Why is my electric bill so damn high?

"Never half-ass two things. Whole-ass one thing." — Ron Swanson

"Why is my electric bill so damn high?" — My Dad

1. Thirty cents a kilowatt-hour

When my dad first complained to me that his electricity bills were too high, I assumed he was doing so in the stereotypically hyperbolic way parents do. Then he whipped out the latest bill and my jaw dropped. Thirty cents a kilowatt-hour. How are they generating electricity up there — getting one of those overeducated coastal elite types to run on a treadmill?

My coal-loving father's theory was a bit more believable: that the liberal politicians in New England, and particularly in our home state of Massachusetts, were driving up electricity prices by forcing the grid to take on lots of expensive renewables and cutting back on the cheap fossil fuels that America thrives on.

As a self-confessed climate nerd, I took it upon myself to figure out what was really going on. It couldn't be that simple. Renewables are the lowest-marginal-cost way to generate power on Earth, and their share of the New England grid — just under 7% in 2024 — simply isn't high enough for them to be setting the wholesale price. So what is driving it? I went digging through the ISO's paperwork to find out.

The answer, it turns out, is pretty interesting. It's also pretty damning — not of climate policy specifically, but of the uncomfortable halfway house New England has built for itself. Before we get to that, though, let's figure out how bad the problem actually is.

2. How bad is it, really?

Bad. The kind of bad that has been true for a decade and is getting worse, not better.

ISO-NE — the grid operator that runs the six New England states as a single market — is the most expensive wholesale electricity market in the Eastern Interconnect. It has been for years. And in 2024, the gap between New England and its peers didn't just persist, it widened.

Here are the numbers that matter:

• The average wholesale price in 2024 was $41.47 per megawatt-hour, up 13% from 2023 and nearly double the 2020 average of $23.31/MWh.

• The all-in cost — which includes transmission, capacity payments, and ancillary services on top of the raw energy price — was about $87/MWh. For comparison, PJM, the much larger grid covering everything from New Jersey to Illinois, runs somewhere in the $60–65/MWh range. New England is paying roughly a 40% premium over the nearest mainland peer.

• Total wholesale costs in 2024 came to $10.2 billion, an 11% year-on-year increase — despite the fact that natural gas prices, the usual culprit when wholesale prices move, were essentially flat across the year.

That last point is the one worth dwelling on. If this were just a commodity story — gas prices went up, electricity got more expensive, wait it out — we'd be having a different conversation. But 2024 was a year when gas was cheap, and New England got more expensive anyway. That tells you the problem isn't the weather or the commodity cycle. It's structural.

What you're actually paying for

The $10.2 billion breaks down into three roughly equal buckets, and each one is telling a different story.

Energy costs — the bit that pays generators to actually produce electricity — were $5.6 billion in 2024, up 24% on the year. This is the bucket most directly tied to gas prices, but it's also where carbon pricing shows up (more on that later) and where the cost of losing cheap imports from Quebec lands.

Transmission costs were $3.0 billion, up 11%. This bucket pays for the wires that move electricity from generators to load centres. It's been climbing steadily for years, and New England now spends more than double what comparable grids spend on transmission. That sounds like waste but isn't quite — it's the legacy of decades of reliability-first grid planning that has produced a system with almost no congestion. It's a choice that looked expensive once and now looks expensive forever.

Capacity costs were $1.4 billion, down 22%. Capacity payments are the retainer the grid pays generators to guarantee they'll be available three years from now, regardless of whether they actually run. On the face of it, a falling capacity bill looks like good news — the grid is paying less to keep plants on standby. It isn't. It's the symptom of a capacity market that has comprehensively failed to signal the need for new investment, and we'll come back to it in Section 3 because it's one of the more consequential things going on in the whole market.

Putting it in your dad's terms

So what does $87/MWh mean for an actual person? Rough maths — and this is rough, because the retail bill wraps the wholesale cost in delivery charges, taxes, utility margins, and a handful of state surcharges — suggests that the wholesale cost premium over PJM works out to somewhere around $15 a month on a typical Massachusetts household bill. Not ruinous on its own. But it's been there for years, it's growing, and it's on top of a retail delivery system that's also more expensive than average. The reason the full bill comes in at 30 cents a kilowatt-hour isn't one problem. It's the same problem compounded across every layer of the stack.

And none of this — not the widening gap, not the rising transmission bill, not the 2024 increase in a year when gas was flat — can be explained by renewables being on the grid. Wind and solar are 6.8% of supply. They are not the price setter. They are barely in the room.

The real story has four parts. Actually, five. But we'll get to the fifth one when we get to the politics.

3. The five drivers of annoyingly high prices in New England

If renewables aren't the problem, what is? Four structural things and one policy choice. The first two are physical realities of New England's geography and its relationship with Canada. The third and fourth are the consequences of decades of decisions about how the grid is run. The fifth is a deliberate policy lever that's working exactly as intended — and that's why your bill went up in 2024.

Let's take them in order.

Cause 1: Gas just costs more up here

New England sits at the literal end of America's gas pipeline network. Two pipelines — Algonquin and Tennessee — carry gas south-to-north from the Appalachian basin into the region, and their combined capacity isn't enough to serve both home heating and power generation at the same time during winter. When you also consider that ISO-NE has essentially no underground gas storage to fall back on (the geology doesn't cooperate), you end up with a region that runs out of pipe capacity before it runs out of demand.

The result is a consistent, measurable price premium. Massachusetts pays 2.3 times the US average for natural gas on an annual basis, and as much as 3.9 times the average in peak summer months — $16.38 per thousand cubic feet in August 2024, against a national average of $4.17. When the marginal generator on your grid is a gas plant burning fuel at four times the national rate, you don't need any other explanation for why your wholesale prices look the way they do.

There's a counterintuitive twist in the data that's worth flagging. You'd expect winter to be the worst — that's when home heating competes with power generation for the same scarce gas. And it used to be. But over the last few years, the summer premium has overtaken the winter premium. Why? Because air-conditioning load keeps climbing, gas has taken over a bigger share of the summer generation mix as cheaper imports have collapsed (more on that next), and the system now has two distinct crunch periods instead of one. New England residents are now paying elevated gas prices nearly year-round.

A note on what's causing this: state-level opposition to new pipeline construction in Massachusetts, Connecticut, and Rhode Island — driven by climate concerns and local environmental politics — has effectively foreclosed the option of expanding pipeline capacity. This is one of the few places in the diagnosis where it's fair to say environmental policy is making the bill worse. Whether it's the right trade-off is a question I'll come back to in Section 5.

Cause 2: The Canadians stopped bailing us out

For most of the last two decades, one of the quiet workhorses of the New England grid was Quebec — specifically, the enormous Hydro-Québec system, which provides cheap, dispatchable, near-zero-carbon hydropower that flows south across the border on a few high-voltage interconnections. When that hydro is available, it suppresses LMPs across the entire region. It is the closest thing the New England grid has to free money.

From 2020 to 2022, Phase II imports from Quebec averaged about 1,351 megawatts per hour. By 2024, that had collapsed to 633 MW/hr — a 53% decline. The cause is mostly precipitation: a multi-year drought has drawn down reservoir levels in Quebec, and Hydro-Québec has had to choose between exporting to New England and meeting its own provincial demand. It chose the province. A separate New Brunswick nuclear outage from April through December 2024 took further import capacity offline. The combined effect dragged net imports to 9% of total supply, the lowest level since 2011 and down from 20% in 2020.

Here's the part that compounds the damage. Every megawatt-hour of lost hydro import has been replaced almost one-for-one by gas-fired generation. So the loss of cheap hydro doesn't just remove a low-cost baseload resource — it pushes up demand for the gas that, as we just established, is already 2-to-4 times more expensive than the national benchmark. It's a double hit. The chart below shows what this looks like in supply-mix terms.

There's a small piece of good news here that I'll come back to in Section 4: a new 1,200 MW high-voltage transmission line from Quebec to Massachusetts called NECEC finally went into commercial operation in December 2024, after years of legal battles in Maine. That partly reverses the import collapse. But "partly" is the operative word, and it doesn't address the underlying issue, which is that the New England grid's exposure to weather in another country is now one of the largest single drivers of its electricity prices.

Cause 3: The capacity market is broken

First, a quick primer on capacity markets.

A capacity market is a separate auction, run alongside the energy market, where the grid operator pays generators a retainer fee to promise to be available three years from now — whether or not they ever actually run. Think of it as an insurance premium for reliability. The clearing price is supposed to act as an investment signal: when the grid needs more plants, the price goes up, new generators get built, and the system stays reliable. When the grid has plenty, the price falls. It's a market mechanism designed to do what a planner would otherwise have to do by hand.

Here's the problem. ISO-NE's Forward Capacity Auction has cleared at 67% to 77% below the cost of building a new plant for eight auctions in a row. Eight. The grid has been signalling, year after year, that it has more than enough capacity and nothing new should be built. And in response to that signal, nothing new has been built. Not a single combined-cycle gas plant has cleared the auction in five years.

So how does this push your bill up? It's subtle. The capacity market's failure isn't expensive in itself — capacity payments are actually falling as a share of the total bill. The damage shows up in the energy market. Because no new dispatchable plant has been built in years, the system stays dependent on its existing fleet of aging gas plants, which are exposed to all the gas pipeline constraints from Cause 1. There's no fresh, more efficient capacity coming online to displace them. And the plants that have been clearing the auction — wind, solar, batteries — don't solve the problem the gas plants are solving, which is "be available for five days when it's nine degrees Fahrenheit and there's no wind."

It gets worse. As of 2024, the capacity market has been suspended entirely. The auction that would have covered 2028/29 (FCA 19) was cancelled as part of a major redesign called Capacity Auction Reform, and the next forward auction won't happen until February 2028. For the next several years, there is no investment signal at all. The grid is flying blind on reliability.

Cause 4: We overbuilt the wires

The fourth cause is the most counterintuitive of the lot, and the one I had to read the data on twice to believe.

ISO-NE pays roughly $24/MWh in transmission costs. PJM and NYISO pay about $9-11/MWh. MISO, the big midwestern grid, pays $5-6/MWh. New England's transmission rate is more than double its nearest peer's and roughly four times the cheapest grid in the country.

In exchange for that premium, New England has the lowest grid congestion of any RTO in America — about $0.33/MWh, which is something like 8-17% of the congestion costs other markets see. Congestion is what happens when you don't have enough wires to move power from where it's generated to where it's needed; it's the grid equivalent of a traffic jam. New England, in other words, has built so much transmission that nothing ever gets stuck. The wires are gloriously uncongested. They are also gloriously expensive.

How did this happen? Decades of conservative reliability planning. ISO-NE's local planning criteria are stricter than peer RTOs', and over the years that has produced a steady drumbeat of approved transmission projects, each justified individually on reliability grounds, that collectively built a network with substantially more headroom than the system actually needs. None of it was waste in the sense that anyone built useless wires. Each project, on its own, made sense. The aggregate is just very expensive.

And here's the kicker: it's about to get worse. The next wave of offshore wind needs substantial new transmission to connect to the grid — undersea export cables, onshore substations, network upgrades to handle the new injection points. That transmission is going to be built, it's going to be expensive, and the costs are going to land on consumer bills several years before the offshore wind itself starts displacing enough gas to bring down energy costs. So this line item is rising before it's falling, even in the optimistic scenario.

Cause 5: The carbon price is doing its job

The four causes above are mostly structural — geography, hydrology, market design, and historical planning choices. The fifth is different. It's a deliberate policy lever, and unlike the other four, it's working exactly as designed.

RGGI — the Regional Greenhouse Gas Initiative — is a cap-and-trade system covering power plants in the New England states plus a handful of others in the mid-Atlantic. Generators have to buy allowances for each ton of CO₂ they emit; the supply of allowances shrinks every year; and the proceeds get recycled back into clean energy programmes and bill assistance. It's the most successful regional carbon market in the United States and a textbook example of carbon pricing in practice.

In 2024, RGGI allowance prices hit a record $21 per ton of CO₂, up 55% from 2023. That added approximately $8/MWh to the average wholesale electricity price — and is the single largest factor in the year-on-year cost increase. Remember the puzzle from Section 2, where wholesale prices went up 13% in a year when gas was flat? RGGI is most of the answer.

It's important to be honest about this. RGGI is raising your bill. It's supposed to. Carbon pricing works by making the dirty option more expensive, so that the clean option becomes more competitive — and so that the cost of climate damage gets reflected in the price of the thing causing it. The intended consequence of a carbon price is that fossil-generated electricity gets more expensive. That's the mechanism. Hiding it would be dishonest.

What you can fairly debate is whether this is the right time, the right level, the right design — and whether the recycled proceeds are actually buying enough decarbonisation to justify the bill impact. Those are real questions, and I'll come back to them in Section 5. But "RGGI is making electricity more expensive" isn't a gotcha. It's the policy.

Where does that leave us?

Five causes, of which roughly one-and-a-half are about climate policy. Pipeline geography (Cause 1) is an act of God plus a state-level planning choice. Quebec hydro collapse (Cause 2) is mostly drought. The broken capacity market (Cause 3) is a market design failure with no climate dimension at all. Overbuilt transmission (Cause 4) is a sunk cost from decades of reliability planning. Only RGGI (Cause 5) is straightforwardly attributable to environmental policy, and even there, the contribution is about $8/MWh out of a $25/MWh premium.

So Dad's theory — that liberals and renewables are why his bill is high — is, charitably, about a quarter right. The bigger story is structural, and it has very little to do with the politics that get talked about. It has a lot to do with politics that don't.

Which brings us, finally, to the thesis.

4. Half-assing two jobs

Here, finally, is the thesis. There are two possible worlds in which New England has cheaper electricity than it does today. Neither of them is the world New England currently lives in.

The Fossil World

In the Fossil World, New England builds out the natural gas system properly. New pipelines from the Marcellus and Utica basins, sized to serve both winter heating and summer power generation simultaneously, with enough headroom that pipe constraints stop showing up in the monthly EIA data. New combined-cycle gas plants clear the capacity auction and replace the aging fleet. Maybe an LNG import terminal with real winter contracted volumes, just for insurance. The grid runs on cheap, abundant, dispatchable gas, and the marginal generator is burning fuel at the national price rather than four times it.

This grid exists. It's called PJM — the regional transmission organisation that runs the wires from New Jersey through Pennsylvania, Ohio, Virginia, West Virginia, and most of the way to Chicago. PJM has all-in wholesale costs of roughly $60-65/MWh versus New England's $87. It's not a fluke. PJM sits on top of the Marcellus shale, which is the most prolific gas basin in North America. It has plenty of pipeline capacity. Its capacity market actually clears at numbers that incentivise new build. It is, in many ways, the boring success story of US electricity markets — boring because the system works, and a success because the bills are roughly two-thirds of New England's.

The Fossil World is also, of course, more carbon-intensive. PJM's emissions per megawatt-hour are higher than New England's, because gas is doing more of the work. That's the trade.

The Renewable World

In the Renewable World, New England goes the other way. It builds out the offshore wind queue — 14,000 MW of proposed capacity, of which even 30-40% delivered would be transformative — backed by grid-scale batteries for the daily ramp, with NECEC and other Quebec interconnections doing the multi-day balancing during cold snaps and dark winter weeks. Solar and onshore wind grow steadily. Heat pump electrification eats home heating demand off the gas system over time. Gas drops from 50% of supply to maybe 25-30%, mostly relegated to peak winter reliability with firm fuel contracts. Carbon costs fall as the carbon-emitting base shrinks.

This grid is harder to point at, because no jurisdiction has actually completed the transition. The closest analogue, geographically and physically, is — rather conveniently — my second home: Great Britain. This side of the pond, we've built out a serious offshore wind fleet (around 15 GW today, with another 15 GW in construction or contracted), a massive interconnection system to Norwegian hydro and continental Europe to handle balancing, a coal phase-out that finished in 2024, and an electricity mix that runs around 45-50% renewable on an annual basis. The climate is cold, grey, and windy — much more like New England than southern California. The grid topology — offshore wind backbone plus hydro-rich neighbour for balance — is essentially what a renewables-built-out New England would look like.

The obvious objection: Britain's wholesale power price is even higher than New England's, so why would we want to look like them? The answer is in the marginal generator. Britain's power prices are also set by gas — but it's expensive LNG tankered in from another continent, on a small island that long since produced out its North Sea fields and built almost no storage. New England's renewable build-out wouldn't just lower emissions; it would lower gas demand, freeing up pipeline capacity and pushing the marginal generator's fuel cost back toward the national benchmark instead of four times it. You'd end up with the best of both worlds: renewables doing most of the work, and the gas that does still set the price actually being cheap. Britain can't get there because the geography won't let it. New England can.

The world New England actually lives in

New England has gone partway down both roads and reached neither destination. State policy has politically foreclosed the Fossil World — no new pipelines, no new gas plants of any meaningful size, RGGI taxing the existing fleet — but the physical infrastructure of the Renewable World is still mostly under construction. Vineyard Wind is partly online. Revolution Wind is expected next year. NECEC just started commercial operation in December. The 14,000 MW offshore wind queue is mostly proposals, not megawatts. Meanwhile, the existing gas fleet is aging without replacement, the capacity market hasn't sent a new-build signal in a decade, and the system gets more dependent on expensive pipeline-constrained gas every year that the renewable build-out runs behind schedule.

This is what Ron Swanson was warning against. Whole-assing the Fossil World gets you PJM. Whole-assing the Renewable World gets you Great Britain. Half-assing both gets you New England — paying premium prices for a grid that is neither cheap-and-fossil nor clean-and-renewable, but stuck in the expensive middle, waiting for one of the two viable endpoints to actually arrive.

In fairness — it's not quite that simple

The half-assing framing is the right one for a snapshot. It's slightly unfair as a description of a process. New England didn't choose to be stuck halfway. It chose the Renewable World — explicitly, through state clean energy standards, decarbonisation mandates, and the political foreclosure of new gas infrastructure — and is now living through the gap between making that choice and finishing the build that the choice requires.

That gap is the real problem. Offshore wind takes a decade to permit, finance, and build. NECEC took twelve years from proposal to commercial operation, mostly because of legal challenges in Maine. Capacity market reform takes effect in 2028. Heat pump rollout is a multi-decade project. Meanwhile, the gas plants the system still relies on were built in the 1990s and 2000s and are getting older every year, and the capacity market hasn't been able to replace them because the policy direction is to retire the category, not refresh it.

So the more sympathetic framing is: New England is in a transition gap, and the question isn't whether the strategy is right but whether the gap can be closed before something breaks. The available levers are limited and most of them are slow.

Look at that list and the picture is uncomfortable. The two things actually working — NECEC and gas plant fuel storage — are real but small. Offshore wind is the structural answer but it's slow and execution-risky. The capacity market reform is necessary but takes years to bite. LNG is a winter buffer, not a strategy. And the one fast lever that could meaningfully reduce the premium — new pipeline capacity — is dead by political consensus across the three biggest load centres.

Which is to say: the transition gap is going to last a while. The bet New England has made is that offshore wind, NECEC, capacity market reform, and the gradual electrification of heating arrive fast enough — together — to bridge it before reliability fails or political support cracks. That bet is live. The next five years will settle it.

Now, you might reasonably ask: was making that bet the right call at all? Given how painful the transition is turning out to be, wouldn't it have been simpler to just build the gas pipelines and live in the Fossil World?

There's an actual answer to that. It involves stranded assets, the asymmetric cost of delaying decarbonisation, and one specific physical fact about winter cold snaps that almost nobody outside the grid operator's office is talking about. That's the next section.

5. In defence of the strategy (and one big caveat)

Everything in Section 4 is, in some sense, an indictment of how New England has handled the transition. Slow build-out, foreclosed alternatives, expensive interim. So a reasonable reader at this point — let's call him Dad — might fairly ask: was the strategy wrong? Should New England just have built the gas infrastructure, accepted the carbon cost, and worried about decarbonisation later when it was cheaper to do?

The honest answer has two parts. The first part is the strongest argument against the climate-policy position, which I want to put on the table before defending the strategy. Then the defence.

The hard problem: winter reliability

Most of the public argument about renewables is about average performance. How many megawatt-hours per year, what fraction of supply, what the levelised cost looks like. On those metrics, renewables look great. The case for them is strong and getting stronger.

But the New England grid isn't sized for the average. It's sized for the worst hour of the worst week of the worst winter. Specifically: a multi-day stretch in January or February when temperatures stay below zero Fahrenheit, gas pipelines are running at full residential heating priority, and electricity demand is high because everyone is trying to stay warm. That's the moment the system has to keep the lights on. Everything else is easy.

In that specific moment, here's what each resource type can actually contribute. Gas plants without firm fuel contracts are worth essentially zero — they can bid into the energy market, but if there's no fuel coming through the pipe, they don't run. Batteries can run for four hours and then they're empty, and they can't recharge from a grid that's already constrained. Offshore wind doesn't correlate with cold weather — high-pressure winter systems are often calm, which is precisely when you need power most. Solar in January at 5pm in Boston is generating zero. The resources that do work — dual-fuel oil/gas steam turbines, gas plants with contracted firm fuel, hydro with reservoir storage, nuclear — are exactly the resources state clean energy policy is trying to retire.

And winter is getting harder, not easier. The 2025 system plan projects winter peak demand growing about 30% by 2034, driven mostly by heat pump electrification. Today's winter peak runs around 20,000 MW. By 2034 it's projected to hit 26,000 MW — converging with summer peak, which has been the system's design point for decades.

So the system has to handle a winter peak that's 30% bigger than today's, made up disproportionately of resources that don't work well in winter, while retiring the resources that do. Pretending this isn't a problem is how you get a reliability crisis that sets the whole transition back politically. It's the strongest argument against accelerating the strategy, and anyone defending the strategy needs to acknowledge it.

The defence: stranded assets and the cost of building backwards

All of that being true — and it is — the strategy is still right. Here's why.

Suppose New England did the obvious thing and built out the gas system. New pipelines from Pennsylvania, two or three new combined-cycle plants, maybe an LNG terminal with a 25-year contract. Bills come down. Dad is happy. The Fossil World materialises.

A new gas pipeline has an economic life of about 40 years. A new combined-cycle plant, similar. The infrastructure built today expects to be earning revenue until roughly 2065. But state-level decarbonisation mandates already on the books — Massachusetts net zero by 2050, Connecticut and Rhode Island similar, the regional clean energy standards that shape the wholesale market — commit the grid to retiring most of its fossil generation by the early 2040s. That's a 20-year gap between when the asset expects to earn its money back and when policy says it has to stop running.

There are only two ways that gap resolves. Either the asset gets stranded — built, paid for, retired early, with the losses absorbed by ratepayers or shareholders — or the policy gets bent around the asset, because once you've spent ten billion dollars on a pipeline, you find reasons to keep using it. Both of those are losing outcomes. The first is straightforward financial waste: you've built infrastructure you knew you'd have to throw away. The second is worse, because it means the pipeline becomes a political constituency for delaying the transition — protecting its own utilisation, lobbying against its own retirement, exactly the dynamic that has kept American coal plants running 15 years past their economic prime.

This is the core economic logic of the climate-policy stance, and it's the bit that doesn't get explained well in public arguments. Climate policy isn't only about emissions. It's also about not investing capital into infrastructure you've already committed to phase out. The discipline that New England's policy is enforcing — slow, painful, expensive in the short run — is the discipline of refusing to build assets you'll have to write off. Every billion dollars of gas pipeline not built today is a billion dollars not stranded in 2045.

The honest synthesis

So: the strategy is right. The winter reliability problem is also real. Both of those things are true at the same time, and a piece that says "renewables are good and the critics are wrong" is doing the climate position no favours, because it's the kind of thing that loses elections when reliability fails.

The honest version of the climate-policy case has to acknowledge that the transition needs a credible bridge — firm-fuel-contracted gas through the 2030s, demand response at scale, dispatchable long-duration storage as it commercialises, more interconnection to hydro-rich neighbours like Quebec — and that pretending the bridge isn't necessary is how you lose the project altogether. The renewable build-out is the destination. The bridge is what gets you there without the lights going out in the meantime, and "the bridge is fine" is not the same as "the destination is wrong."

New England is, on the evidence, building the right destination and almost no bridge. Vineyard Wind and NECEC are real. So is the absence of any plan for the firm-fuel winter problem. The next five years are going to test whether the gap can be closed by pure renewable build-out fast enough to outrun the reliability risk, and the answer is genuinely uncertain.

Which brings us back, finally, to Dad and his electricity bill.

6. So, Dad

Your electricity bill is high because New England sits at the end of an inadequate gas pipeline system, has lost half its cheap hydro imports from Quebec to a multi-year drought, runs a capacity market that hasn't sent an investment signal in a decade, has overbuilt its transmission network in pursuit of perfect reliability, and prices carbon through RGGI more aggressively than any other US region. Of those five things, exactly one is straightforwardly attributable to the politicians you blame, and even that one accounts for less than a third of the premium. The renewables you don't like are 6.8% of the supply mix and aren't setting the price.

The bigger story is that New England has chosen to decarbonise its grid, and is currently living through the gap between making that choice and finishing the build it requires. The strategy is right — building gas infrastructure you'll have to retire in the 2040s is a slow-motion way of setting capital on fire — but the gap is painful, and there's no fast lever available to close it. The next five years will turn on whether offshore wind, NECEC, capacity market reform, and heat pump electrification arrive fast enough, together, to bridge the gap before reliability fails or political support cracks.

Both endpoints are credible. New England could be paying 30 cents a kilowatt-hour in 2032 because the strategy worked. It could also be paying 45 cents because the strategy stalled. The gap between those two outcomes is bigger than most people, including most of the people running the system, are willing to say out loud.

For investors paying attention, the implication isn't subtle: the capital that matters in this story is going into offshore wind execution, grid-scale storage, HVDC interconnection, and the firm-capacity assets that can credibly bridge the winter problem. The capital that isn't going in — and won't, in any reasonable scenario — is new gas in New England, full stop. That's the bet the region has placed, and the wager is whether the build-out arrives fast enough to honour it.

One last thing worth saying. New England is the first US grid to run this experiment at scale. Every other system that decarbonises at pace will eventually face some version of these five causes — pipeline isolation in some form, lost low-cost imports, capacity market signals that don't fit a renewable build-out, transmission costs from grid reconfiguration, and a carbon price that does what it's supposed to do. The question isn't whether New England's experiment succeeds in New England. It's whether the playbook the region is writing — including the mistakes — is one the rest of the country can learn from before having to live through it themselves.

So yes, Dad, your bill is too high. It's too high for reasons that have very little to do with the politicians you blame and a lot to do with politics that don't get talked about. It's going to stay high for a few more years. And then, if the bet pays off, it's going to come down — not because anyone built a treadmill, but because the grid finally finished the thing it started ten years ago.

Whole-ass one thing.