Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

On August 3rd, something caught my attention. ERCOT had just hit an all-time peak load of over 91 gigawatts on July 22nd at 6 PM — up from the previous record of 85.5 gigawatts set in August 2023. So I pulled up the ERCOT dashboard around 1:15 PM Central and started watching in real time

Projected load for the day: just over 88 gigawatts. I started taking screenshots. As Rod Stewart sang on the first LP I ever bought — when I was 11 — every picture tells a story.

The demand side: new loads are real, and they're only getting bigger

The record growth isn't coming from residential air conditioners running overtime. It's large industrial loads. ERCOT's Large Load Working Group report from June puts simultaneous peak demand from large loads at 3,675 megawatts — a substantial chunk of the gap between the old record and the new one.

But here's what makes that number look almost modest: loads already approved to energize exceed 8,900 megawatts. Tens of gigawatts more sit in the interconnection queue. This story has a long way to go.

The supply mix: what's actually keeping the lights on

At 1:15 PM, with demand around 82 gigawatts and roughly 6 more gigawatts still to climb before the day's projected peak, real-time prices sat in the low $20 per megawatt-hour range. Day-ahead prices weren't much different. On what was shaping up to be one of the hottest days of the year.

Here's how the generation stack looked throughout that day.

Before 8 AM, the grid runs on conventional generation and wind. Nuclear — yellow on ERCOT's dashboard — sits at the bottom and just runs. 24/7, unless there's a scheduled outage. Coal and lignite hold fairly steady in the gray band above it. Natural gas, the purple slice, does the heaviest lifting in the morning. Wind contributes meaningfully overnight and into early morning, then fades as it tends to do in daylight hours.

Then around 8 AM, Apollo rides his chariot into the sky, raining down photons that solar panels across the state convert into electrons — tens of gigawatts of them.

Gas backs down. And the batteries — a rapidly growing fleet of storage resources shown in red — start doing something worth paying attention to: by 8 AM they're absorbing nearly 8.5 gigawatts of solar energy. That's close to 10% of peak load, pulled off the grid and stored for later.

By 1 PM, solar is generating more than 40% of the total mix. Wind sits at 6%. Gas at close to 37%. Coal and nuclear cover the remaining 15% or so. Storage, nearly fully charged, pulls back to nearly neutral — absorbing only 275 megawatts — and waits.

The cowboy hat and the duck

Plot combined wind and solar output over a Texas summer day and the shape is unmistakable. Wind tails off at midday, forming the brim. Solar peaks in the middle of the day, forming the crown. It looks like a cowboy hat. Some days it's more of a bowler or a derby depending on the wind, but the cowboy hat is the signature Texas summer shape.

California has the duck curve. Texas has the cowboy hat. Same physics, different headwear.

Storage: the real story of how this grid held together

By early afternoon, storage is essentially done charging — pulling in roughly 8,500 megawatts at its peak. The small oscillations in the data reflect batteries doing grid balancing work: absorbing and releasing energy in response to frequency signals faster than any conventional resource can respond. That was the original use case for grid-scale lithium-ion batteries, before solar made energy arbitrage so economically attractive.

Then evening comes. Prices rise. And those same batteries inject close to 10 gigawatts back into the grid over the 7 PM to 11 PM window.

The math isn't complicated. Charge at $15-20 per megawatt-hour in the morning. Discharge into evening peaks in the high $40 range. A 10% round-trip efficiency loss doesn't hurt much at that spread

California figured this out first — the original grid with large-scale solar influx. Where the duck lands, batteries follow. Texas is living the same dynamic, just with a cowboy hat instead of a duck.

The uncomfortable implication for gas

This setup — solar suppressing midday prices, batteries filling the evening gap — keeps prices low. Good for consumers. But it's a hostile environment for anyone trying to build new dispatchable gas generation.

Gas plants used to count on price spikes during peak summer days. Those were the windfalls that justified new investment. Now, on one of the hottest days of the year, real-time prices are in the low $20s. Existing gas still runs and still provides capacity the grid needs. But building new gas into this price environment is a hard financial case to make.

The question that actually matters

The current equilibrium works. The grid held up on a near-record day with prices that, by any historical standard, should not have been that low. That's genuinely impressive.

But neither demand nor supply is standing still.

The big variable is AI-driven data centers. Load growth from this sector alone could eventually exceed current total system demand. Governor Abbott added a complication this week, directing ERCOT and the Public Utility Commission to audit new data centers for water use, power use, and tax impacts. That may slow some interconnections at the margin. Significant load growth is likely anyway.

When that demand arrives at scale, the grid needs to add resources fast. The interconnection queue has plenty of renewable assets and some gas turbines waiting to connect.

The problem is transmission. Texas was planning a $33 billion expansion of a 765 kV superhighway designed to serve data center loads and the Permian Basin's growing oil and gas industry. Conservative landowners are fiercely opposing it. Several leading politicians are backing them, calling for transmission applications to be denied until all concerns are addressed.

No transmission means stranded resources in the queue can't reach load. Supply can't connect. Demand keeps growing. The stability and low prices we're looking at today start to look like a brief window rather than a durable condition.

That's the real story from August 3rd. Not just that Texas broke a record, but that it did it without adding meaningful fossil fuel capacity, while keeping prices remarkably low. The harder question is whether the infrastructure decisions being made right now will allow that to continue when load growth arrives in force. The pictures from that dashboard were encouraging. What comes next is less certain

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

I have to admit: my past predictions about Vehicle-to-Grid (V2G) and Vehicle-to-Everything (V2X) technology have been way off base and far too optimistic. I really thought that by now, with gigawatt-hours of batteries on wheels sitting idle 95% of the time, the economic imperative of utilizing that storage would have smashed through market barriers like a battering - or should I say battery - ram.

Unfortunately, that hasn't been the case.

Where V2G Actually Works (For Now)

The best use cases so far come from the fleet side. Look at Zum, the bus leasing company. They have 74 electric school buses in Oakland delivering 2 gigawatt-hours of energy annually back to PG&E, and they're launching another 104 bidirectional buses in San Francisco to add 3 gigawatt-hours more. That's enough to power 1.2 million homes for three to four hours.

School buses are perfect for this: they run on fixed, predictable schedules, they take summers off when grid demand peaks, and you have megawatts of batteries parked at one location under a single decision-maker.

Personal vehicles are another matter entirely. They're spread out, and every driver has their own schedule and mobility needs.

The 5 Pillars of Personal V2G

To make V2G work at scale for everyday drivers, five things have to align:

1. The Vehicle: It needs a bidirectional battery architecture backed by an OEM warranty.

2. The Hardware: You need equipment that can pull DC power from the battery and convert it to AC for the grid.

3. The Software: Smart transaction software is what keeps a grid event from leaving you with an aerodynamic paperweight when you actually need to drive.

4. The Economics: There has to be a clear financial opportunity to sell services back to utilities or wholesale markets.

5. The Trust: Owners have to believe the system works and that they'll actually benefit.

The hardware cost bottleneck - and Ford's genius hack

Right now, hardware is the biggest bottleneck. GM has over 250,000 bidirectional-capable EVs on the road. At 10 kilowatts of export capacity each, that's 2,500 megawatts of nameplate capacity sitting on wheels - at a time when data centers are fighting over every single kilowatt.

But GM's bidirectional charging equipment costs between $7,000 and $8,000 before installation. No utility program or power market revenue stream is going to make a homeowner whole on that upfront cost.

Ford, though, just showed what's possible. They announced a setup that lets F-150 Lightning owners run a single connection from the truck's 240-volt outlet straight to an approved GenerLink transfer switch near the utility meter. It runs about $1,100 plus $250 to $450 for installation, and 800 utilities have already approved it.

To put that in perspective: I recently spent over $13,000 to install a natural gas Generac backup generator at my home in coastal Massachusetts. If I had an F-150, I would have jumped at Ford's $1,100 option without a second thought.

The utility communication breakdown

Ford's hardware solution is a great start, but the utility programs designed to incentivize V2G are still falling flat.

Take the recently announced joint V2G pilot in Massachusetts from Eversource, National Grid, Sunrun, and others. The program reportedly pays $275 per kilowatt during the summer season, locked in for five years. That's solid.

But try finding those details on the utility websites. The press releases hyped the launch hard, then sent you to pages about thermostats and home batteries - not EVs. The actual details on costs, installation, participation frequency, and how to avoid getting stranded are practically invisible. They bombed the communication effort with the one party that matters: the consumer.

The golden rule of demand response

When I ran Constellation's Demand Response Group - which became the second-largest virtual power plant in the world - I learned one thing above all else: if you want customer participation, you have to make it easy.

Otherwise, the uncertainties stack up and the "hassle factor" wins. If utilities want to tap into the massive bank of mobile batteries sitting in our driveways, they have to eliminate the friction. Until they do, V2G will stay stuck on the runway. Or in the driveway.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

Capacity auction results for PJM’s 2028/29 delivery year were consistent. Once again the $325/MW-day price cap was hit. And once again, the desired quantities of capacity fell short of the amount deemed necessary to meet PJM’s planned reserve margin of 20%.

The amount of capacity that cleared the auction was 149,181 MW, 6,831 MW below PJM’ desired 20% reserve margins to ensure grid reliability under worst-case conditions. The shortfall increased by 300 MW from last year.

The total level of new supply was just under 525 MW.

PJM also ran a simulated auction absent the price collar and in all markets except Chicago, the price would have cleared at close to $555. The Chicago area would have been almost $777/MW-day.

That compares to a range of $28.92 to $50 per MW-day for 2022-2025, before massive data center forecasted loads entered the picture.

Data center actual and forecasted load increased costs by $6.3 billion, and by $29.4 over the past four capacity auctions, representing 46% of total capacity-related charges.

The cap stifles potential new investment, which can either go into other markets or into

PJM’s September Backstop Reliability Auction for large loads that pays more and offers longer price certainty.

With turbine manufacturers in sold out positions through 2030, and higher costs to generate power, expect the next auction to achieve similar results: capped prices and limited new supplies.

The big surprise was Demand Response and Distributed Energy resources were also limited. I’m at a loss to explain this one, so perhaps somebody can explain.

FERC chair Laura Swett commented on the supply shortfalls. FERC has scheduled a technical conference on July 23 to address these issues.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

PJM stakeholders – including the electric distribution companies and the Data Center Coalition – OK’d a reliability backstop procurement plan to meet data center demand and address a looming supply shortfall. 

This approach – if approved by the PJM Board and then by the FERC – would have utilities, other load-serving entities, and perhaps the data centers themselves - requesting PJM to access a specific quantity of capacity in a one-time auction. The load-serving entities will then bill large loads for capacity, with average prices capped at $555/MW-day, starting in the 2028/2029 Delivery Year.  Contracts will cover from two to 15 years.

The Reliability Backstop Procurement (RBP) package will use a bilateral auction allowing large loads and suppliers to directly contract for capacity, with specific terms and conditions to be negotiated among the parties 

A Large Load Registry will be established develop the procurement target quantities. 

Pricing will be governed by a volume-weighted average cap, based on the estimated Cost of New Entry - CONE - for the 2028/29 Delivery Year – in other words, what it will cost to bring new gas-fired supply on in about two years. That cap is set 

Note that this number is considerably higher than the current $325/MW-day cap for the past two capacity auctions and subsequently extended to the next two.  

PJM would commit resources, ranking the offers by volume-weighted price (in $/MW-day, averaged across the contract term based on the resource’s in-service date). It will accepting each offer sequentially from lowest to highest until the procurement capacity target is met or the price cap is exceeded. 

In PJM’s example, a total volumetric target of 1,000 MW is used and each tehroetical project has the same duration. So, Offer 1 comes in for 250 MW at $475, Offer 2 for 250 MW at $500, Offer 3 for 250 at $525, and Offer 4 for 250 MW at $600, leading to a weighted average of $525.Under that example, all resources would be accepted. But in my example, if the last offer were to come in at $725, the weighted cap would come in over $556/MW-day exceeding the cap. The auction would end and that final $725 offer would be excluded.

The cap is meant to keep developers from obtaining immense leverage, enforcing competitive discipline so generators don’t get too greedy. But it may simply push capital to invest in supply resources elsewhere. 

There’s another challenge: PJM’s recently issued 70-page white paper Powering Reliability Through Market Design notes that the estimated CONE – upon which the price cap is based – is well below empirically observed prices for new turbines. Since that price was set, the CONE has nearly doubled owing to slow supply chains. 

However, this example should provide a real-world indicator of what’s available at what price, while sending a very strong example to PJM ratepayers as to what capacity prices may look like in the years after the current $325 cap expires.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

FERC issues show cause orders to six regional grid operators, directing them to justify or reform the rules that govern how large energy users connect to the electric grid. 

Large loads – mostly data centers – pose unprecedented challenges to many utilities and grid operators because they are huge, desperate to connect to the grid, and characterized by a high degree of uncertainty as to whether they will ever come to fruition. Phantom loads –– could be as much as 3 to 10x the actual number of projects built. 

The show cause order gives PJM, MISO, SPP, CAISO, ISO-NE, and NYISO and relevant transmission owners 60 days to justify why their current tariffs remain just and reasonable –- without provisions tailored to large loads, or to file tariff changes addressing issues identified by FERC. FERC has initially found that existing tariffs appear to be unjust and unreasonable because they don’t adequately address challenges tied to the integration of large and co-located loads onto the transmission system.

There are five categories:

1)     Developing efficient transmission service application and study processes, including consideration of alternative transmission technologies. 

2)     Two - Preventing cost shifting and requiring transparency into transmission costs

3)     Three - Accommodating co-location agreements and behind-the-meter generation 

4)     Four - Providing new transmission services for flexible large loads 

5)     Five - Developing a process to study generating facilities that serve electrically proximate large loads and co-located loads 

Also, within just 30 days, each entity must submit a report outlining how it will ensure that sufficient future generation to serve both existing and new large loads.

This timeframe is pretty short, but there are many existing best practices to choose from. It’s now time to put some rigor around this process so other ratepayers don’t get hurt.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

A few weeks ago, I discussed the likely emergence of sodium-ion batteries in stationary storage markets, mentioned that Peak Energy might have some potential. I also noted Ford had shifted one of its battery plants from EVs to grid applications. 

Storage is growing. The Solar Energy Industries Association reports in Q1 2026, U.S. battery installations hit 9.7 GWh, a 32% year-over-year jump. By 2030, it expects annual installations of 110 GWh with a cumulative 613 GWh.

SEIA also noted EV factories are retooling to serve the storage market, and the U.S. could hit 120 GWh of cell manufacturing if all facilities come online.

Well, GM just announced that it will manufacture batteries for the grid. And it’s partnering with, and making a strategic investment in, Peak Energy – pushing sodium-ion technology. 

GM’s VP of Battery & Sustainability says with electricity demand rising and data centers consuming more power, the battery conversation is changing. Reliability and affordability over long periods of time matter, which is why sodium-ion battery technology is compelling and a defining chemistry for grid-scale energy storage systems in the future. 

The chemistry is cheaper and stable, operating more safely over a broad range of temperatures than lithium-based batteries, and have an estimated 20,000 cycles.

Further, they operate without needing active cooling, so less hardware and maintenance are required.

Kelty also says the tech is immature, meaning there is plenty of room for future improvement.

GM plans on prototyping sodium-ion cells for stationary storage by the end of 2026, with a goal commercialization by 2028.

Coincidentally, the American Battery Leadership Coalition, an industry coalition dedicated to establishing sodium-ion batteries as an technology in the U.S. launched today. Its mission is to advocate for federal policies supporting sodium-ion battery technology. It says that American companies already have 15 GWh of planned sodium-ion storage offtakes. 

With the GM- Peak announcement, perhaps that number will advance more quickly.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

The Electric Reliability Council of Texas (ERCOTs) has 438,000 MW of large loads seeking interconnection to the grid. 

There are many speculative projects, as well as significant global supply chain limits, so many won’t materialize.

ERCOT planners have been struggling to address these volumes, but new – mainly data center - applications have come in so quickly that planners have been overwhelmed. 

Til now, utilities conducted individual studies, later reviewed by ERCOT, to evaluate impacts on power flows and need for transmission upgrades. With so many applicants arriving, study outcomes kept morphing, requiring follow-on evaluations led to growing backlogs.

So, in March ERCOT developed a batch planning process, assigning projects over 75 MW to a group, and evaluating the system impacts of the aggregation. Stricter eligibility criteria require stronger proof of project maturity and financial strength.

The goal is to speed up the process, making it more efficient, transparent, and equitable, and weed out weaker speculative projects that drain scarce planning resources. 

ERCOT’s board voted to proceed, with the first study to be called “Batch Zero.” A Public Utility Commission of Texas confirmation vote is scheduled for June 18. 

If approved, Batch Zero will kick off a continuous batch study process for future large loads, similar to the “cluster” interconnection approach for new supply assets in power markets.

To join Batch Zero, developers must submit project information to their utility by July 10th, confirming control of sites – with lease or ownership of property - while also disclosing any additional interconnection requests in ERCOT or elsewhere – to avoided double-counting. They will also have to show regulatory approvals and anticipated engineering services, while posting a $50,000 deposit per MW of new load.

By January 29, 2027 ERCOT will publish the Batch Zero Interconnection Study, including annual capacity allocations to each applicant through 2032, suggested transmission improvements, and related Contribution In Aid of Construction (CIAC)costs to be paid for these upgrades. 

By March 1, the interconnecting large load entities must formally accept their capacity allocations. 

By June, ERCOT will deliver an iterative refinement study, finalizing exact transmission facility improvements and cost estimates required for the committed load.

Then developers will sign interconnection agreements with the transmission and distribution utilities and pay a non-refundable interconnection fee of $50,000/MW. Large loads will also have to cover all direct CIAC costs so that other ratepayers are not affected. And utilities cannot start any infrastructure upgrade work until the CIAC is paid. 

These stringent Batch Approach requirements should help weed out speculative phantom loads and tell us a lot – both in ERCOT and perhaps extrapolated more nationally – about which loads are real and which are speculative. 

The process may also provide some valuable lessons to other utilities and grid operators – all of whom, having never seen loads of this magnitude or with such urgency to rapidly connect - are pretty much making this up as they go along.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

Sodium-based battery chemistries are more stable than other lithium systems such as lithium iron phosphate (LFP) or nickel-manganese cobalt (NMC), can operate safely over a much wider range of temps, especially cold weather, and have extraordinarily long cycle lives – up to 20,000 cycles, vs about 7,000 for lithium iron phosphate and 2-3,000 for NMC batteries. Sodium batteries are also inherently less costly than lithium-based tech. Estimates are that when the industry isfully scaled, a sodium ion battery will have ~25 to 30% lower material costs than a comparable LFP battery.

The biggest drawback is energy density, at around 175 Wh/kg, compared with about 205 Wh/kg for LFP batteries and 255 Wh/kg for NMC batteries. But weight is not an issue for stationary storage and the storge industry is so large that new technologies can evolve specifically for the grid.

This new dynamic is illustrated by Ford Energy repurposing its originally designed EV battery factory to addressing the storage opportunity

A remaining U.S. is Peak Energy, with a multi-year agreement with developer Jupiter Power for up to 4.75 GWh of sodium ion battery energy storage systems. Peak has 

Also shipped its first sodium batteries to be used in a shared pilot with nine utility and independent power producers. 

But China - specifically Contemporary Amperex Technologies (CATL) is setting the pace. It leads in batteries globally with nearly 40% market share and 23,000 R&D employees. And it announced a 60 GWh sodium-ion cooperation agreement with Chinese firm HyperStrong for technology R&D, product applications, and project deployment.

Sodium-based battery chemistries are about to mainstream in the electric power industry, first in China, and the in other countries.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

In recent years, a few technologies – besides your obvious fusion and modular nukes –have teased us into thinking that commercialization might be just around the corner.  One of those is solid state batteries, and another is the perovskite solar cell. 

These are solar cells made from the mineral perovskite - a calcium titanium oxide and they are promising because they can be easily deposited onto most types of surfaces, even flexible or textured ones. Perovskites can capture certain spectra of sunlight not typically harvested by typical PV panels. If you add perovskites on top of PV modules, you can build a more efficient solar sandwich.  

These hybrids can increase typical PV efficiencies from 22% to 28 or 30%, which may not sound like much, but if you can boost relative performance by 25% or more, translates into cost savings - especially for land and racking structures.

However, perovskites have been difficult to work with in creating durable solutions that match the 20-25 year lifespan of PV panels. They’re more fragile, and susceptible to the presence of high heat, high humidity and UV light. 

Recent announcements are cause for optimism. Tandem PV is building a 65,000 sq foot factory in California that will layer Tandem’s perovskite glass over conventional PV to boost efficiencies into that 30% range. It plans to prove that it can manufacture perovskites on high-speed assembly lines, a big challenge to date.

And U.S. start-up companies Caelux and Solx announced a five-year strategic partnership to integrate Caelux’s perovskite glass into Solx panels, bringing 3,000 MW of modules to market, with estimated conversion efficiencies of 28%. The companies plan to deliver commercial volumes by next year.

In addition, the DOE announced it is developing performance and durability targets for hybrid perovskite PV panels to be finalized this year. It will also collaborate with national laboratories to develop a bankability framework, creating greater confidence among potential investors and insurance companies.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

A Tale of Two Eastern Grids

Grid operator PJM has revised its interconnection process to improve certainty, speed, and discipline of project review. 

Interconnection queues require proposed project to be studied at multiple levels to asses impacts of new projects on existing power flows, need for new transmission infrastructure, costs, and potential impact on neighboring systems. 

PJM’s review process took as long as 5-7 years, and at one point the grid operator simply stopped taking new applicants. 

A large part of the issue arose from the larger numbers of smaller solar, wind, and battery storage projects applying.

There was also a lot of speculation as developers put different projects in queues across the country; if one got approved, they’d pull the others. 

As an side, the demand side for the data center interconnection queues is very similar, so you have huge amounts of phantom load inflating data load capacity numbers by an estimated 3 to 10X. 

Back to the supply side: The old approach involved a first-come, first-served model, and didn’t require much proof of financial viability.

Now, PJM has a “first-ready, first-served approach,” prioritizing projects that are more advanced with a better chance of actually being commissioned. 

Projects must also show proof of financial viability prior, including up-front financial commitments and a demonstration of project site control.

The deadline for new applications closed on 4/27, and PJM announced it had 220,000 MW (220 GW) of name plate capacity in new applications, representing 811 projects. Gas-fired gen led the mix, with 106 GW of nameplate capacity and 157 projects, followed by energy storage, with 66 GW offered by 349 projects. Perhaps surprisingly 27 nuclear projects were in the mix, with an associated 18 GW of capacity, followed by 15 GW of solar and 9 GW of solar storage hybrids, together totaling 187 projects. 65 wind projects also made the list, responsible for 4.7 GW of capacity.

PJM must now validate the applications, and it will deploy Google subsidiary Tapestry’s “HyperQ” AI-enabled software to improve efficiencies by reviewing data associated the interconnection process, while expediting the study process.

Not all of the approve projects will come online anytime soon. For example, Commonwealth Fusion is in the queue and it doesn’t even have a working demo fusion reactor yet. 

And the gas projects may find turbines unavailable as suppliers are largely sold out through the end of the decade. PJM also notes that state permitting processes slow things down. 

PJM wants to get much needed supply online, citing an expected increase in demand of 30 GW between 2024 and 2030, driven largely by data center loads. So, they are planning on a one- to two-year review process, depending on individual project impact.

Meanwhile, looking further northeast, ISO-NE is also eyeing changing demand, but it is forecasting a reduction from previous numbers. It doesn’t expect much data load, with demand anticipated instead from EV sales and heat pump deployments – both of which have recently slowed. The grid operator has cut its forecast a couple times, from 17% over ten years in 2024 to 9% over ten years in its most recent 2026 outlook. 

The region’s net annual energy use has actually trended downward over the past 20 years, owing to more efficient technologies and the growth of on-site solar power. 

This stuff is heard to get right in a world in which everything is constantly in flux. Let’s take the Strait of Hormuz. If it stays blocked for another two months, an enormous economic petroleum energy shock could occur. Then, EV sales could boom again and anybody using oil heat in New England will race for heat pumps. In this world, it seems we – and grid planners - can count on little else besides the accelerating pace of change.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

I recently wrote an opinion piece for RTO Insider addressing a fascinating new metric that captures the interaction between AI data centers and power markets: the Compute Heat Rate (CHR). These data loads have mushroomed into what can only be described as "stupid land". Consider ERCOT, where the record peak demand set in August 2023 was 85,500 megawatts. The grid operator's latest forecast projects 2030 load to max out at an astonishing 319,650 megawatts—a figure that would drop to 107,000 megawatts if large and medium-sized data loads were excluded.

In response to this critical supply and demand issue, many regulators and politicians are demanding that data loads offer flexibility to avoid pressuring the system peak. The Electric Power Research Institute recently rolled out a proposed framework called "Flex Mosaic" to create common approaches for demand response from these massive facilities. In Texas, Senate Bill 6 even stipulates that data loads can be cut off during grid emergencies before rotating blackouts are enacted.

But while regulators focus on capacity and emergency curtailment, energy markets are driven by price. Industry veteran Hans Royal recently published a paper introducing the CHR to ask an essential question: at what maximum electricity price would a data center operator rationally elect not to consume power?

Here’s the problem: The enormous economic value created per megawatt hour by AI makes these data centers incredibly inflexible.

Traditional large loads, like aluminum smelters or steel producers, provide a self-correcting price mechanism in the market by curtailing operations when power costs reach between $40 and $120 per megawatt hour. AI data centers operate in a completely different universe. Royal estimates a blended CHR of approximately $6,350 per megawatt hour, implying that AI demand will not curtail at prices below roughly 127 times the current wholesale average.

It becomes even more extreme when you separate AI training from AI inference. While the continuous training of a large language model might see a CHR around $500 per megawatt hour, just-in-time inference services—which deliver high-value information for trading, logistical planning, or robotics—could have a CHR exceeding $53,000 per megawatt hour.

The likely outcome is that these massive loads will not curtail at any price level currently observed in US wholesale markets. As data center infrastructure reaches critical mass at specific grid nodes, they will be willing to significantly outbid all other loads to establish locational marginal prices.

With new technologies like the Nvidia Rubin architecture packing the peak power draw of 65 households into a box the size of a refrigerator, this presents massive new demand. This approach will have collateral impacts on other electricity consumers, who may soon find themselves priced out of various markets. It might be that it’s now AI’s grid. We only live - and consume and pay for electricity – on it.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

On Friday, April 11th, PJM took another step to meeting the rapid growth of large - principally data related - loads.  These loads have mushroomed up quickly. Consider in May of 2024, AEP Ohio served 600 MW of data load. Today it has 11,000 MW. Dominion has 25,000 MW of large load with connection dates through December 31, 2031, and an additional 45,000 MW of large-load interconnection requests.

In response, PJM proposes a one-off procurement process for 14,900 MW of new capacity to serve large loads. With the assistance of consulting firm Charles River Associates (CRA), PJM would facilitate a bilateral contracting process between large loads and supply from September through next March. 

Qualifying resources include new generating projects, capacity up-rates on existing power plants, repowered generators that have been deactivated, as well as new demand response and distributed energy resources. Delayed power plant retirements are unable to participate. 

PJM and CRA will serve as intermediaries, and provide match-making services, with contracting parties would setting terms and conditions, and contracting out of PJM’s purview. 

The concept arose from the January White House meeting with the 13 PJM states, a meeting to which the grid operator and data center companies were not invited.

Here’s the problem: Turbine supplies are limited and wanted all over the world.

Then there’s the $325/ MW-day price cap for the next two PJM capacity auctions. Developers are unlikely to bid into the BRA and accept a capped capacity price for only a single year, when could bid that new resource into a bi-lateral auction and fix a price for 2 to 15 years. Especially when data companies are willing to pay nearly any price. 

The likely outcome is that little to no new capital focuses on serving existing PJM capacity markets. 

This approach may have collateral impacts to other parties in PJM. It might be that it’s now AI’s world. We only live - and consume and pay for electricity – in it.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

In 2016 the Aliso Canyon storage reservoir began leaking gas, which was needed to supply southern California’s peak electricity demand. Within months, over 77 MW of battery storage was installed and commissioned - the fastest new capacity ever been brought online.

Soon, industry leaders referred to battery energy storage as the “Swiss Army Knife” of energy. Lithium batteries can provide multiple services, from capacity to forward reserves and frequency regulation. 

As more solar energy flooded the system and cut energy values mid-day, batteries moved nearly valueless solar energy and delivered it into evening peaks when prices were often two to three times as high. 

Today, nearly half of all utility scale solar projects are hybridized with storage. Batteries don’t pair as well with wind energy that doesn’t have the same predictable output. 

“Storage as transmission” saw batteries in transmission-constrained areas absorbing energy when there were no transmission limitations, and energy released on the far side of the transmission constraint when needed.

Storage is also in the distribution system, supporting stressed grid assets during peak periods. It’s in residential and sometimes commercial markets, especially California: rooftop solar sent back to the grid is valued at next to nothing; it makes economic sense to store the energy and consume it later, avoiding paying over 30 cents per kWh. 

There’s also a new and rapidly growing market for batteries with data centers having difficulty connecting to the grid. Data centers add on-site batteries and serve loads from storage during system peaks, enabling faster interconnections. 

This matters: one analyst recently commented that accelerating interconnection of a 1 GW of data center for one year may be worth $7 bn. 

So, what does the market look like these days and where might it be headed?

Consulting firm Wood Mackenzie and American Clean Power recently issued its U.S. Energy Storage Monitor report, observing that over 50 GW and 144 GWh of energy storage has been installed in the U.S. since 2019. 

A record 18.9 GW and 51 GWh were installed in the U.S. in 2025.

Looking forward, WoodMac projects about 500 GWh of storage to be added between now and 2031, with a wide high-low variance of 52 GW of capacity by 2031.

As more variable renewables are added, the challenge of resource adequacy – balancing growing demand with supply – grows. Utility planners must think about “renewable energy droughts,” e.g., a five-day rain event deluging California cutting solar output >50%, or a snowstorm covering solar panels for days. No wind for a few days is also an issue. Longer-duration storage will be needed to firm up those resources.

Some long duration technologies – compressed air, liquid CO2,  liquid air – all of which require compressors and lose roughly 30% of the energy with each cycle - may be gaining strength, with commercial projects being announced. 

In California, Hydrostor is developing a compressed air energy storage designed at 500 MW and 4,000 MWh. 

Italian start-up Energy Dome is using liquid CO2, with a signed contract with Alliant Energy for a 20 MW 10-hour duration project to start construction this year in Wisconsin. In the first week of April, Dome signed an MOU with New Era Energy & Digital, Inc. to support its Texas Critical Data Centers site in Odessa. Energy Dome also has an agreement with Google that will likely include multiple projects across a global footprint.

Highview Power – a liquified air storage company, expects a 50 MW, 300 MWh project in Manchester, England to start flowing power this year. A project in Scotland will is planned to deliver 300 MW and 3.2 GWh, coming online between 2028 and 2030.

Some large pumped storage hydro projects are planned, but take years to permit and build, with none expected online until the 2030s. 

Form Energy uses an iron-air battery technology with 100 hours of durations (though with 40% roundtrip efficiencies). A recent announcement with Xcel Energy and Google has 300 MW and 30 GWh coming online in phases between 2028 and 2031. An even more recent deal is with Crusoe for 120 MW and 12 GWh, with deliveries starting next year. Those two deals cover 80% of last year’s total U.S. GWh storage additions.

By 2028, Form plans on 500 MW and 50 GWh of annual factory output, and plans further expansion plans, with past presentations suggesting expansion by 10x.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

Leading AI chipmaker Nvidia and software company Emerald AI will work with a number of energy supply companies to “power and advance a new class of AI factories” that can connect to the grid faster and “operate as flexible energy assets that can support the grid.”

The approach will use a new reference design with Nvidia’s latest chip and its DSX software to help manage power use in real time, modulating demand and coordinating flexible load.

Nvidia envisions factories using on-site, co-located generation and storage as a bridge before they connect to the grid, and then on-site assets will “flexibly support the grid.”

Emerald AI’s Conductor platform will orchestrate computational flexibility, combined with onsite resources to deliver power flexibility.

“Power-flexible AI factories” Nvidia claims, “can help unlock up to 100 gigawatts of capacity across the U.S. power system.”

For perspective, the U.S. hit an all-time peak of 759 GW last July, and has 1,300 MW of installed generating capacity.

Data center flexibility is important because there’s limited transmission and supply available on the grid and new infrastructure can’t be built fast enough.

Plus, the grid has an estimated load factor (the percentage of the energy we use versus the amount we could use if we ran at 100%) of about 60%. It’s very inefficient.

Supply also gets expensive. PJM’s capacity market prices have soared 7 or 8x over average historical numbers, with data loads costing ratepayers an estimated $23 billion in the past three capacity auctions.

By creating more flexibility during grid scarcity, one can meet more demand without building new infrastructure, AND flow more energy across the same grid, lowering the per unit delivery price.

Two recent studies on flexibility suggest that flexible operations can greatly increase ability to add load and result in economic efficiencies: 76 GW of new load could be integrated with just an average annual load curtailment rate of 0.25% and 98 GW of new load could be integrated at a curtailment rate of .5%.

And avoiding just 1% or 2% of the peak hours would reduce utilities’ new natural gas combined cycle construction costs by 10% to 15%.

But the available information doesn’t really tell us all that much. We don’t how flexible the operation of large language training models will be, nor do we know the potential flexibility in the inference function, where the models perform on demand to undertake the work new need on a daily basis.

We have limited empirical data: an EmeraldAI data center in Arizona cut

power consumption by 25% during three hours of peak grid demand. As of late March 2026, Emerald AI confirmed it has demonstrated power flexibility capabilities at five different commercial data centers around the world. But actual performance numbers are limited, for durations and percentages.

Likewise, Google announced it has surpassed 1 GW of demand response but didn’t share the details that matter.

If AI data centers are anxious to connect to the grid, flexibility and ability to curtail should be a pre-requisite. And treated cautiously.

Grid operators such as PJM don’t have the availability to enforce precise real-time load curtailments for individual data centers in real-time, so the system risk is large.

If only 10% of forecasted data loads don’t curtail power during a grid emergency, the shortfall could cost billions.

The PJM Independent Market Monitor states that data load bring their own new generation, which could speed up interconnection. Without it, they should be curtailable before other current demand side customers, and not be paid as demand response – this should be a pre-condition for interconnection.

In summary, the Nvidia Emerald AI and Google announcements on flexible load are interesting, and the economic incentive and technical potential may be there. But we don’t know how it will work, at what scale, and for how long. Until we do know, significant skepticism and caution is warranted.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

In early March, mid-Atlantic grid operator PJM Began using Ambient Adjusted Ratings to better determine how much power can flow through its lines based on actual weather conditions. In addition, the DOE announced it will award billions for quick and effective upgrades to the transmission system.

First we have to fix the broken interconnection issue. For all projects seeking interconnection to the grid from 2008 through 2019, only 19% of the projects actually flowed power by the end of 2024. The typical project built in 2025 took 55 months to get through the queue, compared with 36 months in 2015. 

But even if all of that new supply capacity could be processed through interconnection queues, there are simply not enough transmission lines to accommodate the planned resources. And few new lines are being built: less than 1,000 miles of 345 kV+ transmission lines were completed in 2024 – far less expansion than is needed, especially in the face of enormous new data center demand.

The biggest challenge is permitting for new rights-of-way, which can take well over a decade. There is a glimmer of hope that the federal government may reform the permitting process prior to the mid-terms, but it’s unlikely. 

Grid-enhancing technologies, or GETs, can offer some relief by doing more with existing transmission. In addition, there is the growing potential for reconductoring. 

The GETs technology with the greatest near-term is dynamic line rating, or DLR. As power lines move more power, they heat up. Lines are limited in terms of how much they can energy move by static ratings, based on worst case weather assumptions, such as 100 degrees F with no wind.

Such conditions rarely occur, but with static ratings flows cannot exceed those pre-set amounts. Most days, one could move much more power through that line, if one were 

using DLRs - a combination of software and sensors. DLRs measure ambient temperatures and wind (wind wicks lots of heat away from the line, as well as how much sunshine is warming the wires. Sensors also measure how much the wire is physically sagging at any given moment. This information helps operators move more power without hitting “thermal violations.”

A 2024 case study showed static ratings could be exceeded 100% of the time, with average capacity increases of 81%. In summer, one could exceed the static ratings 94% of the time, with average increases of 27%. 

A less capital-intensive approach that doesn’t require physical sensors and uses weather data, but also fails to measure the impact of wind, is called Ambient Adjusted Rating or AAR. AARs automatically predict transmission line capacity on an hourly basis. 

The Federal Energy Commission’s 2021 Order 881 mandated AARs for grid operators by July 2025. But nobody met that deadline. PJM was first, going live on March 4. It will use hourly ratings from real-time to as far as 10 days out and  employ monthly seasonal ratings for longer-term studies 12 months out. 

Meanwhile, the DOE announced funding of approximately $1.9 bn to “accelerate urgently needed upgrades to the nation’s power grid.” The DOE specifically calls out reconductoring –stringing new and more efficient lines along the same or upgraded poles. 

Since rights of way are the single largest limiting factor to expanding transmission capability, it makes sense to fully exploit existing ROWs. Reconductoring can cost-effectively double transmission capacity within existing ROWs and save billions.

We’ll still need to build many new transmission lines. But it will take many years for new lines to get built. In the meantime, it’s essential to do as much as possible with the infrastructure we have. These two recent developments are a start. 

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

The US solar industry installed 43.1 gigawatts-direct current (GWdc) of capacity in 2025, down 14% from 2024. 

GWdc is the nameplate rating of projects before they connect to the grid through inverters converting direct current (DC) to the alternating current (AC) our grid uses. 

Two elements lower DC ratings to AC ratings. First, inverter losses are around 4% losses. 

More importantly, solar panels have specific output duration curves; there’s only a very small period when they produce maximum output, or even 80-90%. 

It’s uneconomical to buy an inverter rarely hitting full MW ratings, so developers resort to “solar clipping.” A a 100 MWdc solar array might see inverters delivering a max 80 MW of AC power to the grid. Typical DC/AC ratios are1.1 to 1.25. 

So, MWdc numbers must be translated to the real world MWac of the grid

But all capacity is not the same: a MW of solar capacity has two factors differentiating it from, say, a MW of gas-fired generation.

First, solar operates at a different capacity factor (a resource operating at 100% output all year would have 100% capacity factor). An average panel capacity factor is 25%, compared to 60% for a combined cycle gas plant. So, it’s best to think in terms of energy generated. It also matters where panels are located. Massachusetts is 16.5%, while Arizona is 29%. 

One way to compare is by energy output.  Solar is now approaching 10% of total energy contributed on the grid. And you can put in solar arrays faster than new turbines. With data center demand, we need all the electricity we can get. 

However, the solar is not dispatchable. It only shows up when the sun shines, while the gas plant can be called upon anytime, except sometimes in extreme weather. 

In 2024 mid-Atlantic grid operator PJM down-rated combined cycle turbines 96% to 79% in terms of their ability to meet peak demand on the worst hour of the worst day, and recently lowered that rating to 74%.  But PJM has solar at only 7%. 

When you hear about solar in terms of MWdc, , it helps to reframe those values using the above information.

Nonetheless, solar has grown considerably. In 2009, about 1 GW – 1,000 MWs of solar was added iomn the U.S. That total is now 279 GWdc, and analyst Wood Mackenzie forecasts an increase of 490 GWdc over the next decade. 

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

Xcel Energy announced a deal to supply a new Google data center in Pine Island Minnesota with renewable energy. The utility said it was committed to ensuring that new large loads do not negatively affect other ratepayers and that this Clean Energy Accelerator Charge (CEAC) would help meet that commitment, with 1,400 MW of wind and 200 MW of solar. 

The CEAC also includes a $50 mn investment in Xcel’s Capacity Connect program, a unique effort in which it will develop and own up to 200 MW of distributed storage assets, with between 1 and 3 MW of storage at local commercial, industrial, and institutional sites.

Storage is also part of the huge Google deal, with a technology at a scale the world has never seen before: iron air batteries from Form Energy, with 300 MW at 100 hours of duration, totaling 30,000 MWh. This single project represents a little over 50% of the entire battery energy storage duration installed across the U.S. in 2025.

Iron is abundant and it’s cheap, but it has taken the company many years to get to this point, manufacturing, testing and validating the technology. 

Form bought and rehabilitated an old steel mill in W Virginia – with annual output of 500 MW when fully built out. The Google deal will take 60% of one year’s capacity. 

Unlike lithium-ion batteries, that typically operate at 90% round trip efficiencies, losing 10% of the energy during each cycle, or pumped hydro that often sits in the mid 70% range, Form has a low 40% RTE. 

Nonetheless, 100 hours of duration, if delivered reliably, at low cost, and in enormous quantities, has the potential to be a game changer in integrating more variable wind and solar to decarbonize the grid and meet the huge demand from data centers.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

The last few weeks have seen numerous announcements by U.S. fusion energy companies.

First, let’s briefly explain fusion. With fission, you take a heavy and unstable nucleus and split it into two smaller nuclei, releasing energy and creating a chain reaction.

With fusion, you cause two light nuclei (usually hydrogen isotopes) to collide and merge into a heavier nucleus (such as helium), releasing energy. The sun is an enormous fusion reactor.

For commercial fusion, you need three things: 1) temperatures high enough (around 50 to 150 million °C) so nuclei move fast and fuse frequently; 2) sufficient density creating more opportunities for nuclei to collide, fuse, and release energy; 3) the ability to confine the reaction, keeping the plasma dense and hot enough to yield a net energy output.

Plasma itself is a state of matter in which a gas is highly energized so its atoms have lost one or more electrons, creating a mix of free electrons and ions.

Confinement of plasma can be achieved with the inertia of a compressed pellet or by using magnetic fields.

The pellet confinement approach - inertial confinement fusion, or ICF – is achieved by compressing a small fuel pellet (typically hydrogen) rapidly and with high density so it fuses before it can break apart.

With magnetic confinement, two main technologies exist: 1) tokomaks – donut shaped devices combining magnets with electric currents in plasma to construct a sort of magnetic cage; and 2) stellerators – machines employing magnetic coils that yield twisted magnetic fields requiring less currents in the plasma. Companies are pursuing approaches along these two main lines, with the majority using the magnetic approach.

The major recent technical achievement was Helion’s announcement that it had achieved plasma temperatures of close to 150 million degrees C.

On the commercial front, Type One Energy and the Tennessee Valley Authority are advancing licensing and construction plans for a 350 MW stellerator fusion plant, with groundbreaking as early as 2028.

Regarding licensing, Thea Energy received the first Department of Energy certification for its pilot stellerator design.

In financing, Avalanche Energy received $29 million in new investor funding, following significant breakthroughs in plasma physics, to support licensing, commercial-scale operations, and a test program. Avalanche is developing a tiny fusion reactor between 1 and 100 kW, “small enough to sit on your desk.”

Inertia Enterprises also raised almost $450 million to construct powerful lasers, as well as a power plant slated for 2030 commissioning.

Meanwhile, General Fusion announced an agreement to go public at about $1 billion through a SPAC this spring.

Of course, challenges await all of these companies: technological issues, licensing, supply chain, and the critical need to deliver electricity at a competitive price.

Investors are interested. Through the middle of last year, the industry received almost $10 billion in funding, and billions have since been invested.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

Let’s explore the complexity associated with keeping the lights, using New England as an example. The region is a bit of an outlier because of its proverbial end-of-the-pipeline location. Most days, its two pipelines are sufficient to heat homes and generate power. But late January to early February was unusually cold and there was not enough gas for both.

We’ll look at both energy and capacity issues. Capacity is the instantaneous amount of electricity produced or consumed. Energy is a function of capacity times the duration.

The hottest and coldest days are the ones in which we stress the grid the most – because of heating and cooling demands.

Annual grid peaks typically occur in summer, around 5:00 or 6:00 PM. So grids need enough generation to meet the peak demand, plus a back-up reserve margin, in case we lose a big power plant or transmission line.

Until recently, ISO-NE only paid attention to summer peaks, when the system maxed out. But recently, it began to shift its attention to the winter as well. First, because new loads, especially EVs and heat pumps, have higher winter demand. Second, there’s not enough gas to go around.

Fortunately, from a reliability perspective, the region’s dual fuel turbines can burn fuel oil or kerosene, and even jet fuel. So the focus shifts to energy, because the amount of stored liquid fuels is limited, though it can be replenished – especially if weather cooperates. During the frigid cold snap in 2017/2018, New England started with 5 million barrels of oil and ended with only one, in one case burning a million gallons in a single day.

During the extreme cold this January, fuel oil was the leading source of generation for several days, constituting over one-third of operating generation.

One new resource just commissioned was the 1200 MW New England Clean Energy Connect (NECEC) transmission line, bringing hydropower from Quebec to Massachusetts with a contract for an annual 9,555,000 MWh. The NECEC line was expected to help address winter capacity and energy issues.

But last week, no power was flowing into New England over that line on the coldest days. On the frigid Sunday before the storm, power flowed for only a single hour, with the line operating at about half its capacity. The following day, at around 6:00 in the evening, electricity started flowing again at about 25% - this despite penalties for non-delivery.

However, the contract does provide a measure of relief to those oil supplies in the long run. Today, January 3rd, the temps are in the mid-20s. The region continues to burn oil, at 23%.

But net imports right now, including the HQ NECEC contract, make up 16%.

That electricity represents expensive oil inventories we are not burning. Offshore wind – Vineyard Wind has helped as well.

So does rooftop solar, cutting demand by up to roughly 3,500 MW for a good chunk of the day – that’s also largely fuel oil we don’t have to burn. Which matters, since the forecast for the weekend is for wind chills dropping into the negative teens on Sunday night.

It’s clear over-reliance on a single source of supply is a risky strategy, and an all-of-the-above approach helps keep the lights on during those coldest of days.

Energy Future: Powering Tomorrow’s Cleaner World

Peter Kelly-Detwiler

Energy Future: Powering Tomorrow's Cleaner World invites listeners on a journey through the dynamic realm of energy transformation and sustainability. Listen to this podcast on:

Listen Now

Three different federal judges overruled the Trump administration offshore wind stop work orders, allowing work to resume. The government failed to demonstrate a national security risk so urgent that construction must cease. PJM filed an amicus brief in support of the project, saying delays could “cause irreparable harm to the 67 million Americans served by PJM…” It noted “national security benefits in the form of a stronger and more reliable electric grid.”

The Administration and a bipartisan group of governors held a meeting and called on PJM to schedule a one-time emergency capacity auction to dedicate supply resources for 15 years for data center loads. Data company officials and PJM were not invited. 

This approach creates two auction structures and risk starving the existing structure, especially if the 2nd auction is more lucrative. 

Two features may be useful, though: 1) a  focus on new marginal supply resources; and 2) a longer term for fixed capacity prices so investors can better assess profitability. 

The Federal Energy Regulatory Commission will need to bless this proposal, and in the interim, this issue will remain highly political.