waste. The process is akin to perpetual motion — but isn’t, of course.

Now a charismatic nuclear engineer, Yash Patel, founder and CEO of AMReactor, is planning to bring thorium back as a viable future option for space exploration, power generation and, eventually, ship propulsion.

Patel told me that his reactors – he has designs for a microreactor (under 20 MW) and for a SMR (250 MW). The planned reactors are molten salt-moderated, thorium-fueled fast reactors.

He believes they will not only be cheaper, but will also operate better than the SMRs now entering the market.

Patel’s plan for Austin-registered AMReactor is to outsource as much of the fabrication as possible.

A fast reactor is called a breeder reactor because it generates more neutrons than are needed to produce fission, and these transmute waste into additional fuel.

Patel went to school in California and while looking for a career, a break came that changed the trajectory of his life. He got an internship with NASA at the Jet Propulsion Laboratory. There he worked on Curiosity, the plutonium-fueled Mars rover. His nuclear love affair, he told me, was “complete and instant.”

From NASA, he went to Texas A&M and graduated in nuclear engineering. He was well along with his Ph.D., when a family illness caused him to abandon it.

Patel lists two great blessings in his life. “The first was that I moved to America from India. The second was attending Texas A&M. That was another wonderful break.”

After a stint in biopharma, where he prospered, Patel started designing reactors in all his waking hours along with a friend, D’mitri Scott, now the chief technology officer at AMReactor.

Patel said the numbers didn’t work for their plans until they switched to thorium. It was a eureka moment.

There followed a period which he likened to Bill Gates and Steve Wozniak working on the first computer operating system. The two young men were obsessed and inspired by what they believed was extraordinary. “Our girlfriends, now our wives, saw very little of us. We sometimes worked all night,” Patel said.

With thorium, they found all they were looking for: a stable source of reliable power that was safe, couldn’t melt down, and was able to handle most of the fission products.

And it was proliferation-proof because of the presence of intense gamma radiation, which made it hard to process, steal or divert. “Thorium was the winner,” he said.

A new reactor is on the way.

This post is about the most expensive mistake the energy industry has made in the last 20 years and why it is now the single biggest obstacle to the AI-native grid:

We built silos. When we should have built systems.

Let’s get into it.

Your Grid has more Data than ever

Your grid has more data than ever. But your operators are more blind than ever. How is that possible?

In the last decade, utilities have invested heavily in digitalisation. Smart meters by the million. IoT sensors across every asset. SCADA upgrades. Cloud migrations. Data lake projects. Advanced analytics platforms.

And yet I still sit across the table from grid operators who cannot answer basic questions in real time.

• “Where is the fault right now?”

• “How much available capacity do I have in the next 15 minutes?”

• “What happens to network stability if I bring this renewable asset online?”

The data to answer those questions exists. It is being generated, somewhere in the system, right now. The problem is that it is trapped.

Trapped in SCADA. In the EMS. In the OMS. In the DERMS. In the market systems. In the AMI platform. In the asset management database. Each system a world unto itself, with its own data model, its own naming conventions, its own timestamp format, its own definition of what a “fault” or an “asset” or a “reading” actually means.

We didn’t build a digital grid. We built a digital archipelago.

Islands of data, separated by water, with no bridges between them.

And here is the irony that keeps me up at night: We are now trying to build AI on top of this archipelago.

We are pointing machine learning models at fragmented, inconsistent, latency-riddled operational data and expecting them to produce reliable, actionable grid intelligence. And when the outputs are wrong, or worse, when they are confidently wrong: we blame the AI.

The AI is not the problem. The data architecture is the problem. And it was a choice. Not an accident.

Every silo in your operational technology landscape was created deliberately. A vendor sold you a best-in-class solution for one specific problem. It solved that problem. It did not solve the problem of how its data would talk to the system you bought three years earlier from a different vendor with a different data model and a different integration philosophy.

Nobody owned the data layer. So nobody built it.

The result is what we have today: utilities managing the most complex distributed energy systems in history using a patchwork of disconnected tools that, in aggregate, produce more noise than signal.

This is not a technology problem. It is an architecture decision that was deferred for 20 years. And the bill is now due.

The good news is that the path forward is clear.

Not another application. Not another dashboard. Not another AI pilot running on the same broken foundation.

A data fabric. A unified semantic layer across the IT-OT boundary that gives every system, every operator, and every AI model access to the same trusted, contextualised, real-time view of the grid.

One source of truth. Not because we moved everything into one database. No, that ship has sailed. But because we built the layer that connects and contextualises what already exists.

The companies building that layer today are not just solving a technical problem. They are building the foundation that the AI-native grid runs on. Everything else is built on sand.

This post was adapted from my articles series about The AI-Native Grid or Agentic Grid. If you'd like deeper analysis on AI, data platforms, and the future of electric utilities, you can dive deeper on Substack.

When I moved my blog from Blogspot to Substack last August, I needed help many times. On the Blogspot platform, there was (and still is) no help at all. You have to go online to a Google Group (Blogspot is owned by Google) and ask your question there. But Substack has a really great chatbot that springs to attention as soon as you ask for help. While it sometimes takes me two or three back-and-forths to get the chatbot to understand what I’m asking, 90% of the time it understands what I need and gives me a definite answer. Of course, the answer is sometimes, “We just don’t support that now, but I’ll submit a new feature request for you if you would like.” I always confirm I’d like that, but I know full well I’m unlikely to see the new feature implemented in my lifetime.

Recently, I wanted to see a post I had written in 2015. (Some background: I started the Blogspot blog in January 2013. I transferred all my Blogspot posts - over 1200 then - to Substack last August and stopped posting any new posts on Blogspot last fall. In fact, as you’ll see if you go to the link at the beginning of this post, I will soon take down the Blogspot blog because it’s become too popular among AI models eagerly seeking information in posts I wrote years ago. In fact, my Blogspot blog had 672,000 pageviews last month alone, while I guess I receive no more than 10-15,000 pageviews per month in Substack and in Energy Central, where I also put up my posts. I believe the Blogspot pageviews are almost entirely from LLM training)

When I entered “2015” in the Substack search bar, I wasn’t terribly surprised that, while I immediately was shown every post where “2015” appeared in the text, the search doesn’t look at the date of the post itself, and therefore couldn’t show me which posts I wrote in 2015 (or any other date range). I asked the chatbot if it was possible to search on a date range. It cheerfully pointed out to me (it’s always cheerful, of course) that the feature I want isn’t supported in the search bar, but it would be happy to submit a new feature request for me. Even though I knew this would be useless, I let it do that anyway. Then it closed the ticket.

After that, I received the usual email asking me to clarify what I wanted, so I did that – again, not expecting anything more to come of it. However, this time a human emailed me to point out that there’s a completely different way – not involving the search bar – that I can see all of my posts within any date range. It works fine, so now I can find posts from 2015 or any other time period.

The important point about this is that I don’t think the person who solved my problem is some sort of brilliant individual that Substack is lucky to employ. They just did what a human who’s trying to be helpful does naturally (or should, anyway): go back to the problem I was trying to solve and figure out how it could be solved in the context of the Substack platform. The chatbot had categorized my problem as narrowly related to the search bar (even though it was formulated more generally), but my problem was really that I wanted to see posts from a range of dates – and I didn’t know the platform well enough to realize that the search bar isn’t the only possible way to do that. My guess is the human figured out the answer to my problem within a few seconds, even though the chatbot would probably never have done so without being given additional prompts that a human wouldn’t need.

The moral of this story is that generative AI, which is simply an elaborate statistical algorithm for predicting the next word in a sentence, will never reach the point where it can satisfactorily answer a question, if the questioner didn’t ask their question in a way that the answer will be straightforward – specifically, if the questioner didn’t ask the question in the context of the correct response. I asked my question in the context of the search bar, so that was all the chatbot focused on in its answer. But the human understood the question in the right context: “Given that I’m a Substack user, is there a way for me to find all of my posts within a particular date range?”

Of course, since this was Substack’s chatbot, it could have been trained always to consider every question that appears to be about a particular function within Substack to be instead a question about the platform as a whole. That might have allowed it to solve my problem without requiring human intervention, but what if I’d really been asking whether blogging platforms in general allow searches by posting date? That would have required an even bigger context, which the chatbot probably wouldn’t have been trained for.

Human beings don’t know all the answers, but they should at least be able to reformulate the question in its proper context. Generative AI can’t even do that and probably never will. 

Tom Alrich’s Blog, too is a reader-supported publication. You can view new posts for two months after they come out by becoming a free subscriber. You can also access all of my 1300 existing posts dating back to 2013, as well as support my work, by becoming a paid subscriber for $30 for one year (and if you feel so inclined, you can donate more than that or become a founding subscriber for $100). Whether free or paid, please subscribe. 

If you would like to comment on what you have read here, I would love to hear from you. Please comment in my chat or email me at [email protected].

Over the past several years, utilities have invested heavily in modernizing grid infrastructure, digitizing assets, and improving operational visibility.

As these efforts mature, another concept has rapidly gained attention: the digital twin.

The promise is compelling. A virtual representation of physical assets, networks, or even entire grid operations that can provide real-time visibility, predictive insights, and scenario-based decision support.

But amid the growing enthusiasm, an important leadership question remains:

Are digital twins delivering measurable value, or are they becoming another technology buzzword in the grid modernization journey?

Beyond the Buzzword

Most utilities already possess elements of what many would describe as a digital twin:

• Asset models

• GIS platforms

• SCADA and EMS environments

• Operational analytics

• Asset performance management systems

The challenge is not creating another model. The challenge is creating a living, connected representation that remains synchronized with operational reality. That distinction matters.

A static model provides information. A digital twin should provide insight.

The Real Value Proposition

When implemented effectively, digital twins can help utilities move beyond historical analysis toward proactive decision-making.

Potential applications include:

• Asset health monitoring and predictive maintenance

• Grid planning and capacity analysis

• Storm preparedness and restoration simulations

• DER integration studies

• Workforce training and operational readiness

The value is not simply in visualization. The value lies in reducing uncertainty before decisions are made. In many ways, digital twins represent another step in the industry's progression from visibility to operational intelligence.

Why Many Digital Twin Initiatives Struggle

Despite the promise, many organizations find it difficult to scale digital twin initiatives beyond pilots. A common misconception is that a digital twin is primarily a technology project.

In reality, success depends on:

• Data quality and governance

• Asset model accuracy

• Integration across OT and IT systems

• Clear ownership and lifecycle management

• Defined operational use cases

Without these foundations, even sophisticated digital twin environments can quickly become disconnected from reality. And once trust erodes, adoption follows.

The Trust Challenge

Like AI and decision intelligence, digital twins ultimately depend on confidence. Operators, engineers, and planners must believe that the representation accurately reflects the state of the physical system.

The question is not: Can we build a digital twin?

The more important question is: Can we maintain trust in it over time?

That requires continuous synchronization, governance, and accountability.

From Technology Asset to Operational Capability

One of the most common mistakes is treating digital twins as standalone technology investments. Leading organizations are increasingly approaching them differently.

Rather than asking: How do we build a digital twin?

They ask: What operational decisions are we trying to improve?

This shift changes the conversation from technology deployment to business outcomes. The digital twin becomes a means to an end, not the end itself.

Strategic Necessity or Hype?

The answer is neither simple nor universal. Not every utility needs a highly sophisticated digital twin environment today. However, as grid complexity increases through distributed energy resources, electrification, resilience requirements, and AI-enabled operations, the ability to model, simulate, and predict system behavior will become increasingly valuable.

The question is no longer whether digital twins have potential.

The question is where they create the greatest value and how utilities can operationalize them effectively.

Closing Thought

Digital twins are unlikely to transform utilities simply because they exist. Their value will be determined by how well they improve planning, operations, and decision-making. Like many aspects of digital transformation, success will depend less on technology and more on execution, governance, and trust.

The future may not belong to the utilities with the most sophisticated digital twins. It may belong to those that use them most effectively to make better decisions.

Reality check: It takes around five years, on average, for generation and transmission projects to move through review. “The current permitting system is broken,” Xan Fishman, vice president of energy at the Bipartisan Policy Center, told Energy Central over email.

But the grid quickly needs new gigawatts (and transmission lines) to meet a tsunami of demand. To cut through all that red tape ASAP, Congress is racing to broker a deal by August recess.

But first, why does the permitting process take so long? It’s “fractured across federal, state, and local authorities, and it attracts litigation that can last a long time with uncertain outcomes,” Tom Sharp, director of permitting intelligence at analytics firm Arbo, told us via email.

That litigation often stems from federal rules like the National Environmental Policy Act (NEPA) and the Clean Water Act, which were intended to safeguard US ecosystems and communities. These court battles can add years to the process and even kill some projects.

So, what’s the progress on permitting reform? In recent years, the House has introduced a flurry of bills. Roll the tape:

• You’ve got the SPEED Act, which aims to streamline NEPA and cut down litigation.

• There’s also the PERMIT Act, which has similar goals for the Clean Water Act.

• Both are sitting in the Senate but aren’t likely to pass, Sharp and Fishman agreed.

What’s more likely: A deal that wraps up these goals (along with accelerating the transmission buildout) into one hefty package. Senate committees are in negotiations right now, Fishman said. This potential deal would likely also tackle President Trump’s crusade against renewable projects, he added.

These talks have run into some speed bumps, but the stakes are high to wrap things up by next month’s Congressional recess: “If we don’t get this done, energy costs are going to rise and chances of blackouts will increase,” Fishman said.

By Kennedy Maize

In a massive, coordinated campaign, late last month (June 29) 196 local community groups and the attorneys general of eight states — Illinois, Arizona, Colorado, Delaware, Maryland, Minnesota, New Mexico, and Vermont — filed objections to the Environmental Protection Agency’s April proposal to roll back regulations on coal ash disposal from the nation’s coal-fired power plants.

The filing came on the final day of comments on the proposed rule, which is likely headed to a confrontation in federal court. A letter by the community groups, organized by the national environmental law firm Earth Justice, notes that they represent “more than a million Americans concerned about hazardous pollution from leaking coal combustion residuals (“CCR” or coal ash) surface impoundments, landfills, and ‘beneficial use’ sites.”

In their comments, the AGs focus on the EPA’s claim that its proposed rules would increase flexibility in managing coal ash. They charge, “Rather than improving the program, more ‘flexibilities’ threaten to leave the environmental risk from massive quantities of CCR ignored under federal requirements, leaving states with the administrative burden of cleaning up the mess.” The state law enforcement officials complain that the EPA plan, “if adopted, would be arbitrary and capricious under the Administrative Procedure Act (‘APA’) and violate statutory requirements under the Resource Conservation and Recovery Act (‘RCRA’) as recently applied by the D.C. Circuit.”

In a news release when EPA issued the new proposed rules, the agency bragged that the new rules “would promote resource recovery, allow for site-specific considerations in permitting, provide regulatory relief while continuing to protect human health and the environment, and ensure continued transparency. The proposal would also encourage beneficial use, potentially reducing the need for disposing of CCR, set protective and uniform standards for CCR storage piles, and decrease the use of new natural resources.”

Upon diving into the proposed rule itself, a somewhat different story emerges. EPA’s summary of the rule notes that it would “modify or remove three of the criteria that facilities with legacy surface impoundments closed prior to November 8, 2024, must currently meet to be eligible for the deferral from complying with the CCR unit closure standards until site-specific decisions are made by permit authorities.”

The proposal would further “exempt from the CCR regulations in Title 40 of the Code of Federal Regulations Part 257 certain structures primarily used to dewater CCR waste that facilitate disposal of the CCR elsewhere,” and “rescind all CCR management unit requirements and accept comments on alternative approaches that would include revisions to the existing CCR management unit regulations.”

When EPA proposed the rule last Spring, Earth Justice commented, “The proposed rule would dismantle coal ash protections for both operating and former coal power plants sites; exempt hundreds of coal ash dumps from any regulation at all; and permit the owners of coal power plant sites to minimize, delay, or entirely avoid cleanup of contamination at their facilities.”

In their comments last month, the community groups said, “EPA’s current coal ash regulations are the product of decades of research by EPA, the Center for Disease Control and Prevention, and independent scientists. The rules are informed by robust industry data, citizen input, and evidence at scores of sites contaminated by mismanagement of toxic ash. EPA and industry data have confirmed repeatedly that the hazardous constituents in coal ash, including arsenic, boron, chromium, cobalt, lead, lithium molybdenum, and radium, pose serious harm to human health and the environment when they are released to air, water, and soil.”

The AGs state, “Overall, coal plants have generated approximately 5 billion tons of coal ash. Historically, power plants have disposed of coal ash in surface impoundments, often beside or near lakes and rivers. Surface impoundments are prone to leak or rupture, endangering soil, groundwater, surface water, and surrounding communities.”

They cite the disastrous 2008 failure of the ash pond at the Tennessee Valley Authority’s giant Kingston coal-fired plant, the largest industrial accident in U.S. history, costing TVA more than $1 billion in cleanup costs and requiring seven years to remediate.

The states note that EPA “would relax or rescind uniform, nationwide requirements for baseline CCR standards. Rather than own the harm that the Proposal will create, however, EPA devolves authority to permitting agencies, usually state permitting agencies, to decide on their own how to regulate without the benefit of strong baseline standards. By abdicating its statutory responsibility in this way, EPA would create an immense burden on the well-regulated states to craft numerous individual requirements to ensure continued protection of human health and the environment. Simultaneously, the rule changes would relieve laggard states of uniform, nationwide requirements, threatening harm to their own residents as well as neighbor states.”

Earthjustice senior counsel Lisa Evans commented, “This EPA is eradicating environmental and health protections and will make Americans sicker, poorer, and destroy irreplaceable water resources. And Trump’s EPA is doing this because the coal industry asked them to. If this reprehensible and illegal proposal becomes law, we will take the EPA to court and fight for national coal ash protections.”

The Quad Report, covering energy policy and politics

AAAS: "British Trawlers Working Nearly 20 Times as Hard to Catch Fish."

Most commercial fisherfolk today don't appreciate how much harder it is to catch fish than it was for their forebears. In the 1880s, steam-powered trawlers began to compete with sail-powered fishing boats in European waters. "The practice was controversial in the United Kingdom, where some critics claimed that the new trawlers were reducing fish stocks and damaging habitats."

Marine conservation biologist Callum Roberts of the University of York in the United Kingdom decided to analyze the historical data. "To adjust the catch data for the increasingly powerful and sophisticated fishing boats, Roberts and colleagues used boat registration records to calculate the overall power of the British fleet." The researchers expressed ship 'power' in units equivalent to the catching power of one sail-powered trawler in the 1880s, calculating the Landings Per Unit of fishing Power (LPUP).

"From 1889 until 1914, LPUP dropped sharply, from more than 60 tons to less than 20 tons." The decrease in fishing during World War I allowed a recovery of fish stocks, and LPUP rebounded briefly to 30 tons in 1918. "Between WWI and the 1950s, British vessels began fishing farther from home, off the coast of West Africa and in the Arctic...[allowing] the rate of fish caught by British vessels to increase again, to about 50 tons in 1956." But with continued exploitation, LPUP nose-dived, to about 5 tons in 1980, the team reports online this week in Nature Communications.

"After 1983, the Common Fisheries Policy of the European Union set strict new limits on where and how much British vessels could fish, but stocks have not recovered."

Today it takes 17 times as much fishing power to land a fish as it did in 1889, an LPUP of 3.4. 

The implications are clear, overfishing, yes, but also marine warming, loss of coral reefs as incubators, plastic + other pollution, acidification, now looming deoxygenation. Climate change + impoverishment of marine ecosystems. Pity the poor fish + the fisherfolk.

The answer is "it depends"!

What is the desired objective?

If the challenge involves a "short duration," then batteries can be highly attractive and convenient.

If, however, it involves a "long duration," an alternative—such as diesel or gas generators—is the better choice.

These conclusions are based on capital amortisation calculations factoring in the energy delivered and variable costs.

In other words, one must first determine the objective and then compare the available alternatives.

Nick Italiano, S&C Electric Company

More frequent and severe weather events are placing unprecedented strain on the distribution grid—and nowhere is that strain felt more acutely than at the very edge. When a fuse on a distribution transformer operates, crews are often dispatched, only to find nothing obviously wrong. The crew replaces the fuse, and service is restored after a period of time. But the outage is logged as “no problem found” or “unknown cause.”

For customers, it’s another unnecessary, sustained interruption. For utilities, it’s another truck roll, a negative impact on reliability metrics, and another unknown cause. These incidents highlight a growing resilience challenge: a lack of visibility at the grid edge.

The Hidden Cost of “No Problem Found”

Often, the underlying event is temporary—animal or vegetation contact, a momentary flashover, or other fleeting conditions. Severe weather and lightning also frequently trigger fuse operations at distribution transformers.

Outage Management Systems capture the outcome of these events, not the cause. As a result, outages are commonly classified as “no problem found,” and re‑fusing becomes the default response. Over time, this reactive cycle leads to repeated outages at the same locations, escalating O&M costs, and mounting customer frustration.

Taking a Closer Look at the Last Mile

The issue is amplified by the physical realities of the grid edge. Laterals make up the “last mile” of the system, often with distribution transformers serving small load pockets—typically just a few homes—at the very edge.

These lightly loaded lines face greater exposure to weather, vegetation, and wildlife, and during storms, fault probability increases. Customers at the grid edge are typically the last to be serviced and often wait long periods for service restoration. Restoration under pressure raises the risk of re-fusing errors in an effort to get service back on quickly. The result is a segment of the grid with high-outage frequency, low visibility, and significant operational uncertainty.

Turning Data into Insight

What’s missing isn’t effort, it’s insight. Utilities already have the data needed to better understand grid-edge performance.

By analyzing historic outage records, Customer Experiencing Multiple Interruptions (CEMI) metrics, and OMS data—paired with GIS, SCADA, weather information, and AMI, if available—utilities can identify clusters of repeat outages. These patterns often point to laterals where exposure to weather, wildlife, or vegetation contact is high and traditional fuse protection is no longer adequate. Weather and lightning density data further refine where storms are most likely to drive repeat failures.

From Reactive Fixes to Targeted Investment

Instead of asking, “Where did the fuse blow?”, utilities can ask, “Where does the data show this will happen again?”

Targeted deployment of modern protection technologies, such as electronically controlled single-phase resettable interrupters, can help, often with a return on investment. Proactively upgrading protection is an approach that shifts spending from reactive O&M to planned capital, strengthening the case for system improvements.

Modern self-resetting interrupters are uniquely suited for the grid-edge because they are resettable transformer-fuse replacement devices. Just like traditional fuses, they install into cutouts and drop open at the end of their operating sequence, but their vacuum interrupters quickly clear faults without the noise and debris associated with expulsion fuses.

These interrupters are built with electronic controls, offering significant benefits over conventional transformer fuses by:

• Avoiding unexpected outages from overcurrent stress, TCC curve shifts, and nuisance tripping

• Preventing re-fusing errors because there’s no fuse to replace

• Allowing for easy integration and coordination with upstream devices

The non-fault-testing model is ideal for locations where reclosing is not desired. Where fault testing can be used, fault-testing units will automatically restore power for temporary faults, avoiding unnecessary sustained outages, improving reliability metrics such as SAIDI, SAIFI, and CEMI, and further expediting storm recovery efforts.

By focusing on the last mile as an opportunity, utilities can strengthen resilience and enhance reliability across the entire system—because resilience built at the very edge benefits the whole grid.

Utilities have more data than ever before—AMI readings, drone footage, transformer sensors, SCADA signals. The question is no longer whether to collect it. It's how to actually turn it into decisions that keep the lights on.

In this roundtable, host Kinsey Grant Baker sits down with Christina Park of Skydio, Mark Gabriel of United Power, Trevor Stiles of ATC, and Sean Vanslyke of SEMO Electric to explore how utilities are evolving their approach to asset management in real time—moving from gut-call prioritization to condition-based maintenance, getting their teams on board with new technology, and building toward a future where failures get caught before they happen.

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This episode is brought to you by Skydio. Skydio helps utilities move beyond outdated time based maintenance to smarter, safer and more scalable condition-based maintenance. Powered by autonomous remote operated drones, over 280 utilities trust Skydio. Because with real time aerial data and remote inspection, utilities can spot issues early, reduce forced outages and make confident, efficient, cost effective decisions.

Learn more about Skydio here.

• Just in time: This past weekend, Aalo Atomics’ design reached criticality. It’s the fourth reactor in the DOE pilot program to hit that breakthrough (following Deployable Energy’s announcement on July 1, which fulfilled President Trump’s goal for three critical reactors by Independence Day).

• HALEU-lujah: Meanwhile, Centrus Energy has finalized an agreement to receive $900M from the DOE to scale up HALEU production at its facility in Ohio.

• While we’re on nuclear: The NRC is looking to scrap the controversial “as low as reasonably achievable” (ALARA) radiation standard for nuclear plants, which many experts say lacks solid evidence. This would be replaced with “more objective“ rules, according to the agency.

PIOMAS: "PIOMAS Arctic Sea Ice Volume."

I met Andy Lee Robinson more than a few years ago, online that is. Last I heard he was in England. I do remember I paid him in British pounds sterling [£] for the lifetime privilege of using this image. This graph begins in 1979. Pertinent in comprehending this is realizing several points.

First, sea ice forms on the ocean surface, with contributions both from the salty ocean surface + fresh snowfall. Separate from the ice floes calving off tide-water glaciers.

Second, April—the light green line—is the maximum extent of sea ice, the end of Arctic winter of course.

Third, September—the black line—is the minimum extent of sea ice, in this case coincident with the end of Arctic summer.

The pictures you have often seen of the fluctuating surface area of Arctic sea ice represent just that, while this graph is a measure of total volume, more pertinent in understanding climate effects. When + where sea ice disappears, more dark blue ocean water absorbs far more solar energy, which is a main reason that the Arctic is warming up faster than the world as a whole.

It should be apparent to the naked eye where all of this is headed, with huge implications for geoscience, fishing, extinctions, navigation, territorial claims, seafloor mining, extraction of fossil fuels—and the survival of whales. Yes, whales, since with dwindling sea ice, pods of orcas have migrated north to predate on Arctic whales such as belugas + narwhales.

I post this every couple of years, + suggest somber contemplation. Especially if you work in a fossil fuel industry.

India imported 3.83 million tonnes (MT) of coal during 28 June–4 July 2026, with steam coal accounting for 2.82 MT and coking coal 1.00 MT.

Compared with the previous week (21–27 June), overall imports declined marginally as a sharp recovery in thermal coal shipments offset a steep correction in metallurgical coal imports. Steam coal imports increased by more than 43% week-on-week, while coking coal arrivals fell by about 51%, highlighting a shift in procurement patterns between the power and steel sectors.

👉 Read the full story: https://indoen.com/news/coal-watch-steam-coal-rebounds-as-coking-coal-eases-amid-diverging-power-and-steel-demand