With a T-38 at Williams Air Force Base, Arizona, 1985

In 1985, I was a student pilot at Williams Air Force Base in Arizona, flying the T-38, the Air Force’s supersonic jet trainer. I was solo that day. Before every takeoff, we calculated the performance of the airplane. One of those calculations was an acceleration check: by a specific point down the runway, the airplane had to have reached a specific speed. It answered a very important question while there was still enough runway left to do something about it: Is the airplane actually performing the way we assumed it would?

I lined up, brought the engines up to military power, released the brakes and started down the runway. When I reached my acceleration-check point, I looked at the airspeed indicator. I wasn’t going fast enough. Nothing dramatic had happened. Both engines were running and the airplane was accelerating, but it wasn’t accelerating the way my calculations said it should.

So I aborted the takeoff. There was nothing wrong with the engines. The problem was my assumption. It was hotter than I had planned for, which meant the engines weren’t producing the thrust I had calculated. The acceleration check caught my mistake while I still had enough runway to stop. Had I continued the takeoff, I wouldn’t have had enough speed to fly when I reached the departure end of the runway. I would have crashed, and almost certainly died.

That acceleration check wasn’t predicting the future. It was testing an assumption. When the assumption turned out to be wrong, I changed the plan.

More than forty years later, I think about that takeoff when I look at New England’s energy policy. Every energy plan depends on assumptions about demand, costs, fuel prices, construction schedules and performance. There’s nothing wrong with that. The problem comes when we start treating assumptions as facts.

So here’s the next question in this series: What do you have to believe for the answer to be true, and how will you know if it isn’t?

First, We Have to Build It

New England’s energy plans require an extraordinary amount of stuff to exist that doesn’t exist today. ISO New England has estimated that achieving the states’ 2050 goals could require roughly 97,000 MW of new renewable and storage capacity.

Those numbers are easy to put into a spreadsheet. Turning them into physical things is something else entirely. Roughly 30,000 MW of offshore wind means about 2,000 15-MW turbines. Roughly 26,000 MW of solar means something on the order of 50 to 65 million solar panels.

Using the turbine size and spacing assumptions we’ve examined, 30 GW of offshore wind also requires roughly 5,400 square miles of ocean, an area larger than Connecticut. And even that is an assumption. Recent research into wake effects suggests large offshore wind developments may require substantially more spacing because turbines take energy out of the wind available to other turbines. One recent study found that increasing spacing from five to ten rotor diameters substantially reduced modeled wake losses. We can’t just double the 5,400-square-mile figure, but it certainly raises the question of whether we’re underestimating how much ocean this will actually require.

Then we have to connect it all. National transmission studies suggest the United States may need to build 5,000 to nearly 7,000 circuit-miles of major transmission every year, several times the recent construction rate. That means thousands of towers, transformers and breakers, enormous quantities of wire and steel, and enough linemen, electricians, engineers and construction crews to build it.

Maybe we can do it. America has built extraordinary things before. But there’s an obvious acceleration check: How much did we say we needed to build this year, and how much did we actually build?

Sometimes We Just Pick a Number

Maine’s battery target is a particularly strange example. The Legislature established a goal of 400 MW of energy storage by 2030 in 2021. The state’s detailed Energy Storage Market Assessment came afterward. As far as I can determine, there wasn’t an engineering analysis that concluded Maine needed precisely 400 MW to solve a defined reliability problem. We picked the number and then studied how to get there.

Consider the Cross Town battery project in Gorham. It is rated at 175 MW and 350 MWh, meaning it can operate at full output for about two hours. That sounds substantial until you compare it with the energy system we’re trying to support. At a New England winter peak of roughly 20,000 MW, Cross Town’s entire stored energy is equivalent to only about one minute of regional electricity consumption.

So where did 400 MW come from? What problem is it supposed to solve? How long does that problem last? And why is the target measured only in MW rather than MWh or hours of duration? If we can’t answer those questions, 400 MW isn’t an engineering requirement. It’s just a number.

My T-38 acceleration-check speed wasn’t a target someone picked because it sounded ambitious. It came from what the airplane physically had to do to get safely into the air. Energy targets ought to work the same way.

Now Maine Has a $400 Million Answer

This week, the Maine Public Utilities Commission gave us a perfect real-world example. The Commission selected an 800 MW onshore wind project in northern Maine and a 1,200 MW transmission line to connect it to the New England grid. Maine’s share of the wind project will be approximately 600 MW, while Maine is expected to pay less than 11% of the transmission cost.

Then came the headline: Maine ratepayers are expected to receive $387 million to $425 million in net benefits over the life of the project.

That’s remarkably precise for something that hasn’t been built yet. Maybe they’re right, but $400 million isn’t an observed fact. It’s the answer produced by a calculation based on assumptions about what will happen for decades into the future.

What will the project ultimately cost? How much electricity do we assume the windmills will actually produce? What will wholesale electricity prices be? What will the transmission line cost? How much curtailment are we assuming? What happens if construction is late or over budget? And most importantly: Net benefits compared with what?

The contract includes not just electricity, but Renewable Energy Credits, or RECs. A REC is essentially a certificate representing the renewable attribute of one megawatt-hour of qualifying renewable electricity. Maine’s Renewable Portfolio Standard requires electricity suppliers to obtain them. In other words, RECs have value in part because state policy requires them.

If some of the claimed $400 million benefit comes from satisfying Maine’s renewable mandate more cheaply than buying RECs or renewable electricity somewhere else, that may be a legitimate benefit of this particular project. But it doesn’t establish that the renewable mandate itself saves ratepayers money.

There’s another comparison I’d like to see: What would the least-cost reliable energy system look like if the renewable mandate didn’t exist? Without the Renewable Portfolio Standard and Maine’s other renewable requirements, it’s hard to imagine anyone proposing an 800 MW wind farm in northern Maine and a new 1,200 MW transmission line because it was the least expensive way to provide reliable electricity to Maine customers.

We are building this project because Maine has made a policy decision to require more renewable energy. That’s a legitimate policy choice. But if we’re going to tell ratepayers they’ll be $400 million better off, we ought to be very clear about what we’re comparing it with.

If the comparison is this project versus another way of complying with Maine’s renewable requirements, it may show that this is the cheaper way to meet the mandate. It does not show that the mandate itself produces the least expensive reliable electricity.

The Commission said this week that “Maine ratepayers are significantly better off for this effort.” Maybe they are. How do we know, and what would have to happen for that conclusion to change?

Every Alternative Has Assumptions

None of this means a different energy system is assumption-free. Greater use of Marcellus natural gas would require us to believe that enough gas can be produced at competitive prices, that additional pipeline capacity can be permitted and built, and that policymakers will allow customers to use it for electricity generation, heating and industrial processes.

Those are real assumptions. But they’re different assumptions. Marcellus already produces enormous quantities of natural gas. Pipelines, gas furnaces and combined-cycle power plants are proven technologies operating at enormous scale today. The question isn’t whether they work. It’s whether we’re willing and able to build the infrastructure necessary to bring more of that energy into New England.

Every alternative deserves the same test: What do we have to believe, how will we know if we’re wrong, and what will we do about it?

Check the Airspeed

That day in the T-38, the acceleration check didn’t tell me why the airplane wasn’t performing properly. It didn’t need to. It told me that an assumption underneath my takeoff plan was wrong while I still had enough runway left to do something about it.

That’s the part I think is missing from too much of our energy policy. We set targets for 2030 and 2050, spend billions trying to reach them, and measure progress by how much we’ve built or spent. But where are the acceleration checks? What did we assume would be true by now? Is it true? And what would cause us to change course?

Aborting that takeoff wasn’t a failure. Continuing because I’d already used half the runway would have been.

Before we use up any more runway, maybe we ought to check the airspeed.

Last Sunday, after a weekend on our sailboat, I was riding the launch back to shore with a guy who had spent the weekend on his powerboat. We got talking about our boats and he mentioned that he’d burned about $500 worth of fuel that weekend. I smiled. I fill the diesel tank on my sailboat about once every two years.

Free wind. Pretty tough to beat.

But then I thought about the bill waiting for me at the boatyard this winter. Sails, rigging, haulout, storage, bottom work, and an engine that still needs to be maintained. My fuel bill may be almost nothing, but that certainly doesn’t mean my boat costs almost nothing to own.

There’s another problem with the comparison. We’re not even asking our boats to do exactly the same thing. His powerboat is largely about getting somewhere. For me, sailing is as much about the journey as the destination. As Jimmy Buffett put it, “fast enough to get there, slow enough to see.”

We both spent the weekend on the water, but we’re asking very different things of our boats. Comparing our fuel bills doesn’t tell you much when the boats are designed to do different things.

And that’s when it occurred to me that we make both mistakes when we talk about electricity. We compare one cost instead of the whole cost, and we compare resources as though they all do the same job.

A megawatt-hour produced at noon on a mild May afternoon is not the same thing to the energy system as a megawatt-hour we can count on at 7:00 on a bitter January morning. Wind, solar, natural gas, nuclear, hydro and batteries have very different capabilities.

So let’s do the math.

This is the third question in my series about how we should evaluate energy proposals before deciding whether to believe the answer. We started by looking at what actually powers New England today. Then we asked what problem we’re trying to solve. Now comes the next question: Are we doing all the math?

The Generator Isn’t the System

We’re constantly told that wind and solar are among the cheapest sources of electricity. Usually the evidence is some version of the cost per megawatt-hour produced. That may be a legitimate measure of what comes out of the generator. It isn’t necessarily a measure of what it costs to deliver reliable electricity to the customer.

Start with transmission. New England is simultaneously electrifying heating and transportation and moving toward generation that is increasingly located far from the people who use the electricity. Offshore wind is offshore. Northern Maine wind is hundreds of miles from southern New England’s largest load centers. That electricity has to get from where it’s produced to where it’s needed.

ISO New England’s 2050 Transmission Study gives us some idea of the scale. In its high-demand scenario, ISO-NE estimates $23 billion to $26 billion in transmission upgrades by 2050.

And that number deserves an asterisk. It’s in 2023 dollars, with no future inflation included. It doesn’t include all the costs of interconnecting the new generation assumed in the study. It doesn’t include distribution-system upgrades. And ISO-NE identifies additional transmission needs that aren’t included in that number.

So when someone shows us the cost of electricity from a wind or solar project, where is that $23 billion to $26 billion? It belongs in the math.

Then There Are Batteries

Maine has a goal of 400 MW of battery storage by 2030. It sounds impressive, but the number tells us surprisingly little. The target was established by the Legislature in 2021; the state’s detailed Energy Storage Market Assessment followed in 2022.

Consider two actual Maine projects. Cross Town in Gorham is 175 MW and 350 MWh, enough to run at full output for about two hours. The proposed Form Energy project in Lincoln is only 85 MW, but is designed to run for 100 hours and store 8,500 MWh.

So the smaller 85 MW project stores more than 24 times as much energy, yet Maine’s 400 MW scoreboard gives the 175 MW project more than twice the credit. That’s because the target measures power, not energy. I haven’t found an engineering analysis showing why 400 MW was the right operational number in the first place.

This matters because New England doesn’t have a two-hour reliability problem. Winter Storm Fern stressed the system for days. Once a battery is empty, it has to be recharged from generation somewhere else.

So tell me what problem 400 MW solves, how long it needs to last, what it costs and what other investment it eliminates. Otherwise we’re measuring batteries installed, not problems solved.

And We Still Need Dependable Generation

After spending money on wind and solar, transmission and batteries, there’s still one more problem: we need electricity when the weather doesn’t cooperate.

Winter Storm Fern made that painfully clear. Oil approached 40% of New England’s electricity at times, and generators burned 66 million gallons during the extended cold spell.

Those resources aren’t free just because we use them less often. Plants still have to be maintained and ready to run. Fuel still has to be available. The infrastructure that delivers that fuel still has to exist.

So here’s another piece of the math I’d like to see: After we’ve spent billions on new generation, transmission and storage, how much of the dependable system can we actually stop paying for? If the answer is very little, then we’re not replacing one set of costs with another. We’re adding costs.

RTFQ

An engineering professor of mine used to preach something he called RTFQ: Read the question. His version included another word.

The lesson was simple. You can do beautiful work, get all the calculations right and still get the answer wrong if you aren’t answering the question that was asked. That’s worth remembering when someone tells us one source of electricity is cheaper than another.

The question isn’t: What does it cost to produce a megawatt-hour from this generator?

The question is: What does it cost to build and operate an energy system that delivers the electricity we need, when we need it?

Those are very different questions.

Show Me the Whole Bill

So now let’s put it all together.

Start with the generation itself. ISO New England’s high-demand 2050 scenario assumes roughly 30,000 MW of offshore wind and 40,000 MW of solar. Applying federal laboratory capital-cost benchmarks to a build of that magnitude puts the generation investment alone well above $150 billion. And that’s before we start adding the rest of the system.

Then add $23 billion to $26 billion of transmission upgrades, stated in 2023 dollars without future inflation and still not including everything. Add the batteries. Add distribution and other interconnection costs. And after all of that, add the cost of keeping enough dependable generation available to get us through the periods when the weather doesn’t cooperate.

We’re talking about well north of $175 billion before we’ve counted several major pieces of the bill. Maybe after adding all of that up, the new system really is cheaper.

If it is, show me.

But don’t show me the cost of producing a megawatt-hour from a wind turbine and compare it with a megawatt-hour from a natural-gas or nuclear plant. They don’t do the same job, and the generator isn’t the whole system. Show me what customers actually have to pay for the entire energy system before and after.

That’s what I wasn’t doing on the launch Sunday. I heard that my friend had spent $500 on fuel while I’d spent almost nothing and, for a moment, felt pretty good about my choice.

Then I remembered my boatyard bill.

Maybe my sailboat really is cheaper to own. I doubt it. But our fuel bills certainly don’t answer the question. And neither does the advertised price of a megawatt-hour of electricity.

If we’re going to fundamentally rebuild New England’s energy system, asking what the whole thing costs doesn’t seem like too much to ask.

Are you doing all the math?

Imagine walking into your doctor’s office and, before asking what’s wrong with you, the doctor says, “I’ve decided you need knee surgery.” You’d probably find another doctor.

Yet that’s remarkably close to how we make energy policy. We start with the answer. We need more solar, offshore wind, batteries, heat pumps or transmission. Depending on who’s talking, we need nuclear or natural gas. Maybe we need some of those things. But shouldn’t we start by asking what problem we’re trying to solve?

If the problem is high energy prices, show me how the proposal lowers the total cost paid by customers. If the problem is reliability, show me how it provides dependable energy when the system is under the greatest stress. If the problem is climate change, tell me what it costs and what measurable result we get for the money. And if the problem is economic growth, show me how it provides enough additional affordable energy for new factories, data centers, homes and businesses.

Those aren’t the same problems. Why would we assume they all have the same solution?

Start With the Problem, Not the Technology

This is where I think much of our energy debate gets backwards. We decide we want more of a particular technology and then construct an argument for why we need it. The technology becomes the objective rather than a tool for achieving the objective.

Solar isn’t an objective. Neither are wind, natural gas, nuclear or batteries. They’re tools available to us for building an energy system.

The objective should be abundant, affordable, reliable and resilient energy.

Then we can have an honest argument about which combination of technologies gets us there.

If the Problem Is Affordability, Measure the Whole Cost

New England doesn’t have a theoretical affordability problem. We have some of the highest electricity prices in the country.

Through May of this year, residential electricity in New England averaged 29.32 cents per kilowatt-hour, according to the U.S. Energy Information Administration. Maine averaged 29.68 cents.

So if affordability is the problem we’re trying to solve, that’s the scoreboard.

The question isn’t whether a particular generator can produce a megawatt-hour cheaply under favorable conditions. The question is what it costs to provide customers with the electricity they need, whenever they need it.

Suppose we add a large amount of wind or solar. The advertised cost of the electricity may look attractive. But if we still need natural gas, nuclear, hydro or other dispatchable generation when the wind isn’t blowing or the sun isn’t shining, those costs don’t disappear. If the new resources require additional transmission, storage or distribution upgrades, those costs belong in the calculation too.

Customers don’t pay the levelized cost of one generator. They pay for the energy system.

If a proposal claims it will make energy more affordable, show us the total cost before and after. Include generation, transmission, distribution, storage, backup, subsidies and the other costs ultimately borne by customers or taxpayers.

If the total bill goes up, don’t tell me you solved affordability.

If the Problem Is Reliability, Test the Hardest Day

We got a pretty good demonstration of this during Winter Storm Fern in January.

Oil normally produces very little of New England’s electricity. But as the cold settled in and natural gas became constrained, oil-fired generation surged to nearly 8,000 megawatts and approached 40% of New England’s electricity at times. Petroleum became the region’s largest source of electricity for periods between January 24 and 26, and dual-fuel generators switched from natural gas to oil.

Over the extended cold spell, New England generators burned 66 million gallons of oil—more than during the previous four winters combined.

Think about that. A fuel that barely registers during normal conditions suddenly became the largest source of electricity when the system was under severe stress.

That’s why averages can fool us. For reliability, the important question isn’t simply how much energy does a resource produce over a year? It’s what can we count on it to produce when we really need it?

If someone tells me a proposal will improve reliability, show me the worst week, not the best one. Show me what happens when it’s 5 degrees, the wind isn’t cooperating, the sun went down at 4:30, heating demand is surging and the system has already been under stress for several days.

If it works then, we have something worth talking about.

If the Problem Is Climate Change, How Much Does It Cost and What Do I Get?

A lot of Maine’s energy policy is justified as a way to address climate change. Fair enough. Taxpayers and ratepayers ought to be able to ask two simple questions:

How much does it cost, and what do I get?

Maine points proudly to greenhouse gas emissions that are about 30% below 1990 levels. That’s true. But the latest DEP inventory behind that figure is for 2021, and before we credit climate policy for the entire reduction, we ought to ask what else happened to Maine’s economy during those years.

We lost an enormous amount of industrial activity. At the end of the 1990s, Maine’s paper industry employed more than 15,000 people. Between 2000 and 2017, 11 of Maine’s 17 pulp and paper mills—64%—shut down. Today, we’re essentially down to three large operating pulp and paper mills: Sappi in Skowhegan, ND Paper in Rumford and Woodland Pulp in Baileyville.

Energy wasn’t the only reason. Paper markets changed, electronic media reduced demand and global competition increased. But energy costs mattered. Maine regulatory testimony documents mills idling during high-cost periods because competitors elsewhere could produce more cheaply. Energy can represent as much as 25% of a paper mill’s production cost, and Madison Paper specifically cited energy costs as a major factor when it closed in 2016.

And here’s the part I think gets missed: when a mill closes, its emissions disappear from Maine’s inventory too. We lose the jobs, the production and the economic activity—and then count the lower emissions as progress.

If a Maine mill becomes more efficient and produces the same amount of paper with fewer emissions, that’s progress. If the mill closes and the paper gets made somewhere else, Maine’s emissions also decline. But we’ve exported the production, the jobs and potentially the emissions.

The broader economic scoreboard isn’t particularly encouraging either. In 2018, MaineCare enrollment was already 48% higher than it had been in 2001, while Maine’s population had grown only about 4%. Enrollment then grew from about 263,000 in 2018 to more than 400,000 by 2022. Today, roughly 30% of Maine’s population is enrolled.

I’m not arguing that high energy prices caused MaineCare enrollment. They didn’t. I’m saying these are all parts of the economic scoreboard. We’ve lost much of our industrial base, energy prices are high, economic growth has been weak, and a remarkable share of our population now qualifies for government health coverage.

Against that backdrop, pointing to declining emissions by themselves and declaring success isn’t good enough.

Tell me what we’ve spent. Tell me what these policies have done to energy costs. Tell me how many tons of emissions were eliminated by the policies rather than by economic activity disappearing. Then tell me what measurable impact those reductions have on the problem we’re supposedly trying to solve.

How much does it cost, and what do I get?

And there’s one more part of that question: even if Maine reaches every one of its emissions targets, what measurable impact does that have on global climate?

We’ll get to that later in this series.

If the Problem Is Economic Growth, We Need More Energy

We’re not just changing how New England produces electricity. We’re also asking the electric system to do considerably more.

ISO New England expects normal winter peak demand to grow from about 20,500 megawatts in 2026/27 to 26,400 megawatts by 2035/36—an increase of roughly 29%. Heating electrification alone is expected to add 5,533 megawatts to the winter peak, with transportation electrification adding another 1,509 megawatts.

We’re planning to add all that demand while simultaneously changing the resources that supply it.

We want businesses to expand, manufacturers to build here, more housing, and increasingly data centers and AI infrastructure. At the same time, public policy is moving transportation and heating onto the electric system.

Economic growth requires more abundant energy at competitive prices.

A manufacturer deciding whether to build in Maine doesn’t care much about our energy slogans. It wants to know whether enough power will be available, whether it will be reliable, how much it will cost and whether the company can get it when it needs it.

A 500-megawatt resource that produces electricity when customers need it is not economically equivalent to a 500-megawatt resource whose output depends on the weather. Nameplate capacity doesn’t tell us how much dependable power the system gained.

If our objective is economic growth, the question should be straightforward: How much additional dependable energy does this proposal make available, and at what price?

You can’t build a growing economy around energy scarcity.

Are We Measuring the Solution—or Just the Activity?

This may be where energy policy gets most confused. We announce goals for megawatts of wind and solar, heat pumps installed or electric vehicles on the road. Then, when we hit those targets, we declare success.

But those are measures of activity, not necessarily results.

If the problem was affordability, did energy bills go down? If it was reliability, did the system become more dependable when it was under stress? If it was climate change, how much did we spend and what measurable result did we get? If it was economic growth, did we create more abundant, competitively priced energy?

Installing 1,000 megawatts of something isn’t inherently a success. Neither is spending a billion dollars or installing 100,000 heat pumps. Those may be tools for achieving an objective, but they aren’t the objective.

And we should apply the same standard to every technology. If someone proposes a natural-gas pipeline, tell me what problem it solves. If someone proposes a nuclear plant, show me the cost, output, reliability benefit and when we’ll actually get it. Wind, solar and batteries should face the same test.

Start with the problem. Define the outcome. Then choose the best tools to get there.

The Question I’d Ask

We’re going to hear a lot of energy proposals during the coming election season. They’ll have impressive numbers, ambitious targets and probably a lot of adjectives attached to them.

Before deciding whether you support one, ask a simple question:

What problem are you trying to solve?

If the problem is affordability, ask what happens to the customer’s total bill. If it’s reliability, ask what happens on the hardest day of the year. If it’s climate change, ask how much does it cost, and what do I get? If it’s economic growth, ask how much new dependable energy becomes available and what it will cost.

If the answer comes back in megawatts installed, dollars spent, heat pumps deployed or some other measure of activity, ask the question again.

Because building more stuff isn’t the objective.

Solving the problem is.

If an NFL team somehow signed the twelve best quarterbacks in football, it would have the worst team in the league. Not because quarterbacks aren’t valuable, but because no matter how good they are, they can’t perform the jobs of the other positions.

Football is a system. The offensive line blocks. The quarterback leads the offense. Running backs gain tough yards. Receivers stretch the field. The defense gets the ball back. Special teams control field position. Championships aren’t won by collecting the best players. They’re won by building the best team.

Our energy system is no different.

In the first article of this series, I suggested that before you believe any energy proposal, you should ask five simple questions. This is the first—and I think the most important.

Do you understand the system we have today?

You can’t improve a system you don’t understand.

Principle #1: Energy Is Bigger Than Electricity

When most people hear the word energy, they picture the electric grid. They think about power plants, transmission lines, wind turbines, and solar panels. That’s understandable, but it’s only part of the picture.

Electricity accounts for only about 20% of the energy Americans consume. The other 80% comes from fuels used for home heating, transportation, manufacturing, agriculture, aviation, and countless other purposes. We heat our homes with natural gas, heating oil, propane, and wood. Trucks move freight with diesel. Airplanes burn jet fuel. Manufacturers use enormous amounts of fuel to produce everything from paper and steel to pharmaceuticals and food.

Think about that for a moment.

Four out of every five units of energy we consume never travel across an electric transmission line. Yet much of our public discussion about “energy policy” focuses almost entirely on electricity.

That’s like evaluating an entire football team by watching only the offensive line. You’re looking at an important part of the team—but it’s still only one part.

If you’re only talking about electricity, you’re only talking about one-fifth of the energy system.

Principle #2: Who Powers New England Today?

Now let’s narrow our focus to electricity.

If someone proposes redesigning New England’s electric system, the first question should be simple:

How does it work today?

Here’s who powers New England in a typical year, according to ISO New England, the independent organization responsible for operating the region’s electric grid.

ResourceShare of New England ElectricityNatural Gas51.0%Nuclear23.0%Net Imports7.0%Hydroelectric6.0%Solar4.1%Wind3.9%Refuse (Trash-to-Energy)2.2%Wood1.7%Oil1.0%Landfill Gas0.3%Coal0.2%

Spend a minute looking at those numbers.

If you stopped a hundred people on the street and asked what powers New England, I suspect many would answer wind and solar.

The numbers tell a very different story.

Natural gas alone generates more than six times as much electricity as wind and solar combined. Nuclear alone produces nearly three times as much.

There’s another lesson hidden in the table. When people hear the word renewable, they usually picture wind turbines and solar panels. But ISO New England’s renewable generation also includes electricity produced by burning municipal trash, burning wood, and capturing landfill gas.

That’s why it’s important to look beyond the labels and understand what’s actually in the numbers.

The current mix didn’t happen by accident. Some resources became the backbone of the system because they provide capabilities the grid depends on every day. Others were added more recently to advance public policy goals. Understanding which is which is part of understanding the system.

Natural gas provides dispatchable electricity that operators can increase or decrease as demand changes. Nuclear provides large amounts of around-the-clock electricity. Hydroelectric facilities provide dependable generation and operational flexibility. Oil remains available because there are still winter days when the system calls on it.

Understanding today’s system naturally leads to the next question.

Principle #3: The Question Nobody Asks

Wind, solar, and batteries are often presented as replacements.

But replacements for what?

Wind generates electricity only when the wind blows. Solar generates electricity only when the sun shines. Batteries don’t generate electricity at all. They simply store electricity produced elsewhere and return it later for relatively short periods before they must be recharged.

That doesn’t mean they have no value. It does mean we should ask a question before we spend billions of dollars building more of them.

What function of the existing system does it replace?

If the existing natural gas plants, nuclear plants, hydroelectric facilities, the transmission system, and winter backup resources all still have to remain in place, then we’re not replacing part of the system.

We’re adding another layer to it.

That’s one reason I’ve argued that New England is building two energy systems instead of replacing one with another.

You may agree with that conclusion or disagree with it. That’s fine.

My point is much simpler.

Before someone proposes changing the system, they should first demonstrate that they understand the system they’re trying to change.

Principle #4: New England Is Built for Winter

Every energy system is designed around its toughest operating conditions.

Arizona prepares for extreme summer heat. Florida prepares for hurricanes. New England prepares for winter.

The system isn’t built for a pleasant afternoon in May. It’s built for the coldest week in January, when demand is highest, fuel supplies are stressed, and reliability matters most.

That’s the test.

Not an average day.

The hardest day.

Any proposal that works only under ideal conditions isn’t a plan for New England. It’s a plan for the weather we wish we had.

Principle #5: There Are No Solutions. Only Tradeoffs.

One of the biggest mistakes we make in energy policy is searching for perfect solutions.

They don’t exist.

Every proposal improves something while asking us to accept something else. The question isn’t whether there are tradeoffs. The question is whether those tradeoffs produce a better overall system.

The purpose of this series isn’t to tell you what to think.

It’s to give you better questions to ask.

The next time someone tells you they know how to fix our energy system, don’t start by asking whether you agree with the proposal.

Start by asking whether they understand the system we have today.

If they can’t accurately describe today’s system, I’d be very careful about trusting the rest of their proposal.

Next in the series: What problem are you trying to solve?

Sources

• U.S. Energy Information Administration (EIA) – U.S. Energy Facts (electricity is about 20% of U.S. energy consumption).

• ISO New England – 2025 Annual Resource Mix.

Bad ideas don’t fall apart when you argue with them. They fall apart when you ask the right questions.

During my career with Illinois Central and Canadian National, for a time I ran CN’s locomotive repair facility in Homewood, just outside Chicago. Every night, about 50 locomotives rolled in on inbound trains. Our job was to inspect them, fuel them, repair what needed repairing, and have them ready to pull outbound trains a few hours later.

Every night, we needed 50 locomotives ready for service.

That wasn’t an arbitrary number. The railroad had already done the math. Fifty locomotives were what it took to move every scheduled train and deliver every customer’s freight.

If we had 51, nobody cared. The system didn’t need another locomotive.

But if we only had 49, everything changed. One or more trains didn’t have enough horsepower to pull the tonnage they were assigned. Cars got left behind. Customers didn’t get what they had been promised. Costs went up. And I got my ass chewed.

That experience taught me something I’ve never forgotten.

Complex systems don’t care about good intentions. They care whether the system works.

I’ve come to believe our energy system is no different.

Every election brings promises. We’ll hear that we need more renewables. We’ll hear we need more natural gas. We’ll hear we should electrify everything. Others will argue for nuclear power, batteries, offshore wind, carbon taxes, or new transmission lines.

Some of those ideas may be good. Some may be terrible. Most are more complicated than the campaign slogan.

Over the last year, as I’ve researched and written about these issues, I realized I was asking the same questions over and over again. Eventually, it dawned on me that I wasn’t really evaluating individual proposals. I was evaluating whether they made the entire energy system work better—or simply shifted costs and risks somewhere else.

Somewhere along the way, I realized those questions had become the framework I was already using.

Not because they’re complicated. Quite the opposite. They force us to strip away the politics, the marketing, and the slogans and focus on whether an idea can actually deliver what it promises.

Over the next several weeks, I’m going to use these same five questions to evaluate every energy proposal that comes across my desk—whether it comes from a candidate, a utility, an environmental organization, an industry group, a regulator, or even from me.

1. Do you understand the system we have today?

This sounds obvious, but it may be the question we skip most often.

Take New England’s energy system. We hear calls to electrify home heating, transportation, and much of our economy while, at the same time, many oppose new pipelines, new natural gas generation, new transmission lines, and often even nuclear power.

Maybe that’s the right answer. Maybe it isn’t.

But before changing a system, you ought to demonstrate that you understand the one you’re changing. What keeps homes warm, businesses operating, and the lights on during the coldest week of January? Where does that energy come from? What constraints already exist? How does one decision affect the rest of the system?

You can’t improve a system you don’t understand.

2. What problem are you trying to solve?

We often argue about solutions before we’ve agreed on the problem.

Are we trying to lower costs? Reduce emissions? Improve reliability? Strengthen national security? Create jobs?

Those are all legitimate goals, but they don’t always point to the same answer.

Before we debate solutions, we should agree on the problem we’re trying to solve.

3. Are you doing all the math?

This may be the most important question of all.

One of the biggest issues facing New England is that we’re trying to build two energy systems at the same time.

We’re adding wind, solar, batteries, and other renewable resources. At the same time, we still need natural gas pipelines, power plants, transmission lines, fuel storage, and the infrastructure that keeps homes heated and electricity flowing when renewable generation falls short.

Whether you support that strategy or oppose it isn’t the point.

The point is that both systems cost money. If someone only talks about the cost of one system—or only the benefits of the other—they aren’t doing all the math.

4. What do you have to believe?

Every proposal rests on assumptions.

Maybe battery costs fall dramatically. Maybe offshore wind performs exactly as projected. Maybe electricity demand grows more slowly than expected. Maybe natural gas prices stay low. Maybe permitting becomes easier.

None of those assumptions are impossible.

But they are assumptions.

Good analysis doesn’t hide assumptions. It makes them visible so everyone can decide whether they’re reasonable.

5. How will we know if it worked?

This is the accountability question.

If someone promises lower energy costs, how much lower? Compared to whom? By when?

If someone promises lower emissions, what will success look like? If someone promises greater reliability, how will we measure it?

Predictions shouldn’t disappear after Election Day. They should become scorecards.

One of the reasons I write so often about where Maine ranks on energy costs is simple: if affordability is the goal, we should be keeping score.

I don’t expect everyone to agree with my conclusions. In fact, I hope sometimes you don’t.

What I do hope is that we begin asking better questions. Good ideas can survive tough questions. Bad ideas usually can’t.

These five questions are the standard I’ll use to evaluate every energy proposal I write about. I’ll apply them whether the proposal comes from a Republican or a Democrat, a utility or an environmental organization, an industry group, a regulator—or even from me.

I hope you’ll use them too.

Not because they’ll tell you what to think.

Because they’ll help you decide what deserves to be believed.

During my time in Homewood, one missing locomotive could leave a train sitting on the tracks because the railroad no longer had the horsepower to deliver what it had promised.

Our energy system is no different.

Every proposal makes promises.

Before we accept them...

Let’s make sure the system can deliver them.

The second shift that never gets added — and the young Mainer who leaves because the career he wanted is somewhere else. The new production line that goes to another state, taking its jobs, suppliers and tax base with it. The factory that looks at Maine, runs the numbers and quietly crosses us off the list before we ever knew we were being considered.

No press release. No angry employees at the State House. No headline announcing that 200 jobs are not coming. They just never come.

Maine knows what losing jobs looks like. We have watched mills close, taking good jobs and local tax base with them, while nothing comes along to replace them. Too many of our young people discover that the careers they want are somewhere else.

And in a state where roughly 400,000 people rely on MaineCare, every lost job and every missed investment makes the problem worse: fewer people and businesses supporting the system, and fewer good jobs that give people a path out of dependence on it.

Energy is not the only reason businesses make these decisions. But it is one of the few costs that can hit a company year after year and is largely beyond management’s control. A manufacturer can improve productivity, negotiate harder with suppliers and invest in better equipment. It still needs power to run the plant and fuel to make the product.

If you are deciding where to build the next plant, you are not trapped here. You can run the numbers and go where you can be successful.

So I did.

Let’s Go Shopping for a State

I compared Maine with four very different states: Ohio, Washington, Arkansas and South Carolina.

Ohio was an obvious place to start. CNBC just ranked it the No. 1 state in America for business in 2026. Nearly 12 million people. A deep manufacturing base. Major highways and railroads. Access to enormous markets and a long history of actually making things.

Then I spread out the map. Washington gives us the West and a completely different political and energy model. Arkansas gives us the South-Central United States. South Carolina is one of America’s great manufacturing success stories.

Different regions. Different politics. Different economies. Different energy systems.

I added Maine and ran the numbers.

Put Real Money on the Table

Energy prices are interesting, but businesses do not pay rankings. They pay bills.

Imagine a medium-sized manufacturer using 10 million kilowatt-hours of electricity and 100,000 million Btu of natural gas each year. Every manufacturer is different, but this gives us a reasonable plant with meaningful electric and natural gas loads.

Using 2024 U.S. Energy Information Administration data, here is what that same plant would spend each year:

StateElectricityNatural GasTotal Energy CostSouth Carolina$684,000$472,000$1,156,000Arkansas$661,000$768,000$1,429,000Ohio$710,000$724,000$1,434,000Washington$661,000$1,111,000$1,772,000Maine$1,246,000$838,000$2,084,000

And there it is.

South Carolina: about $1.16 million a year. Ohio and Arkansas: about $1.43 million. Even Washington: about $1.77 million.

Maine?

$2.08 million.

That is when I thought of Rodney Dangerfield.

For those who do not remember him, Rodney had a routine where the audience knew its part. He would say:

“Oooooh, she is so ugly.”

And the crowd would yell back:

“HOW UGLY IS SHE?”

Then Rodney delivered the punchline.

So let’s run the numbers.

The same manufacturer would spend about $312,000 more every year on energy in Maine than in Washington, about $650,000 more than in Ohio, about $655,000 more than in Arkansas, and about $928,000 more than in South Carolina.

Now extend today’s price difference over 20 years. No inflation. No escalation. Just hold the current gap constant.

Even then, our Maine manufacturer would spend about $6.2 million more on energy than in Washington, $13 million more than in Ohio, $13.1 million more than in Arkansas and $18.6 million more than in South Carolina.

Imagine you are sitting in the boardroom. Same company. Same product. Same management team. Same capital.

One location comes with an $18.6 million energy disadvantage over 20 years.

Where are you going to build?

What About the Businesses Already Here?

The site-location exercise is hypothetical. The problem for existing Maine businesses is not.

A company already here may have millions of dollars tied up in a plant, hotel, warehouse or store. Its workers live here. Its customers are here. Its equipment may literally be bolted to the floor. It cannot simply move every time the electric bill goes up.

So it absorbs the increase. Then another. It tries to become more productive. It delays equipment. It puts off an expansion. It raises prices where it can and accepts lower margins where it cannot.

Eventually something gives.

The losses add up. A town loses another taxpayer. A local business loses another customer. More people need help, while fewer people and businesses are left to pay for it.

That is the cycle Maine has to break.

We cannot keep talking about affordability and opportunity while treating energy costs like somebody else’s problem. Businesses run the numbers. They compare states. They go where they can succeed. And the businesses already here eventually run the numbers too.

So how ugly is Maine’s energy problem?

Ugly enough that one manufacturer faces an $18.6 million disadvantage over 20 years. Ugly enough that some companies will never come and some already here will stop investing. Ugly enough that more young Mainers will leave to find opportunity somewhere else.

Maine should aspire to more than this.

We should want a state where our kids can build careers without leaving home. Where towns grow their tax base instead of watching it shrink. Where good jobs create independence and opportunity instead of more dependence on government.

That will not happen by accident. And it will not happen if we keep making Maine one of the most expensive places in America to build, invest and employ people.

Energy policy is economic policy.

Until we understand that, we should not be surprised by what we lose.

Massachusetts is experimenting with electric school buses that send power back to the grid during periods of peak demand. Across Europe, utilities are using dynamic pricing to push people toward using electricity when more of it is available. Smart thermostats can adjust consumption remotely. Electric vehicles are increasingly discussed not just as transportation, but as batteries that can help support the grid.

The idea is no longer simply to build a grid that supplies electricity when customers want it. Increasingly, the idea is to influence when—and sometimes whether—they use it.

Charge your car later. Run the dishwasher overnight. Pre-cool the house before the afternoon peak. Let the utility adjust the thermostat. Pay more when the grid is tight. Someday, perhaps, let the grid borrow electricity from the battery sitting in your driveway.

While all of this is happening, New York is worrying about reserve margins. New England remains constrained by inadequate natural gas pipeline capacity. Governors who spent years opposing additional pipeline infrastructure are reconsidering. Electricity prices across the Northeast continue to climb.

I don’t think these are separate stories.

We are designing customers around the limitations of the electric grid instead of building an electric grid capable of serving customers.

For most of American history, rising electricity demand was a sign of progress. When homes added air conditioning, we built more power plants. When factories expanded, we built generation and transmission. When suburbs grew, utilities expanded with them. Growing demand went hand in hand with a growing economy.

Today, we increasingly treat demand as the problem.

It reminds me of the dot-com boom, when smart people with enormous amounts of venture capital built clever apps and websites to solve problems no one actually had. The technology was impressive. The business plans were polished. The only thing missing was a customer who wanted the product.

Much of modern energy policy feels the same way.

Who asked for a refrigerator that waits for permission from the grid? Who wants to plan dinner around the hourly price of electricity? Who bought an electric car because they hoped the utility might someday drain the battery during a heat wave? Who decided the great promise of modern technology was a thermostat someone else could control?

Factories do not exist to manage the grid. They exist to make things. A paper mill makes paper. A steel mill makes steel. A semiconductor plant makes chips. When electricity becomes too expensive, manufacturers produce less, delay investment, or move production somewhere else. There is nothing efficient or innovative about that. It means the energy system has become too expensive to support the economy that depends on it.

And the factory that never gets built is harder to see. Investment follows affordable, reliable energy. Increasingly, it is flowing toward states that have it and away from states that do not.

Previous generations would have looked at rising electricity demand and built more power plants. We are building apps to tell people when they can run the dishwasher while manufacturers ask whether it still makes sense to produce in high-cost electricity markets.

That is not innovation. It is an admission that we have failed to build enough energy.

A few weeks ago, I wrote about abundance. I argued that the energy debate has been framed incorrectly for years. It is not really about wind versus natural gas, solar versus nuclear, or Republicans versus Democrats. It is about two very different ways of thinking.

One asks how much energy a growing economy might need and then builds the infrastructure to support it. The other looks at how much energy is available and finds increasingly complicated ways to live within the constraint.

I think we are choosing the second path.

Just look at the language: demand response, peak shaving, load shifting, behavioral pricing, managed charging, flexible load, curtailment. Different terms, different programs, same basic idea. Change the behavior of the customer because the system cannot deliver enough affordable electricity when customers want it.

The grid no longer simply serves demand. Increasingly, demand is expected to serve the grid.

AI makes the contrast especially clear. Artificial intelligence, advanced manufacturing, semiconductor fabrication, and other emerging industries will require enormous amounts of electricity. Some states see that demand and ask how quickly they can build enough generation and infrastructure to capture the investment. Much of the Northeast asks how the grid will survive it.

Maine politicians warn about data centers overwhelming our electric system even as very few data centers choose to locate here at all. I keep coming back to the same uncomfortable observation: instead of asking why investment is going elsewhere, we are debating how to manage growth that isn’t coming.

And electric school buses may be the perfect symbol of how far this thinking has gone.

Maine has already lived through the reality. Electric buses have been sidelined by battery warnings, loss of power, brake problems, failed inspections, charging problems, and other mechanical failures. Some districts were left with buses they could not reliably operate, while the state itself now advises districts with mixed fleets to assign electric buses to routes that fit within their shortest winter range.

Think about that. We spend heavily to replace a proven school bus with one that requires special planning around its winter limitations. Then someone discovers another supposed benefit: perhaps the battery can help support the electric grid.

We created one expensive problem and found a new use for it managing another.

That is scarcity feeding on itself.

Maine should be preparing for a future in which people use more energy, not less. We should want new factories, new technologies, growing businesses, more homes, higher wages, and enough economic opportunity that our own kids can afford to build their futures here.

All of that will require more energy. A lot more.

The question is whether we intend to build it or keep finding increasingly complicated ways to live without it.

That is what happens when the grid starts managing us.

Regular readers know I have a habit of connecting dots that don’t appear to belong together.

One week it’s offshore wind. The next it’s electricity prices in Germany, pipeline politics in New England, reserve margins in New York, or AI data centers in Texas. At first glance, they seem like completely unrelated stories.

Over the past few weeks, I’ve watched Europe experiment with behavioral economics and dynamic electricity pricing because its grid is increasingly constrained. I’ve watched Massachusetts celebrate electric school buses feeding power back into the grid during periods of peak demand. I’ve watched New England governors quietly rediscover the value of natural gas pipelines after spending years opposing them. And I’ve watched politicians in Maine warn that AI data centers could overwhelm our electric system, even though those investments are overwhelmingly choosing to locate somewhere else.

Then it hit me.

Instead of asking why investment is going elsewhere, we’re debating how to manage growth that isn’t coming.

As I worked through my gubernatorial candidate scorecards over the past several months, I thought I was writing about offshore wind, pipelines, electricity prices, ISO-New England, and the future of natural gas. Looking back, I think I was writing about something much bigger.

The irony is that all of these stories are connected.

For much of the last two decades, Maine and much of the Northeast have pursued an energy philosophy built on the assumption that electricity is becoming increasingly scarce and therefore must be managed. We subsidize some technologies, discourage others, expand mandates, electrify more sectors of the economy, and spend an extraordinary amount of time discussing when people should use electricity rather than how to produce enough of it.

As supply becomes constrained, policymakers face a choice. They can build more energy infrastructure, or they can find ways to manage demand. Europe has increasingly embraced dynamic pricing, behavioral economics, and demand response programs to shift electricity consumption. At the same time, governors across New England who spent years opposing natural gas pipelines are beginning to acknowledge that the region needs additional energy infrastructure after all. Reality has a way of imposing itself.

Meanwhile, another group of states has chosen a different path.

Texas, Tennessee, Ohio, Indiana, and much of the Southeast continue building generation, pipelines, transmission, and industrial infrastructure because they understand something previous generations of Americans took for granted: economic growth requires energy, and lots of it.

The same states attracting artificial intelligence, advanced manufacturing, and industrial investment tend to be states with abundant, affordable electricity. Meanwhile, many of the nation’s highest electricity prices are concentrated in California and the Northeast, regions that have spent years making it more difficult to build the infrastructure that supports growth.

Politicians warn that AI data centers could overwhelm Maine’s electric grid. The irony is that very few data centers are choosing to locate here at all. They are investing in states with abundant, affordable electricity while Maine debates how to accommodate growth that has largely gone somewhere else. Businesses routinely cite energy costs as a competitive disadvantage, yet much of our public discussion remains focused on managing demand instead of expanding supply.

The economy emerging over the next twenty years will require enormous amounts of electricity. Artificial intelligence, advanced manufacturing, electrified transportation, and technologies we cannot yet imagine will all depend on abundant, reliable power. States that can provide it will attract investment. States that cannot will watch that investment happen somewhere else.

This is not an argument against wind, solar, hydroelectricity, batteries, natural gas, or nuclear power. Every one of those technologies can contribute to a stronger energy system. The objective should never have been maximizing one technology or minimizing another. The objective should be abundant, reliable, affordable energy capable of supporting economic growth.

It finally occurred to me that all of these seemingly unrelated stories are really about the same thing. They reflect two fundamentally different philosophies of energy policy.

One assumes scarcity and asks how best to manage it.

The other assumes abundance and asks how to create more of it.

Because abundant energy attracts investment. Investment creates jobs. Jobs create opportunity. Scarcity does the opposite. It raises costs, discourages investment, and slowly chips away at a state’s competitive position until opportunity begins showing up somewhere else.

Maine is one of the most beautiful places on earth. We have more than 3,300 miles of coastline, mountains, forests, lakes, and communities that people across the country dream about calling home. Our challenge has never been convincing people that Maine is a great place to live.

Our challenge is creating enough economic opportunity that our own kids can afford to stay and that others can build a future here.

If Maine wants to compete for those jobs and those industries, we have to stop treating energy as something to ration and economic growth as something to be discouraged.

We need to start thinking about abundance again.

Because prosperity has always followed abundant energy.

It always will.

With Maine’s gubernatorial primary approaching, energy policy is one of the top issues voters are hearing from the candidates.

For nearly eight years, Maine has pursued one of the most aggressive climate and electrification agendas in the country through Maine Won’t Wait.

Billions of dollars have been invested. Thousands of heat pumps have been installed. Solar development has expanded dramatically. Electrification has become a central objective of state policy.

The promises have been made. The money has been spent. The policies have been implemented.

Now we can evaluate the results.

Electricity prices have more than doubled since 2020. Maine now has some of the highest electricity rates in the United States. New England remains heavily dependent on natural gas for electric generation. LNG imports have increased. Oil remains a constant part of the regional generation mix.

Economic growth has stalled. Maine’s economy recorded essentially zero growth last year, and state forecasts project little improvement in the years ahead. At the same time, much of Maine’s emissions reduction is attributable to industrial contraction, mill closures, and declining industrial energy consumption rather than the energy transition itself.

Those facts do not determine how anyone should vote. They do provide a framework for evaluating the candidates who want to lead Maine for the next four years.

Electricity prices are not the only measure of success, but they are one of the most important. Affordable energy affects household budgets, business investment, economic growth, and competitiveness.

Price is only part of the story, however. Reliability and energy security matter as well. After years of renewable expansion, New England remains heavily dependent on natural gas, while LNG imports and oil-fired generation continue to play important roles during periods of high demand.

Those realities provide the context for evaluating the candidates seeking to become Maine’s next governor.

Disclosure

I know some of these candidates better than others.

I worked with Angus King III for approximately seven years and consider him a friend. I recruited Jonathan Bush to Maine while serving as CEO of Maine & Company, and we have remained in contact over the years. David Jones and I have shared a radio microphone for the past four years discussing energy, politics, and Maine’s future.

I met individually with several candidates, reviewed campaign materials, debate performances, public statements, media interviews, and applied the same evaluation criteria to everyone. Bobby Charles was invited to participate in a meeting but did not respond.

My goal is not to tell anyone how to vote. It is to evaluate how each candidate approaches Maine’s energy challenges and what results their policies are likely to produce.

How I Evaluated the Candidates

Every candidate in this race says they support affordable energy, reliable energy, economic growth, and environmental stewardship. The challenge is that those goals often compete with one another.

For this evaluation, I focused on five questions:

• Will this candidate’s policies lower energy costs?

• Will they improve reliability?

• Will they strengthen energy security?

• Will they support economic growth?

• Do they demonstrate a strong understanding of how New England’s energy system actually works?

I did not grade candidates on their intentions. I graded them on the likely outcomes of the policies they support.

Reasonable people can disagree with my conclusions, but after nearly eight years of Maine Won’t Wait, I believe voters deserve a discussion focused on results.

2026 Maine Governor Energy Scorecard

The following scorecard reflects my assessment of each candidate’s likely impact on energy affordability, reliability, energy security, economic growth, and their understanding of New England’s energy system.

The grades reflect my assessment of likely policy outcomes, not intentions, character, or leadership ability.

What the Scorecard Revealed

The energy divide in this race does not always follow party lines.

The candidates differ less on identifying Maine’s energy challenges than they do on how to solve them.

Some candidates begin with affordability, reliability, and economic growth. Others begin with climate objectives and renewable energy deployment.

Those differences help explain the grades that follow.

Democratic Candidates

Angus King III

Of all the Democratic candidates, Angus King III has the strongest understanding of New England’s energy system.

My disagreements with Angus are not about the problems. They are about the solutions.

Angus has a strong grasp of electricity markets, utility regulation, reliability, economic development, climate policy, and the practical realities of operating an energy system in New England.

Where we differ is in his belief that wind and solar should remain part of the solution set. Angus is trying to solve two problems simultaneously: energy and climate.

I believe that strategy has not produced the promised results. Angus believes the region should continue pursuing an all-of-the-above approach.

Whether voters agree with Angus’s conclusions or mine, he has a deep understanding of the issues and tradeoffs associated with Maine’s energy choices. That understanding is reflected in his score.

Troy Jackson

Troy Jackson approaches energy through the lens of mills, manufacturing, and working families.

Troy’s first question is usually not about emissions. It’s about jobs. Can a paper mill stay open? Can a manufacturer compete? Can a family afford the electric bill? That perspective separated him from several other Democratic candidates in this evaluation.

Throughout the campaign, Troy consistently returned to the economic consequences of energy policy. He understands that high energy costs affect more than utility bills. They affect jobs, wages, investment decisions, and whether businesses choose to expand in Maine or somewhere else.

I do not agree with every energy policy Troy supports. However, I appreciated that he viewed energy through the lens of affordability and economic competitiveness rather than treating it solely as a climate issue.

That focus on jobs, manufacturing, and working families helped distinguish him from several other Democratic candidates and is reflected in his score.

Hannah Pingree

Hannah Pingree was the principal architect of Maine Won’t Wait, Maine’s climate and energy strategy. Any evaluation of Hannah’s energy policies must begin with that fact.

That does not mean Hannah lacks understanding of energy policy. Quite the opposite. She understands the strategy better than almost anyone in the race because she helped create it.

The question is not whether Hannah understands the strategy. The question is whether the strategy produced the promised results.

Over the last eight years, electricity prices have more than doubled. New England remains heavily dependent on natural gas. LNG imports have increased. Oil remains a constant part of the regional generation mix. Maine’s economy has stalled, and much of the state’s emissions reduction is attributable to industrial contraction and declining industrial energy use rather than the energy transition itself.

Supporters of Maine Won’t Wait argue the strategy is working and simply needs more time. I disagree. After eight years, voters have enough evidence to evaluate the results.

If voters believe the last eight years have been successful, Hannah offers the clearest path forward. If they do not, it is difficult to argue for more of the same.

Nirav Shah

Of all the candidates in the race, I found Nirav Shah’s energy platform the most difficult to distinguish from the policies pursued over the last eight years.

That is not necessarily a criticism. Many voters may view the Mills administration’s approach as a success and want to continue in the same direction. My challenge was identifying where Dr. Shah’s energy policies would materially differ from those already being implemented.

For voters who are satisfied with the results of the last eight years, that continuity may be appealing. For voters seeking a different direction, I did not see evidence that Dr. Shah would significantly alter Maine’s current course.

Shenna Bellows

Shenna Bellows’ energy positions generally represent a continuation of Maine’s current direction.

Like several other Democratic candidates, she supports aggressive climate goals, renewable energy deployment, and continued electrification. The challenge for me is that these policies have already been in place for much of the last eight years.

For voters who believe Maine is headed in the right direction on energy, Bellows offers continuity. For voters who believe affordability, reliability, and economic competitiveness have deteriorated, her platform offers little reason to expect a different outcome.

Republican Candidates

Ben Midgley

Ben Midgley begins with affordability.

Throughout the campaign, Ben consistently returned to a question that many policymakers seem to overlook: Can Maine families and businesses afford the energy system we are building?

Ben’s approach is rooted in the belief that affordability, reliability, and economic growth are not competing objectives. They are prerequisites for everything else. He argues that if energy becomes too expensive, Maine will struggle to attract investment, retain manufacturing jobs, and remain competitive with other states.

I found Ben’s focus on cost, economic competitiveness, and energy security both clear and consistent. Whether discussing electricity, natural gas, or economic development, he repeatedly returned to the importance of affordable energy as the foundation of a healthy economy.

What separates Ben from much of the field is his willingness to challenge assumptions that many politicians treat as settled. He is willing to question whether renewable energy subsidies are producing the promised results. He is willing to question whether Maine’s current climate policies are improving affordability. He is willing to ask whether the state is becoming more competitive or less competitive as a result of its energy choices.

He is also one of the few candidates willing to argue that some existing policies should be repealed rather than simply modified. Whether the issue is renewable energy subsidies, RGGI, or other elements of Maine’s current energy framework, Ben’s approach is not to make incremental adjustments around the edges. It is to ask whether the policy is achieving its intended purpose and, if not, whether it should continue at all.

That perspective, combined with a well-developed policy framework, is reflected in his score.

Jonathan Bush

Jonathan Bush begins with economic growth.

I recruited Jonathan to Maine when I was CEO of Maine & Company, and we have remained friends and stayed in contact over the years. During that time, I have watched him build businesses, create jobs, and think deeply about what allows economies to grow and prosper.

Jonathan approaches energy policy primarily through the lens of competitiveness, investment, and Maine’s ability to attract and retain businesses. His starting point is not energy policy itself. His starting point is economic growth. What kind of energy system allows Maine businesses to invest, expand, hire people, and compete?

That perspective leads him to many of the same conclusions reached by Ben Midgley. Jonathan understands that high energy costs discourage investment, make Maine less competitive, and ultimately reduce economic opportunity. He understands the importance of reliability, fuel security, and dispatchable generation. He also recognizes that businesses make long-term investment decisions based on confidence that affordable and reliable energy will be available for decades, not election cycles.

What impressed me most about Jonathan’s approach is that he sees energy policy as part of a larger economic system. Housing, permitting, workforce development, taxation, infrastructure, and energy all interact. A state that gets one of those pieces wrong can struggle. A state that gets several wrong can fall behind quickly.

If Ben Midgley starts with affordability and works forward, Jonathan Bush starts with economic growth and works backward. Interestingly, they arrive at many of the same conclusions. That combination of economic understanding, energy literacy, and focus on long-term competitiveness is why Jonathan earns the highest grades in this evaluation.

Owen McCarthy

Owen McCarthy presented the most comprehensive energy framework in the race.

Of all the candidates, Owen provided the most detailed and fully developed discussion of energy policy. His positions reflected a broad understanding of affordability, reliability, energy security, economic growth, permitting, infrastructure, and market structure.

What impressed me about Owen was not a single energy proposal. It was the amount of thought that clearly went into connecting energy, housing, permitting, infrastructure, workforce development, and economic growth into a coherent strategy. Unlike many candidates who discuss energy as a standalone issue, Owen recognizes that it is one component of a larger system that determines whether Maine grows, stagnates, or falls behind.

Like Midgley and Bush, Owen understands that affordable and reliable energy is essential to economic growth. He understands New England’s dependence on natural gas, the importance of dispatchable generation, and the economic consequences of rising electricity costs. He also recognizes that energy policy cannot be separated from broader questions of permitting, infrastructure development, and the state’s ability to attract investment.

The reason Owen falls slightly below Midgley and Bush is not because he misunderstands the issues. It is because I found him somewhat less willing to challenge some of the underlying policies that contributed to Maine’s current situation. While his solutions are thoughtful and well-developed, they tend to focus more on improving existing systems than fundamentally rethinking them.

Still, Owen’s understanding of the interaction between energy, economic growth, and public policy is among the strongest in the field, which is why he earns some of the highest grades in this evaluation.

David Jones

David Jones is the strongest advocate for nuclear energy in the field.

David Jones and I have shared a radio microphone for the past four years. We have discussed energy, economic development, public policy, and Maine’s future dozens of times.

David approaches energy the same way he approaches most issues: through the lens of common sense.

He understands that high energy costs hurt families, businesses, and economic growth. He also recognizes that Maine cannot build a prosperous economy on expensive and unreliable energy.

Of all the candidates in the race, David is probably the strongest advocate for nuclear energy. He sees nuclear power as a long-term solution to the affordability, reliability, and energy security challenges facing both Maine and New England. On that issue, I believe he is directionally correct.

Where David falls short of the highest-rated candidates is not in recognizing the problem. It is in developing a detailed roadmap for solving it. Compared to Midgley, Bush, and McCarthy, I found his overall energy platform less comprehensive and less developed.

Still, after four years of conversations, I have little doubt that David understands the direction Maine should be moving. I simply found fewer specifics that allowed me to score him as highly as candidates who have spent more time developing detailed energy policies.

Garrett Mason

Garrett Mason approaches energy as a practical economic issue.

Unlike several of the other candidates, I have not had extensive conversations with Garrett Mason about energy policy. My assessment is based primarily on his public statements during this campaign and his record as a State Senator.

What stood out to me was Garrett’s practical approach to the issue. Like several of the highest-rated candidates in this evaluation, he views energy as an economic issue first. He understands that affordability, reliability, and energy security are not abstract policy goals. They are prerequisites for economic growth, business investment, and a higher standard of living.

Based on his public statements and legislative record, Garrett recognizes many of the same challenges identified by Midgley, Bush, and McCarthy. He understands that high energy costs undermine competitiveness and that Maine cannot grow its economy while ignoring affordability and reliability.

Where I struggled was in finding the same level of detail and policy development offered by the top-tier candidates. Garrett generally identifies the right issues and points in the right direction, but I found fewer specifics regarding how he would implement those ideas as governor.

That does not place him in the wrong camp. He is focused on the right priorities. The difference is that I found less information available to evaluate the path from diagnosis to implementation, which is why he falls slightly below the top tier.

Robert Wessels

Robert Wessels consistently challenged assumptions that have become common in Maine’s energy debate.

After meeting with him and discussing energy policy, I came away with the view that Robert understands many of the same affordability, reliability, and economic growth challenges identified by the strongest candidates in the field.

Like Garrett Mason and David Jones, the challenge is not recognizing the problem. The challenge is the level of detail and development behind the proposed solutions.

Still, I found myself agreeing with his assessment of many of Maine’s energy challenges. He demonstrated a practical understanding of affordability, reliability, economic growth, and competitiveness. That understanding, combined with a willingness to challenge assumptions that have become common in Maine’s energy debate, earned him solid grades across the board.

Bobby Charles

Bobby Charles diagnoses many of Maine’s energy challenges correctly.

Bobby was the one major candidate in the race who never responded to my request to meet, so this assessment is based entirely on his public statements, campaign materials, debate answers, and policy positions.

On the surface, Bobby and I agree on a number of things. He talks about affordability. He talks about reliability. He talks about the damage high energy costs do to families, businesses, and Maine’s economy.

Where we differ is that identifying a problem is only the beginning.

Throughout the campaign, Bobby frequently proposed solutions that struck me as simplistic, impractical, or beyond the authority of a governor to implement. His suggestion during a Chamber debate that Maine should generate significantly more electricity from wood is one example.

Energy policy is complicated. New England’s electric system is complicated. Good intentions and strong rhetoric are not enough.

As I reviewed Bobby’s positions, I repeatedly found myself agreeing with the problem he was describing while questioning whether he fully understood the constraints, tradeoffs, and realities involved in solving it.

That is why Bobby received the lowest scores among the Republican candidates. In my view, his diagnosis was often stronger than his prescription.

Conclusion

Elections are about accountability.

For nearly eight years, Maine has pursued one of the most aggressive climate and electrification agendas in the country through Maine Won’t Wait. The promises have been made. The money has been spent. The policies have been implemented.

Electricity prices have more than doubled. New England remains heavily dependent on natural gas. LNG imports have increased. Oil remains part of the regional generation mix. Economic growth has stalled.

Those are the results.

The candidates running for governor are now asking voters to evaluate them.

Some are offering a continuation of the current approach. Others are offering a different path.

The voters get to decide.

The recent May heat wave in New England was not historically extreme. That is precisely why it mattered.

Under relatively favorable spring conditions for solar generation, the grid still leaned heavily on natural gas, nuclear power, hydroelectric generation, imports, and even some oil-fired power as evening demand rose and solar production faded with the sunset.

That should force a serious conversation.

Because if the system still depends overwhelmingly on dispatchable generation during a relatively mild spring heat event, what exactly is the plan during prolonged winter cold, tighter fuel conditions, or more severe summer peaks?

For more than a century, the electric system operated around a simple promise: when people flipped the switch, the power would be there.

That expectation became so deeply embedded in modern life that most people stopped thinking about electricity altogether. It was simply there when needed — like water from the tap or daylight in the morning.

Utilities built systems around that expectation. Regulators demanded it. Customers expected it. The mission was straightforward: build enough generation, fuel supply, redundancy, and reserve margin to survive the hardest conditions the system might reasonably face.

That is how infrastructure works.

The people who run electric grids still understand reliability. So do gas utilities. They have to. Their systems are designed around the hardest days, not the easiest ones.

You build for the cold snap.

You build for the heat wave.

You build for equipment failures, fuel constraints, and demand spikes because those conditions eventually arrive.

But in Maine and across New England, the public conversation around energy increasingly drifted away from how infrastructure systems are actually built and operated.

Instead, the discussion became dominated by averages:

annual renewable production,

annual emissions reductions,

nameplate generating capacity,

and modeled performance under favorable conditions.

Part of that shift was political. Emissions became the dominant public metric in energy discussions, while the realities of operating large-scale infrastructure systems became less visible to most people. Annual production numbers and nameplate capacity are easy to communicate. Reliability during difficult operating conditions is much harder to explain.

At the same time, the marketing surrounding wind and solar often emphasized annual output and theoretical replacement potential while minimizing discussions around intermittency, duration, dispatchability, fuel security, and reliability during difficult operating conditions. Many policymakers repeated those simplified narratives without fully understanding the complexity of maintaining a stable electric grid in a region with constrained fuel infrastructure and severe winter conditions.

The people operating the systems still understand the difference.

Grids do not fail on annual averages. They fail during concentrated periods of stress when demand remains high, fuel supplies tighten, weather conditions deteriorate, or large amounts of intermittent generation become unavailable at the same time.

And now New England is pushing even more onto the electric system:

heat pumps,

electric vehicles,

and broader electrification.

At the same time, dispatchable generation continues retiring, pipeline expansion was blocked for years, reserve margins are tightening, and major infrastructure projects have become politically toxic.

For a while, those contradictions were partially masked by relatively modest demand growth and the fact that the system still retained enough dispatchable infrastructure to absorb stress events.

But the underlying realities never changed.

The margin for error is getting thinner.

One of the biggest disconnects in the modern energy debate is that the public conversation increasingly revolves around averages while the grid itself operates around peaks.

Utilities do not build systems for the average day in October. They build them for the brutal stretch when it is below zero, the wind is not blowing, the sun is setting at 4:00 PM, people are trying to heat their homes, industry still needs power, and something somewhere on the system has already failed.

Hospitals are not designed around the average number of patients on a quiet Tuesday afternoon. They are built to handle emergencies, surges, disasters, and the moments when failure would be catastrophic. Power systems work the same way.

But much of the modern discussion around energy skips over that reality entirely.

Annual renewable production sounds impressive. Nameplate capacity sounds impressive. Emissions reductions sound impressive. None of those numbers necessarily tell you whether enough electricity will actually be available at 7:00 PM during a major winter event or after several difficult days in a row.

That problem becomes even larger as electrification accelerates.

In New England, we are steadily moving more of daily life onto the electric system while simultaneously narrowing the margin for error underneath it. Heat pumps push more winter heating demand onto the grid. Electric vehicles add new load. At the same time, dispatchable generation continues retiring, pipeline constraints remain unresolved, and infrastructure expansion becomes harder every year.

In its 2026 Summer Reliability Assessment, the North American Electric Reliability Corporation (NERC) warned that large portions of the country are entering a period of rising reliability risk as electricity demand accelerates and reserve margins tighten.

The people responsible for operating infrastructure systems already know why.

Electricity demand is rising again after years of relatively modest growth. At the same time, reserve margins are shrinking, dispatchable generation continues retiring, fuel infrastructure remains constrained in places like New England, and major projects have become slower, harder, and more political to build.

For years, a lot of those contradictions stayed hidden because the system still had enough excess capacity and dispatchable infrastructure to absorb difficult conditions.

But the underlying realities never changed.

The grid still has to survive:

the cold snap,

the heat wave,

the fuel constraint,

the equipment failure,

the period when demand spikes and weather-dependent generation underperforms at the same time.

The warning lights are starting to flicker.

At some point, energy policy stops being theoretical.

Regions that make electricity expensive, constrain infrastructure, discourage industrial development, and operate with shrinking reliability margins eventually pay an economic price for it. New England increasingly looks like that warning.

Maine’s economic growth has stagnated. Employment growth forecasts are essentially flat for years ahead. Young people continue leaving for opportunity elsewhere. Electricity prices remain among the highest in the country while the region continues making large-scale infrastructure difficult to build.

At the same time, much of the economic growth in America is flowing toward regions that chose a very different path. States with abundant energy, expanding infrastructure, lower power costs, and a willingness to build are attracting manufacturing, industrial investment, population growth, logistics hubs, petrochemical expansion, AI infrastructure, and large-scale economic development.

That is not an accident.

The places that build and power growth will attract the future. The places that manage scarcity will watch it happen somewhere else.

“It was the best of times, it was the worst of times…”

This week, four stories caught my attention.

In California, the franchise operator running 59 Southern California Carl’s Jr. restaurants filed for bankruptcy protection, squeezed by rising labor costs, inflation, crime, and shrinking margins.

Here in Maine, towns are considering restrictions and moratoriums on data centers just as electricity demand tied to AI and cloud computing is beginning to surge. In Gorham, residents are fighting a proposed Amazon distribution facility over concerns about traffic, lighting, and community impact.

And on Wall Street, NextEra Energy announced a $67 billion acquisition of Dominion Energy — a massive bet on future electricity demand growth.

At first glance, these stories seem unrelated. Burgers, warehouses, data centers, and utility mergers do not appear to have much in common. But underneath all of them is the same question: which regions are preparing to support growth, and which are preparing to constrain it?

The economy is beginning to divide between places willing to build the physical systems modern life requires and places increasingly uncomfortable with the infrastructure growth demands.

Modern economies are incredibly energy intensive, and they are becoming more so by the day. AI, cloud computing, advanced manufacturing, electrification, and data infrastructure all require enormous amounts of electricity. Not theoretical electricity. Not nameplate capacity. Real electricity delivered every hour of every day.

That reality is beginning to collide with communities and states increasingly hostile to the infrastructure required to support growth.

Data centers, transmission lines, substations, pipelines, warehouses, and industrial facilities are facing growing resistance in many of the same places pushing hardest for electrification and economic expansion.

The resistance is becoming almost universal. Pipelines. Transmission corridors. Data centers. Warehouses. Natural gas generation. Industrial facilities. Housing developments. In many places, we have moved well beyond “Not In My Backyard.”

It increasingly feels like:

Not On Planet Earth.

And nowhere does that seem more pronounced than in parts of New England, where economic growth, electrification, AI expansion, and infrastructure opposition are all colliding at the same time.

Eventually, the physics catches up.

The NextEra Energy acquisition of Dominion Energy is a signal the market sees all of this coming. You do not spend $67 billion because you think electricity demand is flattening out. You spend it because you believe AI, cloud computing, industrial growth, and electrification are going to drive enormous increases in load for a long time.

And the market is signaling something else. The winners are likely going to be the companies and regions capable of delivering large amounts of reliable power consistently and affordably. Real power. Real infrastructure. Real physical systems.

The economy still runs on physics whether policymakers acknowledge it or not. AI servers do not care about policy goals. Factories cannot idle every time weather conditions change. Hospitals and cities still need electricity during the coldest nights, the hottest days, and the worst storms.

For years, much of the public discussion around energy has centered on aspiration. Targets. Mandates. Timelines. Press releases. But the market increasingly seems focused on a much more basic question: who can actually power growth?

Dispatchable generation delivers power “just in time” — exactly when the system needs it. Wind and solar largely produce power “just in case” — when weather conditions happen to cooperate.

Nobody cares how the system performs on a sunny spring afternoon.

The real test is multi-day winter storms, heat waves, prolonged cold, and extended periods of low wind output. That is when you find out whether a grid is resilient or fragile.

The immediate response is usually, “but batteries.” Batteries can absolutely help with short-duration balancing and shifting load by a few hours. But modern economies are not stressed by two-hour problems. Grids are stressed by multi-day events and seasonal demand swings.

Physics still matters.

And increasingly, many proposed “solutions” are really forms of demand management rather than energy abundance. Shifting industrial loads, curtailing usage during peak periods, delaying consumption, and managing scarcity may help stabilize constrained systems, but they are not the same thing as creating the abundant, reliable power required for sustained economic growth.

Growing economies historically expanded supply to meet demand. Constrained economies increasingly attempt to manage demand around limited supply.

That may be the biggest shift happening underneath this entire debate.

For decades, America largely operated from an assumption of abundance. We built power plants, pipelines, transmission systems, highways, ports, factories, industrial parks, and housing because growth itself was viewed as positive. Infrastructure was not always popular, but it was generally understood to be necessary.

That mindset appears to be changing in parts of the country.

Increasingly, large physical projects of almost every kind face organized opposition. Pipelines. Transmission corridors. Natural gas generation. Nuclear. Warehouses. Data centers. Industrial development. Even housing in many places. The modern economy depends on physical systems, yet we are becoming increasingly uncomfortable building them.

At the same time, expectations for the economy continue to rise. We want AI growth, electrification, remote work capability, instant delivery, advanced healthcare, cloud computing, lower emissions, domestic manufacturing, and affordable living costs simultaneously.

But all of that requires enormous physical systems underneath it. More electricity. More transmission. More generation. More industrial infrastructure. More supply chains. More construction. More land.

The market appears to understand this clearly. The regions and companies attracting investment are largely the ones still willing to build.

Maybe that is what these stories are really showing us.

In some parts of the country, this may become the best of times. AI growth, industrial expansion, infrastructure investment, rising energy demand, and economic development are creating enormous opportunity for regions capable of supporting it.

In other places, it risks becoming the worst of times because investment and industry will flow toward regions capable of supporting growth and away from regions increasingly committed to constraining it.

Power has to be available when demand arrives. Infrastructure has to get built. Industrial systems have to exist somewhere.

Capital goes where it can grow.

That may become the defining divide of the next decade. Not red states versus blue states. Not even fossil fuels versus renewables. The real divide may be between regions willing to build physical systems and regions increasingly committed to restricting them.

The market seems to be voting already. Capital is flowing toward infrastructure, dispatchable power, industrial growth, and scale.

Toward abundance.

Because in the end, aspiration alone does not power economies.

Power does.

What was New England’s worst trade ever? Red Sox fans might say selling Babe Ruth to the Yankees for $100,000. Younger fans may point to trading Mookie Betts for Alex Verdugo, Jeter Downs, and Connor Wong. The details almost do not matter anymore because the underlying lesson is the same: New England gave away something enormously valuable and received far less in return.

We can now add another terrible trade to the list.

Over the last fifteen years, New England systematically blocked major natural gas pipeline projects that would have connected the region more directly to some of the largest and lowest-cost energy reserves in the world. In exchange, the Northeast increased dependence on imported LNG, oil-fired generation, intermittent renewable energy, and some of the highest electricity prices in the United States.

A few hundred miles from New England sits the largest natural gas field in America. Yet New England still burns oil for electricity, imports LNG from overseas, and pays some of the highest energy prices in the country during the coldest periods of the year. The region sits on the doorstep of abundance and still struggles with energy scarcity.

The region knew this problem was coming.

Over the last fifteen years, multiple pipeline projects were proposed specifically to address New England’s growing fuel constraints during winter peak demand. Projects like the Constitution Pipeline, Northeast Energy Direct, and Access Northeast would have expanded the region’s ability to move abundant low-cost Appalachian natural gas into New England when it was needed most. Constitution alone was designed for up to 650,000 dekatherms per day, and Northeast Energy Direct was designed around roughly 1.3 Bcf/day of capacity.

Instead, those projects were systematically blocked through state permitting decisions, legal challenges, regulatory opposition, and political pressure. Political leaders increasingly treated new fossil fuel infrastructure itself as incompatible with the region’s climate agenda. At the same time, those same states aggressively pushed electrification policies, increased dependence on intermittent renewable generation, and retired dispatchable power sources without replacing the underlying fuel infrastructure required to support the system during winter reliability events.

The consequences were entirely predictable. Electricity prices rose. LNG imports increased. Oil-fired generation remained critical during cold weather. Industrial competitiveness weakened, and Maine’s manufacturing base continued its long decline under some of the highest delivered energy costs in the country.

Now, after years of insisting the problem did not exist, the region is quietly reconsidering the very infrastructure it once fought so aggressively to stop.

What These Pipelines Were Designed To Solve

At its core, New England’s problem is not a lack of energy resources. It is the inability to move enough fuel into the region when demand is highest.

During much of the year, the region’s existing pipeline system can adequately supply homes, businesses, and power plants. But winter changes everything. Heating demand rises sharply across the Northeast at the same time electricity demand increases and renewable output can become less reliable during cold, dark, low-wind conditions.

That is when pipeline constraints begin driving electricity prices, fuel availability, and ultimately the reliability of the entire system.

Natural gas used for home heating receives priority on much of the interstate pipeline network during extreme cold. As available pipeline capacity tightens, power generators are forced to compete for remaining supply. Natural gas prices spike. Electricity prices follow. When gas becomes unavailable or prohibitively expensive, the system falls back on LNG imports and oil-fired generation to maintain reliability.

The Constitution Pipeline, Northeast Energy Direct, and Access Northeast projects were all designed to relieve different parts of this bottleneck. Together, they would have added nearly 3 billion cubic feet per day of additional fuel deliverability into constrained Northeast markets. That additional capacity would not have eliminated winter reliability risks entirely, but it would have materially reduced fuel scarcity, price volatility, LNG dependence, and oil burn during peak winter periods.

In other words, the pipelines were not designed to create dependence on natural gas. They were designed to reduce dependence on scarcity.

The Three Pipelines New England Rejected

The Northeast did not reject a single pipeline project. It rejected multiple major infrastructure expansions over more than a decade.

The Constitution Pipeline would have transported roughly 650 million cubic feet of natural gas per day from Pennsylvania into New York, improving downstream supply conditions throughout the Northeast and New England. The project received federal approval from FERC but was ultimately stopped after New York denied a key water quality permit.

Northeast Energy Direct, proposed by Kinder Morgan, would have added roughly 1.3 Bcf/day of pipeline capacity into New England demand centers. The project faced mounting political opposition across Massachusetts and New Hampshire before ultimately collapsing in 2016.

Access Northeast was designed primarily as an expansion of existing infrastructure serving New England. Backed by major utilities and pipeline operators, the project aimed specifically at improving winter fuel reliability and reducing price volatility. Political opposition and regulatory uncertainty eventually halted the effort.

Taken together, these projects represented nearly 3 billion cubic feet per day of additional fuel deliverability into one of the most constrained energy markets in the United States. New England did not merely fail to expand infrastructure. It systematically blocked nearly every major proposal intended to address the region’s growing winter fuel constraints.

Scarcity Was a Policy Choice

The failure of these projects was not primarily technical or economic. The pipelines were proposed because the need was obvious. New England’s dependence on natural gas for electricity generation had been growing for years, while pipeline capacity into the region remained largely stagnant. Grid operators, utilities, and energy companies all understood what was coming: increasing winter reliability concerns, price volatility, and fuel constraints during peak demand periods.

The response from political leadership across much of the Northeast was not driven primarily by engineering, grid operations, or fuel-system realities. It was driven by ideology. Warnings from utilities, grid operators, pipeline companies, and energy experts about growing winter reliability risks were increasingly subordinated to climate targets, electrification mandates, and opposition to fossil fuel infrastructure itself.

Across the region, energy policy became dominated less by people experienced in operating complex energy systems and more by political and regulatory institutions staffed primarily around climate policy, environmental advocacy, and decarbonization goals. The physical realities of fuel deliverability, winter reliability, dispatchable generation, and industrial competitiveness were often treated as secondary concerns or dismissed altogether.

The result was an energy strategy built more around political aspiration than operational reality.

The Constitution Pipeline was effectively killed when New York denied a key Section 401 water quality permit through the New York State Department of Environmental Conservation. Northeast Energy Direct collapsed under a combination of political opposition, regulatory pressure, and deteriorating project economics created by that opposition. Access Northeast, designed largely as an expansion of existing infrastructure to improve winter reliability, met a similar fate.

This was not a coincidence. Opposition to pipeline infrastructure became a central feature of the Northeast’s climate and energy agenda. Politicians openly celebrated blocking these projects as evidence of climate leadership. Around the same time, states accelerated electrification mandates, expanded renewable portfolio requirements, subsidized intermittent generation, and increasingly framed conventional fuel infrastructure itself as the problem.

On the coldest days of the year, when electricity demand rises and renewable output is often reduced by weather conditions, the region still depends heavily on dispatchable thermal generation backed by deliverable fuel. When pipeline gas becomes constrained, the system falls back on imported LNG and oil-fired generation.

New England did not eliminate dependence on fossil fuels. It replaced nearby pipeline gas with imported LNG, oil-fired generation, and some of the highest energy costs in the country.

Maine cannot simply claim to be an innocent bystander in this story. While the biggest pipeline battles were fought in New York and Massachusetts, Maine’s political leadership embraced the same climate-first framework that made fuel infrastructure politically toxic across the Northeast. In 2019, Governor Janet Mills went to the United Nations Climate Action Summit and pledged that Maine would become carbon neutral by 2045. Her administration simultaneously pushed aggressive electrification policies, renewable mandates, and large-scale heat pump adoption while the underlying regional fuel system remained constrained.

Instead of reducing dependence on fossil fuels, New England’s policies often shifted the region toward more expensive and less reliable fossil fuels. Electrification increased winter demand for electricity at the exact same time pipeline constraints limited access to affordable natural gas, forcing the grid to rely more heavily on imported LNG and oil-fired generation during periods of peak stress.

LNG added cost. Oil added cost — and carbon.

Political leaders continued promising rapid decarbonization while the underlying energy system moved in the opposite direction.

The Economic Consequences Were Predictable

New England’s energy policies did not simply affect utility bills. They steadily degraded the region’s broader economic competitiveness.

Energy is not a niche input in a modern economy. It underpins nearly every critical system in the region. Hospitals depend on enormous quantities of electricity, but they also rely heavily on thermal energy for heating, sterilization, laundry, food service, and hot water systems. Federal emergency preparedness standards require healthcare facilities to maintain robust backup power capability and fuel continuity planning because reliability matters more than political slogans during emergencies and winter storms. In practice, many hospitals in Maine and across New England maintain dual-fuel capability and on-site fuel storage precisely because the region’s winter energy system remains vulnerable to fuel constraints during peak demand periods. Manufacturers rely on both electric power and process heat. Schools, municipalities, grocery stores, data centers, warehouses, restaurants, and small businesses all depend on affordable and reliable energy to remain financially viable.

When policymakers deliberately constrain access to low-cost fuel, those costs spread through the entire economy.

That reality hit energy-intensive industries first and hardest. Maine’s paper industry provides perhaps the clearest example. Over the last two decades, roughly fifteen paper mills across the state either closed or significantly curtailed operations. Global competition, changing paper demand, labor costs, and environmental regulations all contributed to those losses, but energy was never a side issue. By constraining access to abundant Appalachian natural gas, New England locked itself into some of the highest and most volatile energy costs in the country. For industries like papermaking, where electricity and thermal fuel are foundational operating costs, those differences compound year after year through lower margins, weaker reinvestment, reduced competitiveness, and eventually closures.

The consequences extended far beyond heavy industry. High electricity prices ripple through healthcare systems, municipal budgets, school systems, and small businesses. A hospital paying millions more annually for electricity eventually passes those costs into healthcare pricing. Municipalities facing rising energy costs pass them into property taxes. Restaurants, retailers, manufacturers, and small businesses absorb higher operating expenses that ultimately show up in consumer prices.

Energy costs do not remain confined to utility bills. They spread through the entire economy.

The bitter irony is that many of these outcomes were foreseeable. ISO-New England repeatedly warned about fuel security concerns and winter reliability risks. Pipeline developers proposed multiple projects designed specifically to increase deliverable fuel into the region. Utilities and energy market participants understood exactly what constrained pipeline capacity would do to winter gas and electricity pricing.

The region knew the economic direction of these policies long before many of the consequences fully arrived.

What Did This Cost New England?

It is impossible to calculate precisely how much New England paid for choosing energy scarcity over infrastructure. No one can rerun the last decade with the Constitution Pipeline, Northeast Energy Direct, and Access Northeast all in service.

But the scale is enormous.

Natural gas frequently sets the marginal price of electricity in ISO-New England. When pipeline constraints tighten during winter, natural gas prices spike sharply and electricity prices follow almost immediately behind. ISO-New England has warned about this relationship for years through repeated discussions around fuel security, winter reliability, and constrained gas deliverability.

Because New England consumes roughly 120 to 130 million megawatt-hours of electricity annually, even relatively small reductions in winter natural gas pricing can produce enormous regional savings.

The combined capacity of Constitution, Northeast Energy Direct, and Access Northeast would have represented nearly 3 billion cubic feet per day of additional fuel deliverability into constrained Northeast markets. That is an enormous amount of supply in a region where winter gas scarcity routinely drives both natural gas and electricity price spikes.

Instead of accessing abundant nearby Appalachian gas, New England increasingly relied on imported LNG tied to volatile global pricing. In 2022 alone, LNG facilities serving the region supplied roughly 34 billion cubic feet of gas into New England markets. During winter scarcity events, New England natural gas prices often traded many multiples above benchmark U.S. gas prices.

The scale of the excess costs becomes staggering very quickly.

If New England imported roughly 34 billion cubic feet of LNG-related supply at winter pricing premiums averaging even $10 per MMBtu above nearby Appalachian gas, the region effectively overspent by roughly $340 million in a single year on fuel alone. At a $15 differential, the number approaches half a billion dollars annually. Over a decade, the excess cost of relying on imported LNG instead of abundant nearby pipeline gas compounds into many billions of dollars before even considering the downstream effects on electricity pricing.

And electricity is where the costs explode.

New England consumes roughly 120 to 130 million megawatt-hours of electricity annually. Because natural gas often sets the marginal price of power across the region, even modest reductions in winter gas pricing produce enormous savings in wholesale electricity markets. A sustained reduction of just $5 per megawatt-hour would lower regional electricity costs by roughly $600 million annually. A $10 reduction approaches $1.2 billion per year. During severe winter pricing events, the impacts become dramatically larger.

The direct impact on individual households is harder to calculate precisely because energy costs ripple through multiple systems simultaneously — electricity prices, heating fuel prices, municipal taxes, healthcare costs, food distribution, manufacturing, and small business operating costs.

But the broad direction is unmistakable.

New England families paid more for electricity because constrained pipeline capacity increased winter natural gas and wholesale power prices. Families heating with oil or propane faced additional exposure because regional energy scarcity increased competition across winter fuel markets. At the same time, rising energy costs filtered into healthcare systems, property taxes, consumer goods, and local business pricing throughout the regional economy.

Energy costs do not remain confined to utility bills. They spread through the entire economy.

Every hospital bill, property tax bill, grocery bill, manufacturing payroll, and restaurant menu in New England sits downstream of energy costs.

Those costs did not fall equally across the economy. Large industrial facilities absorbed millions of dollars in additional annual energy expense. Hospitals and universities paid more to operate critical facilities. Municipalities passed higher utility costs into local property taxes. Small businesses and households absorbed rising electricity and heating bills that steadily eroded affordability throughout the region.

Over a decade, the cumulative effect of higher electricity prices alone reaches into the tens of billions of dollars. Once higher heating costs, lost industrial competitiveness, municipal energy burdens, healthcare expenses, and broader economic impacts are included, the total economic cost of New England’s energy policies reaches well into the hundreds of billions of dollars.

The irony is that the Northeast accepted these costs voluntarily while sitting only a few hundred miles from some of the most abundant and affordable natural gas resources in the world.

At the same time New England constrained major fuel infrastructure projects, the region spent tens of billions of dollars subsidizing renewable generation, electrification programs, offshore wind procurement, transmission expansion, grid restructuring, and decarbonization initiatives intended to transform the energy system. Yet despite those enormous expenditures, the region still entered nearly every winter dependent on constrained natural gas pipelines, imported LNG, and oil-fired generation to maintain reliability during periods of peak demand. The deeper irony is that the pipelines designed to address New England’s underlying fuel deliverability problem would have cost only a fraction of what the region ultimately spent attempting to work around that problem instead. After years of massive investment, New England still requires the very fuel infrastructure it chose not to build in the first place.

Reality Is Forcing a Reconsideration

The irony is difficult to miss.

A decade after projects like the Constitution Pipeline were blocked in the name of climate policy, the underlying problems they were designed to solve have only become more obvious. New England still faces winter fuel constraints. Electricity prices remain among the highest in the country. Oil-fired generation still appears during periods of system stress. LNG imports remain critical during cold weather. At the same time, the region continues pushing electrification policies that increase dependence on an already constrained winter energy system.

The underlying physics of the system never changed.

Now the politics may be changing.

Williams is again pursuing the Constitution Pipeline. Recent reporting says Williams is targeting reinstatement of federal approvals by 2026, with potential in-service by late 2027, while federal regulators have reopened environmental review. Reuters has also reported that Williams is working with federal and state regulators to revive Constitution and NESE after years of state-permitting fights, and that Williams described these projects as essential to addressing persistent Northeast gas supply constraints that have raised costs and increased reliance on higher-emission fuels.

That shift did not happen because politicians suddenly rediscovered engineering or energy economics. It happened because reality became harder to ignore.

The Ukraine war exposed the fragility of global LNG markets and the geopolitical risks associated with energy scarcity. More recently, rising tensions involving Iran and the Strait of Hormuz reinforced how vulnerable globally traded fuel markets can become during periods of geopolitical instability. New England increasingly tied portions of its winter energy security to those same global supply chains despite sitting only a few hundred miles from some of the largest natural gas reserves in the world.

At the same time, ISO-New England continued issuing warnings about fuel security and winter reliability. Electricity demand forecasts climbed as electrification accelerated and data center growth increased projected system loads. Meanwhile, consumers and businesses across the region continued absorbing some of the highest energy costs in the United States.

Eventually, energy costs became too large and too visible for the public to ignore. Electricity bills rose. Heating costs climbed. Businesses absorbed higher operating expenses while households across the region devoted larger portions of their budgets simply to keeping the lights on and their homes warm.

Even more remarkable, some of the same political leaders and utilities that once opposed expanded fuel infrastructure are now quietly acknowledging the region’s growing reliability and affordability problems. The conversation has shifted from whether fuel constraints exist to how long the Northeast can continue operating under them.

That does not mean Constitution will ultimately be built. Governors like Kathy Hochul and Maura Healey still possess significant political and regulatory tools capable of slowing or obstructing the project. New York’s Section 401 permitting authority remains a major obstacle, and political opposition to new fossil fuel infrastructure remains deeply embedded across much of the Northeast.

Maine’s next governor will play a meaningful role in shaping the outcome of the Constitution Pipeline debate. While Maine does not control New York permitting decisions, governors influence regional energy priorities through public advocacy, ISO-New England policy discussions, interstate coordination, and direct engagement with federal agencies such as FERC and the U.S. Department of Energy. A governor focused on affordability, reliability, and industrial competitiveness rather than symbolic climate positioning will help push the Northeast toward a more realistic conversation about fuel security and energy costs.

More fundamentally, the Constitution Pipeline fight increasingly raises broader questions about interstate commerce, federal authority, and whether individual states should be able to block major energy infrastructure projects carrying significant regional economic and reliability implications. Those tensions are likely to intensify if winter reliability concerns and energy costs continue rising across the Northeast.

But the environment surrounding the project is undeniably different today than it was ten years ago.

The region has now lived with the consequences of constrained infrastructure long enough to see where the policies actually led: higher prices, greater dependence on LNG and oil, weakened industrial competitiveness, and a grid increasingly stretched between political ambition and physical reality.

Physics waited patiently while politics ran the meeting.

New England Still Has a Choice

The most remarkable part of this story is that New England’s energy problems were never primarily caused by a lack of resources, technology, or wealth. The region sits near some of the most abundant natural gas reserves in the world. It possesses a highly educated workforce, sophisticated financial markets, world-class universities, and enormous engineering capability.

What it lacked was the political willingness to align energy policy with physical reality.

For more than a decade, the Northeast pursued an energy strategy built around restricting the infrastructure required to deliver affordable and reliable fuel into the region. Policymakers treated pipelines themselves as the problem while assuming the underlying realities of winter reliability, industrial competitiveness, and fuel deliverability could somehow be engineered away through mandates, subsidies, and political ambition.

They could not.

The result was a system that became more expensive, more globally exposed, and increasingly dependent on LNG and oil during periods of peak winter stress. LNG added cost. Oil added cost — and carbon. Meanwhile, households, businesses, hospitals, manufacturers, municipalities, and industrial employers absorbed the cumulative economic consequences of those decisions year after year.

The deeper lesson extends beyond pipelines alone.

Modern economies do not function without large-scale, reliable, and affordable energy infrastructure. Every serious industrial economy in the world ultimately bends back toward this reality no matter how ambitious the political rhetoric becomes. The laws of physics, fuel logistics, grid stability, and industrial economics do not disappear because policymakers wish them away.

That is why the possible revival of the Constitution Pipeline matters far beyond a single project. It represents a broader test of whether New England is finally willing to reconnect its energy policies with engineering, economics, and operational reality.

Because the central contradiction never disappeared. New England sits only a few hundred miles from some of the largest natural gas reserves in the world, yet continues to struggle with high energy prices, winter fuel constraints, LNG imports, and oil-fired generation during periods of peak demand. None of those outcomes were inevitable. They were the result of political decisions that constrained the infrastructure required to deliver abundant, affordable energy into the region.

For years, political leaders promised that mandates, subsidies, and electrification targets could overcome the physical realities of fuel deliverability and grid reliability. But modern energy systems do not operate on aspiration. LNG added cost. Oil added cost — and carbon. Electricity prices rose. Industrial competitiveness weakened. Households, businesses, hospitals, municipalities, and manufacturers absorbed the consequences year after year while the region’s politicians and climate special interest groups celebrated the policies that helped produce them.

The lesson here extends beyond pipelines alone. When governments subordinate engineering and economics to ideology for long enough, reality eventually reasserts itself — usually through higher prices, weaker competitiveness, and declining resilience.

New England was never energy-poor. It chose energy scarcity.

The region could still choose differently.

The Story We’re Being Told

Maine is being told it is in the middle of a “clean energy boom.” The latest report from the Maine Department of Energy Resources points to more than 16,000 jobs and nearly $3 billion in economic activity.

Those numbers are deeply misleading.

They are built on a definition of “clean energy” that includes everything from HVAC work to efficiency programs to administrative roles tied to compliance and incentives. Much of it is driven by government policy, subsidies, and ratepayer-funded programs—not by a competitive energy system that delivers lower-cost, reliable power and can stand on its own in the market.

So yes, there is activity. But calling it a “boom” suggests the system is working.

It isn’t.

What the System Actually Does

At the same time, the grid still depends on oil when it matters most.

Not occasionally, and not as a last resort. This isn’t an isolated event—it’s how the system is built. During extreme winter conditions—cold, dark, and still—natural gas delivery is maxed out because pipeline capacity was never expanded to meet peak demand. Renewable output falls, and the system turns to whatever can run.

That means oil.

Major pipeline expansions into New England were proposed and then stopped after sustained opposition from environmental advocacy groups and regulatory actions that made new pipeline construction effectively impossible.

Those efforts were driven by a focus on reducing fossil fuel infrastructure. But the result was not the elimination of fossil fuels—it was a system that still depends on them, just under worse conditions. Heating needs take priority, power plants get squeezed, and the system turns to oil.

Oil isn’t a backup. It’s part of the design.

We Didn’t Replace the System—We Duplicated It

We didn’t replace the system. We built a second one on top of it.

Wind, solar, batteries, and efficiency programs were added to the grid, but oil and imported LNG were never removed because they couldn’t be. During peak demand—especially in winter—those fuels are still what keep the system running.

That’s not a transition. It’s duplication, and duplication is expensive. Every dollar spent building weather-dependent generation has to be matched by dollars spent maintaining something that can run on demand, because reliability is not optional.

In Maine, that matters. Solar panels in this region typically produce on the order of 15% of their rated capacity over the course of a year, and wind often averages around 25–30%. Those are annual averages—and they drop much lower at the exact moments demand is highest.

In the winter, when the system is under the most stress, days are short, skies are often overcast, and wind conditions can be still. At those moments, output can fall to very low levels—or disappear entirely.

That’s why something else has to be there.

You don’t build a power system around averages. You build it around the hours when everything is strained.

The Subsidy Layer

None of this happened by accident. What is being described as a “clean energy boom” is the direct result of policy, not the emergence of a competitive energy system. It is driven by federal subsidies, state mandates, and ratepayer-funded programs that shape what gets built and where capital flows.

At the federal level, the Inflation Reduction Act created one of the largest waves of energy subsidies in history, with tax credits like the Production Tax Credit and Investment Tax Credit directly improving the economics of wind, solar, and storage projects. At the state level, Maine layers on its own incentives and requirements—efficiency programs funded through electric rates, Net Energy Billing, and procurement mandates that guarantee revenue streams for certain types of generation.

When you subsidize an activity at this scale, you will get more of it. That’s not a market signal—it’s a policy outcome.

You don’t tear down the old bridge until the new one can carry the full load. Anyone driving around Cumberland or Falmouth can see how this works. The Maine Department of Transportation keeps existing infrastructure in service until the replacement is ready. You don’t remove critical infrastructure first and hope the system adjusts.

That’s exactly what we’ve done here.

What Actually Happens in Winter

Winter is where the system is tested.

During extreme cold—when days are short, demand is high, and conditions are often still—the grid shifts quickly. Natural gas delivery is maxed out, not because the fuel doesn’t exist, but because the region never added the pipeline capacity needed for winter peaks. Renewable output falls, and the system turns to whatever can run at scale.

That means oil.

Across New England, oil-fired and dual-fuel plants ramp up sharply during peak demand. At critical hours, oil can supply a significant share of total generation—not as a primary resource, but as the fuel that keeps the system operating when everything else is tight.

Those plants store fuel on site and can run when needed, independent of pipelines or weather conditions. They are not the most efficient or the lowest-cost option, but they are available when the system has no margin for error.

That is what reliability looks like in practice.

Emissions Don’t Respect State Lines

Maine does not operate its own power system in isolation. It is part of a regional grid managed by ISO New England, where electricity is dispatched across state lines based on what is available and what can run.

When pipeline capacity is insufficient, the region turns to imported liquefied natural gas. It’s the same pattern in a different form.

In typical conditions, natural gas priced at the Henry Hub trades in the range of $3 to $5 per MMBtu, while LNG delivered into New England during constrained winter periods can range from $10 to $25 or more.

At the height of the Russian invasion of Ukraine, LNG surged to $50 to $70 per MMBtu.

New England burns roughly 200–300 million MMBtu of gas in a winter. At those price spreads, that implies exposure of roughly $8 to $15+ billion in a single season.

Those costs flow directly into electric bills.

By relying on LNG, the region has built direct exposure to global energy markets into its power system.

The effort to restrict or effectively shut down Wyman Station is a good example of how far this has drifted from the reality of how the system actually works.

Wyman isn’t a plant that runs every day, and it isn’t intended to. It exists for the conditions this system struggles with most—periods of extreme winter demand when natural gas delivery is constrained, renewable output is low, and the margin for error disappears. In those moments, plants like Wyman are not optional. They are part of what keeps the system operating.

Requiring a facility like that to install expensive emissions controls—despite the fact that it may only run a limited number of hours each year—doesn’t eliminate the need for the plant. It just makes it more costly to keep available, or pushes it toward retirement without anything capable of replacing it under the same conditions.

We’ve seen this pattern before. Pipeline capacity was constrained without being replaced, and the system didn’t stop using fuel—it shifted to oil and imported LNG when demand peaked. The same logic is now being applied to dispatchable generation. Limit what can run when it matters most, without putting something equally dependable in its place, and the system will adjust in ways that are more expensive and often less efficient.

From a distance, that can look like progress. In practice, it’s a system that is being tightened at the margins while still depending on the very resources it is trying to phase out.

The Scorecard We Should Be Using

Step back and look at what has happened.

We have spent billions of dollars across federal programs, state policies, and ratepayer-funded initiatives to reshape the energy system. Maine has passed laws like Maine Won’t Wait, reduced natural gas capacity before building a replacement, and pushed widespread electrification without a plan to add firm generation to meet peak demand. At the same time, regional policies like the New England Heat Pump Compact are adding roughly 4 gigawatts of new winter peak demand—with zero gigawatts of firm supply to back it up.

And yet, when the system is tested, it still depends on oil, imported LNG, and a policy-constrained natural gas network.

If the goal is lower emissions, the system tells a different story. When generation shifts across state lines, when oil is burned under peak conditions, and when LNG replaces lower-cost pipeline gas, total emissions don’t disappear. LNG also carries additional emissions from liquefaction, transport, and delivery by ship, making it a more energy-intensive way to supply the same fuel.

If the system still relies on oil under stress, if it replaces $4 gas with $40 gas shipped in from overseas, and if costs continue to rise, then we haven’t built a better system.

We’ve built a more expensive one that still depends on everything it was supposed to replace.

Over the past month, Microsoft, Google, and Meta have committed to gigawatts of new power to support artificial intelligence infrastructure. These are not incremental projects. They are industrial-scale developments built around one requirement: reliable, continuous energy delivered on a predictable timeline.

Cost is the first filter for any project like this, and Maine fails it before anything else is considered.

Industrial Electricity Cost Comparison (2023)

Maine
████████████████████████████ 12.5¢/kWh

Lowest-Cost States (Average)
████████████ 6.1¢/kWh

Source: U.S. Energy Information Administration (2023 industrial electricity prices). Maine ~100–120% higher.

Based on 2023 industrial electricity rates, power costs in Maine are roughly 100% to 120% higher than the average of the ten lowest-cost states. That gap is not marginal. It is the difference between being competitive and being eliminated in the first round. At those prices, Maine isn’t just at a disadvantage. It’s not in the conversation.

At the same time, Maine has been working through legislation aimed at large energy users like data centers. The Maine Legislature passed a bill to address how those projects would interact with the electric system, and Janet Mills vetoed it. The bill now returns for a possible override, though that outcome is uncertain. For anyone looking to invest billions of dollars in a project that depends on power availability, that sequence does not answer the most basic question: can this be built here, on time, with confidence?

The market has already moved

9

The largest buyers of electricity in the world are not waiting for that kind of clarity. Microsoft is pursuing a model built around dedicated onsite generation. Google is combining grid access with its own supply. Meta is working with utilities to develop multiple large-scale gas plants tied directly to its demand. These are different structures, but they all reflect the same conclusion: power has to be secured before construction begins, not assumed to appear later.

Maine’s problem is not one decision

This is not about a single bill or a single veto. It is about how several policy directions intersect. Maine has encouraged electrification, which increases demand on the grid, while also limiting expansion of firm fuel supply. It relies on a system that is already tight during winter peaks and has not established a clear, repeatable approach for integrating very large new loads.

What stands out is not a lack of awareness. It is a clear set of priorities. Over the past several years, policy has focused heavily on emissions reduction and electrification while doing little to support large-scale economic development. In some cases, it has moved in the opposite direction. Programs that once attracted investment—like the Pine Tree Development Zones and the Business Equipment Tax Reimbursement—have been scaled back or reworked, reducing their effectiveness.

At the same time, there has been no corresponding effort to ensure the state can support large, continuous industrial loads. Electrification increases dependence on the grid, while large industrial projects require firm, predictable power. If policy pushes demand higher while limiting the ability to supply it—and removes tools that attract investment—the outcome is straightforward. We haven’t just neglected development. We’ve made Maine a place serious projects avoid.

The numbers reflect it

This is not just a policy debate. It shows up in the economic data. According to the U.S. Bureau of Economic Analysis, Maine’s real GDP growth was about 0.6% in the most recent full year, compared to roughly 2.5% nationally. That gap is not a rounding error. It reflects the kinds of projects that are—and are not—being built.

If Maine were attracting large-scale, energy-intensive investment tied to the next phase of industrial growth, it would show up in those numbers. It doesn’t.

It’s not just data centers

Consider the proposed salmon farm in Belfast, Maine by Nordic Aquafarms. This was a roughly $500 million project that would have brought industrial-scale aquaculture and year-round jobs to the Maine coast. The company spent years in permitting, secured approvals, and began development. After extended legal challenges—particularly around water access—the project ultimately stalled and was abandoned.

You can support or oppose that project on its merits. That’s not the point. From an investor’s perspective, the timeline stretched into years and the outcome remained uncertain even after approvals were in hand. That experience does not stay isolated to one project. It becomes part of how the entire state is viewed.

The physical system sets the boundary

Even if policy were fully aligned, the underlying system would still impose limits. Tools like the Engineered Vision Energy Infrastructure Map make the contrast clear. In Texas and along the Gulf Coast, dense pipeline networks and abundant fuel supply support expansion. In New England, pipeline capacity is constrained, winter demand strains the system, and scaling up quickly is difficult.

This is not ideological. It is a description of the infrastructure that exists today.

While others expand, New England manages constraints

In much of the country, the discussion is about how to move increasing volumes of energy to market and where additional infrastructure should be built. In New England, the discussion is more often about how to operate within existing limits. That difference shapes what kinds of projects are feasible and how quickly they can move.

Artificial intelligence infrastructure amplifies that divide. These facilities require continuous, high-volume power and operate on development timelines that do not allow for extended uncertainty. If those requirements cannot be met in one location, they will be met in another.

The bottom line

The question is whether Maine supports economic development in general terms.

The answer, based on outcomes, is increasingly no.

Recent experience makes that clear. Dragon Cement has shut down operations in Thomaston. Pride Manufacturing has closed. Sawmills in places like Milo, Maine have struggled or disappeared. These are energy-intensive industries that once formed the backbone of Maine’s economy and are now contracting without replacement.

Existing industrial operations face the same environment. Sappi North America has been drawn into recurring disputes over the dam that supports its operations, and Bath Iron Works operates under constant political and regulatory pressure. Whether each individual case is justified is not the point. From the outside, it looks like a place where large industrial employers are regularly contested.

New investment follows the same pattern in reverse. Projects that require large amounts of reliable, affordable energy are not choosing Maine. High power costs, constrained infrastructure, and a policy environment that prioritizes other objectives make that outcome predictable. Developers compare options and build where the fundamentals already work.

This is not a transition. It is contraction without replacement. The industries that sustained the state are shrinking, and the industries that define the next phase of economic growth are being built elsewhere.

The AI economy is being built now, at industrial scale. Maine isn’t being overlooked. It’s being ruled out.

The Utility Bargain Is Breaking Down

For most of the last century, electricity was simple. You flipped a switch, and the power was there. It just worked, every time.

They built the power, secured the fuel, and made sure it held up when demand surged. When it got very cold and everyone turned the heat up, the system held. When it got very hot and demand spiked, the system held. That was the job.

For the customer, that promise meant something real. It meant you didn’t have to think about when to run your business. You didn’t have to watch the weather or worry about whether the grid would hold up. Electricity was there when you needed it, and the cost was stable enough to plan around.

That mattered more than people realize. It meant a manufacturer in Maine could compete with one in Texas or Tennessee without electricity being the deciding factor. Power wasn’t the advantage, but it wasn’t the handicap either.

That was the bargain. Plan ahead. Build enough. Deliver when called.

That bargain is changing.

A Different Set of Assumptions

That system worked because it was built around control and predictability. Utilities could decide when to generate electricity, how much to produce, and how to meet demand when it showed up.

That is no longer the case.

Today, more of the system depends on resources that generate when conditions allow, not necessarily when demand is highest. Output varies with the weather, and it cannot be scheduled in the same way as traditional generation.

At the same time, we’ve stopped planning this system years in advance and started pushing those decisions closer to real time. That means instead of planning years ahead, businesses are now reacting to conditions that can change in real time. For some, that’s manageable. For others, it’s a reason to rethink whether they operate here at all.

The result is a system that is less about ensuring supply ahead of time and more about managing conditions as they happen. Reliability is no longer something fully built into the system. It is increasingly something that has to be managed in real time.

Under the old model, utilities made money by building and maintaining infrastructure that worked. They were allowed to earn a return on investment, but in exchange they had an obligation to deliver reliable service. It wasn’t exciting, but it was effective. As Meredith Angwin has pointed out, the control rooms were boring. That was the goal. Nothing unexpected, nothing breaking, nothing that required customers to think about the system at all.

What we are moving toward is something very different.

The Two-Front Pressure on Customers

For businesses, this shift shows up in two ways at the same time: costs are going up, and the system is starting to put conditions on when electricity can be used.

Electric bills today are not just about the cost of generating power. They include transmission buildout, policy programs, and capacity payments layered into the system. Those costs are embedded. They don’t show up as line items you can avoid. They are part of what it takes to operate here, and when the system is under stress, they don’t stay flat. They move quickly.

What’s important is how those costs get there. These aren’t collected through taxes. They are dictated by Maine’s energy policy, built into utility rates, and approved by regulators. That means policy decisions show up on electric bills without a clear line between the cost of the system and the cost of the policies driving it. To the customer, it is easy to attribute higher rates to utility management when, in reality, they are the result of state policy decisions.

At the same time, the system is beginning to place limits on how electricity is used. Maine has enacted policies that expand demand response and push customers toward off-peak consumption, and at the regional level pricing is moving closer to real time. When demand is high or there isn’t enough power available, the expectation is that customers—not the system—will adjust. Instead of building enough supply to meet peak demand, these policies rely on customers to change their behavior when the system comes under pressure.

At the same time, policy is pushing demand higher. The New England Heat Pump Compact, rebates through Efficiency Maine Trust, and electric vehicle policies are all designed to move more energy use onto the electric grid. We are adding load to a system that is already short when demand peaks, and that is not a side effect. It is the result of policy.

These are not market outcomes. They are policy decisions managing a system that cannot consistently meet peak demand on its own, and the result is a system that is both more expensive and more dependent on when you use it.

It is one thing to pay more for power. It is another to pay more and still be asked to manage when you can use it.

How We Got Here

This didn’t happen on its own. It is the result of a series of policy decisions made by Maine’s elected officials and regulators.

Democrats in the Legislature have passed laws that move the system toward managed demand, expanded electrification, and greater reliance on renewable generation. That includes authorizing time-of-use pricing, establishing demand response programs that push customers away from peak usage, redesigning net energy billing, and increasing renewable and clean energy mandates. These are not incremental changes. They reshape how the system is expected to operate.

Governor Janet Mills and her administration have backed and accelerated that direction through Maine Won’t Wait, setting aggressive electrification targets and shifting more energy use onto the electric grid. At the same time, those policies are being implemented in a system that is increasingly dependent on variable generation and less able to meet peak demand on its own.

The Maine Public Utilities Commission is where all of this shows up. It sets the rates, approves the programs, and makes the decisions that determine what customers pay and how the system actually works.

This direction was not accidental. It reflects a set of policy choices made under unified Democratic control of state government, and without bipartisan agreement on the path forward. The results are what matter. Costs have gone up. The system is less reliable at peak. Customers are now expected to adapt to a system that used to be built to serve them. The system no longer serves the customer. The customer now serves the system.

The Early Signals Are Already Here

This is not a future problem. It is already starting to show up.

In the past year, Maine has seen long-established businesses close or scale back operations. The Pride Manufacturing closure removed a major employer that had operated for decades. More recently, the Lumbra Sawmill in Milo announced it would shut down, another blow to a region that has already seen too many of these decisions.

A few years earlier, Dragon Cement shut down its cement manufacturing operations. The facility was eventually sold and now operates in a much more limited role, focused on importing and distribution rather than production. The plant remains, but the energy-intensive manufacturing and the associated jobs are gone.

These are not isolated events. They reflect a pattern. Costs are rising, margins are tightening, and operating conditions are getting harder to manage. In energy-intensive industries, electricity does not have to be the only problem. It only has to be the one that makes the rest unsustainable.

When electricity becomes more expensive, less predictable, and more dependent on timing, it changes the math. Planning gets harder. Risk increases. The margin for error disappears.

At the same time, companies making investment decisions have options. They can go to states where electricity is cheaper, where supply is built to meet demand, and where energy policy is aligned with growth. Those decisions rarely make headlines, but they matter just as much as a closure.

This is how it happens. Not all at once, but one decision at a time. Maine has seen this before. Paper mills didn’t all close in a single moment. Investment slowed. Facilities aged. Margins tightened. And eventually, plants shut down.

The same pattern is starting to take shape again. A project goes somewhere else. A facility is not upgraded. A plant eventually closes. By the time it becomes obvious, it has been happening for years.

What Kind of System Do We Want?

At its core, this is not a technical debate. It is a question about how the system is designed to work and who it is designed to serve.

For decades, the goal was straightforward. Build enough supply, secure the fuel, and deliver power when customers needed it. The system carried the burden so that businesses and households did not have to, and that model supported growth because it removed energy as a constraint.

We are moving away from that model. The system is becoming more expensive, more dependent on conditions it cannot control, and more reliant on customers to adjust their behavior. At the same time, policy is pushing more demand onto the grid through electrification, even as the system becomes less capable of meeting peak demand on its own.

That has real consequences. When electricity becomes a constraint, it changes how businesses operate, where they invest, and whether they stay. It affects job creation, industrial capacity, and long-term economic growth, and these are not abstract outcomes. Maine’s economy is already showing signs of strain, with real GDP growth of just 0.6% in 2025, one of the slowest rates in the country. Adding structural pressure to an already slow-growing economy is not a path to greater prosperity.

There is also a broader question. If the system requires customers to change when they use electricity—when they heat their homes, run their businesses, or charge their vehicles—then it is no longer just infrastructure. It is a system that is shaping behavior, and that is a very different relationship between the customer and the grid.

We can choose to build a system that serves the customer, or one that asks the customer to serve it. Right now, we are moving toward the latter, and that has implications far beyond energy policy.

The system no longer serves the customer. The customer now serves the system.

For decades, the global energy system ran on a simple assumption: disruption was temporary. Oil might be threatened, shipping lanes might be contested, prices might spike, but the system would adjust and return to normal. That assumption shaped everything from what we were willing to defend, to how we built our energy systems, to how regions like New England made long-term decisions.

That assumption was wrong, and it changes everything that follows.

Roughly one fifth of the world’s oil moves through this narrow passage.

Roughly 20 million barrels per day of oil typically move through the Strait of Hormuz, about one fifth of global supply. For decades, the threat of closing that chokepoint was treated as the ultimate lever. But what we’re seeing now is different. The flows are disrupted, prices are rising, and instead of waiting for things to snap back, countries are already changing behavior.

Buyers are shifting suppliers. Producers outside the Gulf are stepping in. U.S. exports are rising. Governments are accelerating alternative routes and rethinking how they secure supply. In real time, new trade patterns are forming and new alignments are taking shape.

But those changes don’t just stabilize flows. They change how energy actually moves. The old approach depended on global flows that were kept open and restored quickly when something went wrong, while the emerging reality is being shaped by geography, infrastructure, and access. Oil and gas are no longer just traded. They are routed, negotiated, and increasingly controlled.

That shift doesn’t just affect markets. It changes how countries think about risk, how they secure supply, and how they plan for the next disruption. New England is one of the places where that change matters most.

The World We Thought We Had

Since World War II, energy has functioned as a global network. The Middle East had the supply, Western companies and expertise developed it, and a worldwide shipping network moved oil and gas anywhere in the world it was needed. Geography mattered, but it did not determine outcomes, and if energy was available somewhere, it could generally reach you.

That network worked because a few key conditions held. Sea lanes remained open, even in periods of tension, and chokepoints like the Strait of Hormuz were understood risks that could be managed. The United States Navy and its allies had both the capability and the expectation of acting to keep those routes open. That expectation extended beyond military force and into the commercial system, where insurers like Lloyd’s of London underwrote global shipping on the assumption that disruptions would be temporary and manageable.

Alliances were aligned enough to support that mission. When the network was stressed, coordination generally followed, and access to airspace, bases, and logistics was assumed to be available when it mattered. At the same time, there was enough buffer to absorb shocks. Spare production capacity, alternative fuels, and flexible infrastructure allowed the network to adjust without breaking.

That model was tested repeatedly.

The oil embargo of the 1970s disrupted supply and drove prices sharply higher. The Iran–Iraq War threatened production and shipping in the Gulf. The Gulf War put critical infrastructure at risk. The financial crisis of 2008 collapsed demand and destabilized markets. The COVID pandemic disrupted both production and logistics at a global scale.

Each time, the pattern held. Supply adjusted. Shipping resumed. Alternative sources came online. Markets stabilized.

The details were different. The outcome was the same.

Over time, that behavior created something more important than supply alone. It created confidence that energy would show up where it was needed, even in a crisis.

What Just Changed

The current disruption looks familiar on the surface. A conflict threatens a critical chokepoint, oil flows are disrupted, prices rise, and markets react. By the standards of the past fifty years, none of that is unusual.

What is unusual is what happens next.

A ceasefire is announced, and the market does not settle. Shipping remains uneven, insurance markets hesitate, and flows do not quickly return to prior levels. The expectation that stability will follow is no longer being acted on in real time.

It shows up first in places most people don’t see. Tanker operators adjust routes or delay movement, insurers reassess risk and raise premiums or withdraw coverage, and buyers begin securing alternative supply rather than wait for conditions to normalize. Each decision is rational on its own, but taken together they change behavior.

The problem is not that supply has disappeared. The problem is that access has become uncertain, and that uncertainty triggers a different response. Energy flows are no longer pausing and returning. They are adjusting in real time, and once that starts, the old pattern breaks.

What That Means Now

If energy flows are being rebuilt, the implications are straightforward.

They become more regional, as supply moves to aligned markets rather than simply to the highest bidder, and geography begins to matter again. They become more constrained, with fewer backup options and less ability to absorb disruption without visible impact. They become more volatile, as smaller disruptions lead to larger and longer-lasting price swings. And control becomes more important, because access depends less on whether energy exists somewhere in the world and more on whether it can actually be delivered when and where it is needed.

Taken together, this is a shift from a world defined by availability to one defined by access.

What the Market Is Telling Us

The consequences are already showing up, not in a single place, but across decisions that point in the same direction.

Shipping patterns have shifted. Even after a ceasefire, traffic through the Strait of Hormuz does not return to normal overnight. Routes change, delays persist, and insurers reassess risk rather than assume it has passed.

Look at where ships are actually going. Tanker fleets are moving toward North America in visible numbers, clustering around U.S. ports and Atlantic routes instead of waiting for conditions to normalize in the Gulf. That doesn’t happen because of headlines. It happens when operators believe the underlying conditions have changed.

Alliances are less predictable, with coordination that once was assumed now needing to be negotiated and responses varying based on exposure and national interest. Fuel choices are changing as well. When gas becomes uncertain or expensive, countries do not wait. Coal runs longer, nuclear stays online, and reliability takes precedence over preference.

None of these changes, on their own, define the shift. Together, they do, showing energy flows being rebuilt around access and reliability rather than the expectation that everything will normalize.

New England Is Already Living This

If you want to understand where this is going, look at New England.

The region sits at the end of the line. Through policy choice, it has limited pipeline capacity, minimal storage, and relies on imported LNG during periods of peak demand. When conditions tighten, it doesn’t matter how much energy exists elsewhere. What matters is what can actually get here, and at what cost.

Those policy choices were made based on assumptions about how energy would be delivered and how disruptions would resolve. Those assumptions were wrong, and the consequences are showing up now.

Electrification does not eliminate fuel. It shifts the point of consumption, and electricity still has to be generated. In New England that generation depends heavily on natural gas, which becomes constrained in winter and forces reliance on LNG and oil. We built a reality that depends on external fuel at the moment of highest demand.

The Maine Policy Mistake

At this point, the response is predictable: build more wind, solar, and batteries. That sounds logical, but it is incomplete.

Wind and solar reduce fuel use when they produce, but they require backup when they do not. In winter, when demand is highest, they are least reliable. Batteries shift energy over hours, but they do not replace days of sustained demand. When the cold settles in and the heat is running hard for days, the question isn’t how to move energy around, it’s whether you have the fuel.

When those resources fall short, you still have to keep the heat on and the lights on. In New England, that means natural gas and oil, and the constraints do not go away. Pipeline capacity still matters. LNG still has to be imported. Oil still has to be delivered. The dependency remains exactly when it matters most.

And it comes at a cost. Maine is already seeing it as wind and solar are layered onto an existing model without replacing it. The region is paying for multiple systems at once while still relying on external fuel under stress. The result is higher cost without solving the underlying constraint.

That is the policy mistake.

What Comes Next

Energy is moving differently now, built around access, alignment, and control.

New England has spent a decade moving in the opposite direction, based on assumptions about how energy would be delivered and how disruptions would resolve. Those assumptions were wrong, and the world is adjusting accordingly.

The question is not whether we feel this shift. We already do. The question is whether we adjust to it. That means prioritizing deliverability, not just capacity, and recognizing that reliability in January matters more than averages in July.

Energy still underpins everything. If it is not affordable, reliable, and resilient, the rest of the economy adjusts around that constraint. The world is already adjusting, and the only question is whether we do it on our terms, or have it forced on us.

Prices jump, supply tightens, and shipping routes matter. That’s not new. It’s how global energy markets work.

What has changed is New England’s position in those markets. Events thousands of miles away now show up directly in New England’s energy costs, not because we produce energy there, but because we rely on those markets when demand is highest.

We didn’t just import fuel; we imported volatility.

That wasn’t always true, and it doesn’t have to be this way.

On the Coldest Days, New England Runs on Imports

That exposure is not theoretical. It shows up during the coldest periods of the year, when demand peaks across New England.

At those moments, the region’s pipeline system is fully utilized. Heating demand rises, power demand follows, and there is no additional local supply available to meet it. When that happens, the system turns to whatever fuel is available to close the gap.

Increasingly, that means imported liquefied natural gas.

During peak winter demand, New England relies on LNG and oil to close the gap when pipeline supply is constrained.

What matters is not just that LNG is used, but that it shows up when there are no cheaper or closer options left.

The last unit needed to meet demand sets the price.

When New England relies on LNG to close that gap, it is no longer operating as a local system. It is competing in a global market, where cargoes are priced against demand in Europe and Asia and influenced by events far outside the region.

That is how global volatility becomes local cost.

We Are Not Short on Energy

New England’s energy challenges are often framed as a lack of local resources. That’s not the issue.

The region sits roughly 300 to 400 miles from the Marcellus Shale, one of the largest natural gas basins in the world. Pennsylvania, Ohio, and West Virginia produce enormous volumes of energy just a short distance away, and Texas produces more natural gas than most countries.

New England is surrounded by energy, but lacks access to it when it matters most. Regions sitting on top of or directly connected to these resources don’t rely on imported LNG to meet winter demand. They draw from nearby supply, delivered through infrastructure designed to match local needs.

New England took a different path. Over time, policy choices limited access to domestic supply while encouraging increased reliance on electricity for heating and transportation. At the same time, the region reduced its ability to generate reliable power.

The result is a system that reaches outward for supply, even when abundant energy exists nearby.

We are not short on energy. We are short on access.

This Was a System Design Outcome

None of this is accidental. The system is behaving exactly as it was designed to behave.

Over time, policy choices constrained access to domestic fuel while increasing reliance on electricity, particularly during winter peak periods. At the same time, the region reduced its own dispatchable generation and replaced it with resources that are not always available when demand is highest.

Those choices did not eliminate the need for energy. They changed where it comes from and when it is available.

When demand rises beyond what local infrastructure can support, the system turns outward, drawing on imported fuel and external markets to close the gap. In New England, that increasingly means LNG.

Energy systems respond to physical constraints, not intent.

What Happens When the System Is Stressed

The impact of these design choices becomes most visible during extreme weather.

During Winter Storm Fern, New England’s energy system was pushed to its limits. Demand surged across both heating and electricity at the same time, and the region was forced to rely heavily on imported LNG and oil-fired generation to keep the system balanced.

The grid held, but with very little room to spare.

In testimony following the storm, the North American Electric Reliability Corporation noted that while the bulk power system remained reliable, the event highlighted how exposed it has become under stress. A system can be technically reliable and still be operating with very little room for error.

That fragility is not limited to cold weather. The same pattern shows up whenever global energy markets tighten.

In those moments, New England is not insulated. It competes for supply, costs rise, and the system leans more heavily on fuel from outside the region.

This is what happens when it gets cold and demand surges. It is what happens when competition for fuel increases. It is what happens when a major supply route like the Strait of Hormuz is disrupted, and fuel becomes harder to secure at any price.

This is not a hypothetical scenario. It is how the system already behaves when conditions are tight.

Other Regions Chose Differently

New England’s outcome is not unique, but it is not inevitable either.

Other regions faced the same basic reality and made different decisions. They built infrastructure to connect supply to demand, maintained access to dispatchable generation, and kept their systems anchored in local or regional fuel sources.

States with direct access to domestic supply and lower-cost generation consistently deliver lower industrial electricity prices than New England states.

The results are clear. Regions with direct access to domestic supply consistently see lower and more stable energy costs, particularly during periods of peak demand.

New England does not. Instead, it relies on higher-cost fuel during the very periods when energy matters most, and those costs flow directly through to businesses and consumers.

This is not a question of technology. It is a question of how policy choices have shaped the design of the system.

What This Means for Maine Businesses

For Maine businesses, this is not an abstract policy discussion. It shows up directly in operating costs and long-term competitiveness.

Energy is a core input for many industries. When prices are higher and more volatile, it becomes harder to plan, harder to invest, and harder to compete with businesses in regions where energy is more stable and more affordable.

Maine businesses are not just competing on products and services. They are competing on energy costs.

Over time, those conditions shape economic outcomes. Energy-intensive businesses look elsewhere to expand, and new investment flows to regions with lower and more stable costs.

This is not about a single bill or a single winter. It is about the structure of the system and the signals it sends to businesses making long-term decisions.

We’ve Seen This Pattern Before

New England is not the first region to encounter these dynamics.

In Europe, efforts to reshape energy systems by reducing domestic supply and increasing reliance on intermittent resources have produced similar outcomes. Installed capacity increased, but reliability did not, and the system became more dependent on imports and backup fuels.

The result has been higher costs, greater volatility, and increased pressure on industrial competitiveness.

The lesson is not political. It is structural.

When reliable, local supply is constrained, the system reaches outward toward imports and backup fuels.

New England is smaller, but the underlying dynamics are the same.

Energy Security Is a Structural Issue

The implications of this system extend beyond cost.

Energy underpins manufacturing, transportation, and the broader economy. When access to reliable, affordable energy is constrained, the effects ripple outward through every sector.

When energy must be sourced from outside the region at the moment it is needed most, the system becomes dependent on conditions it cannot control.

Energy policy does not just shape costs. It shapes resilience.

This Was a Policy Choice—and It Has to Be Fixed

The system New England has today is not the result of geography or technology. It is the result of policy.

Over time, state and regional leaders made a series of decisions that reshaped the system. They supported the early retirement of dispatchable generation, including nuclear facilities such as Maine Yankee and Vermont Yankee, along with coal plants across the region, removing reliable sources of power without equally dependable replacements in place. At the same time, they constrained access to domestic supply and pushed electrification of heating and transportation, increasing demand during the periods when the system is already under the most stress.

Those choices did not eliminate the need for energy. They changed where it comes from and when it is available.

In Maine, those policies have been promoted at the highest levels of government. Governor Janet Mills has advanced aggressive electrification targets under the state’s climate plan, Maine Won’t Wait, which targets a 45% emissions reduction by 2030 and at least 80% by 2050, alongside widespread electrification of heating and transportation. These policies increase demand on the electric system, particularly during winter, without a corresponding expansion of firm, in-region supply.

Across the region, similar decisions have been made. In Massachusetts, Governor Maura Healey, along with New York Governor Kathy Hochul, has supported actions that blocked key pipeline expansions into New England, including projects such as Access Northeast and the Northeast Energy Direct pipeline, both of which were intended to bring additional Marcellus gas into the region. Permit denials and regulatory opposition ultimately prevented those projects from moving forward.

The result is a system that remains constrained on the supply side while demand continues to grow.

This is not about intent. It is about outcomes.

When supply is constrained and demand is increased, the system becomes more expensive, more volatile, and more dependent on external sources. That is exactly what has happened.

The purpose of an energy system is straightforward. It must be affordable, reliable, and resilient. If those conditions are not met, the system is not working, regardless of the goals used to justify it.

Policy needs to reflect that reality. That means reconnecting to domestic supply, matching demand growth with reliable capacity, and rebuilding a system anchored in sources we can access and control.

The Bottom Line

Events halfway around the world should not determine the cost of energy in Maine, but today they do.

On the coldest days of the year, New England relies on imports priced in global markets at the moment demand is highest.

We did not eliminate fossil fuels. We changed where they come from and when we depend on them.

We traded proximity for exposure, stability for volatility, and control for dependence.

An energy system has a simple job: deliver energy that is affordable, reliable, and resilient. When it doesn’t, the consequences show up immediately in cost, volatility, and risk.

This system didn’t happen by accident. It was built—and it has to be fixed. Even if we start today, it will take years. Every day we wait increases the cost, the risk, and the damage to the region’s competitiveness.

I was looking at a utility bill in Waterville, Maine recently and had the same reaction I hear from customers every day, how is this this high?

Not just high, confusing. Different charges, different rates, delivery, supply, adjustments, and that is before you even ask what it will look like next winter.

Underneath it all is the same assumption most people make, this must be about the fuel. Oil, propane, electricity, natural gas, maybe a heat pump.

It is not. It is about the system behind that fuel, and in New England that system is constrained, exposed, and under increasing pressure.

That is why two buildings on the same street can see very different energy costs, and it is why what happens in Texas, Québec, or the Strait of Hormuz can show up on your bill in Waterville. Right now those pressures are building, not easing.

What Matters Right Now

Before comparing fuels, it helps to be clear about the system we are operating in.

New England is not a balanced energy system. It is a constrained system that operates close to its limits much of the time, which is why the region relies so heavily on imports. New England routinely imports roughly 10 to 15 percent of its electricity from New York and Canada, and during stressed conditions that share can increase.

Local infrastructure, especially pipelines and transmission, has not kept pace with demand. As a result, the system depends on flows from outside the region to stay stable.

Winter still matters most, but it is no longer the only stress point. Cold weather drives heating demand at the same time that natural gas is needed for both homes and power generation, which tightens supply quickly.

During cold periods, LNG is not a marginal fuel in New England, it is a core part of the system. Depending on conditions, roughly 20 to 40 percent of the region’s natural gas supply can come from LNG rather than pipeline gas.

That is not because the region lacks natural gas. It is because it lacks the infrastructure to move enough of it when demand peaks. Pipeline capacity into New England has remained effectively fixed for years, as proposed expansions have been blocked or not permitted in New York and Massachusetts. Maine’s governor and administration have supported that same policy direction, opposing new pipeline infrastructure and reinforcing a system that relies more heavily on imports rather than readily available domestic supply.

The result is a system that cannot access nearby, low-cost domestic natural gas when it is needed most. When heating demand and power generation both rise at the same time, the system turns to LNG and, in some cases, fuel oil to fill the gap. Power generators face the same constraint, and when pipelines are fully utilized they either secure LNG or switch to oil to keep the grid running.

In practical terms, a significant share of New England’s winter energy supply depends on the same global LNG market as Europe and Asia.

At the same time, summer peaks are getting steeper. Heat pumps are adding air conditioning load in places that historically did not have it, particularly in Maine, and that pushes the system hard during hot, humid days.

So the system is now under pressure in both winter and summer, for different reasons, but with the same underlying constraint, limited infrastructure relative to demand.

Global markets layer on top of that reality. Oil prices move directly with global events, and instability in the Middle East adds risk to both price and supply. Propane is even more exposed than most people realize. It is produced domestically, but it is sold into a global market, which means demand from Europe and Asia can pull U.S. supply offshore and tighten availability here.

The result is straightforward. Even when the United States looks well supplied, New England can still be tight. Prices do not move evenly, and risk does not show up the same way across fuels. The difference is not the fuel itself, it is how each one is connected to a system that is already under stress.

Heating Oil, Global Pricing, Strong Local Logistics

Heating oil is the most straightforward fuel in Maine, and that is part of its strength.

It is produced by refining crude oil into products like gasoline, diesel, jet fuel, and heating oil. That means its price is tied not only to crude oil, but also to refining margins, often referred to as the crack spread.

Refiners do not produce a fixed mix of products. Within the limits of their equipment, they shift output toward the highest value products. When diesel or jet fuel prices are strong, refineries maximize those yields and reduce the share of lower value products like heating oil. In practice, heating oil is not just priced off crude, it is competing with diesel and jet fuel for priority inside the refinery.

That is why refining margins matter. When distillate markets are tight, whether due to global demand, seasonal factors, or outages, heating oil prices can rise faster than crude because it is competing for a smaller share of the barrel.

But in New England, the delivery system for heating oil is deep and well established. There are multiple terminals across the region, significant storage, and a distribution network that has been built over decades. Oil also benefits from its connection to broader distillate markets, which allows supply to be redirected and balanced more easily than other fuels.

That matters under stress. Even in difficult winters, heating oil tends to remain available. Deliveries may get delayed, and prices may rise, but the system has enough depth and redundancy to keep fuel moving.

For many homeowners and small businesses without access to natural gas, heating oil remains the default not because it is cheap, but because it is dependable.

The tradeoff is clear. Heating oil is fully exposed to global markets and refining conditions, so you feel it when the world gets tight, but in Maine it is still one of the fuels most likely to show up when you need it.

Propane, Global Fuel, Local Constraints

Propane looks like a local fuel. It is not, and understanding where it comes from explains why.

Most propane in the United States is produced during natural gas processing, when heavier hydrocarbons are separated from the gas stream. A smaller portion comes from oil refining. That means propane supply is tied to both natural gas production and refinery activity, but it is not the primary product in either case.

Propane is priced in a global market. The United States exports large volumes, so domestic supply is directly connected to demand in Europe and Asia. When global prices rise, U.S. barrels move offshore.

New England sits at the end of that system. Propane arrives by rail, marine shipments, and truck, then must be stored locally before winter. The system depends on building inventory ahead of peak demand and managing logistics throughout the heating season.

When the market is tight, inventory is low, transportation capacity is fully utilized, and there is little margin for error. The country can be well supplied and New England can still be short, because the constraint is not production, it is positioning the fuel before it is needed.

That showed up this past winter. Supply existed, but delivery timing and logistics were strained during peak periods, and customers experienced delays. The issue was not whether propane existed in the system, it was whether it was in the right place at the right time.

The tradeoff is clear. Propane is exposed to global markets like oil, but without the same depth of local infrastructure, which makes it more dependent on logistics working exactly as planned.

Electricity and Heat Pumps, Dependent on a Constrained System

Electric heating, including heat pumps, shifts dependence from delivered fuels to the electric grid.

In New England, that grid is built around natural gas. Roughly half of the region’s electricity is generated from natural gas, and most of the time the last unit needed to meet demand is also gas fired, which means electricity prices are tied to gas availability and cost.

In winter, that relationship becomes exposed. The same gas system serves both heating and power generation. When demand rises, power plants compete with homes and businesses for limited pipeline capacity. As gas tightens, generators either pay higher prices, switch to LNG, or burn oil, and those costs set the market price of electricity.

There is another factor that matters just as much, policy driven cost.

State renewable portfolio standards, or RPS, require increasing amounts of electricity to come from renewable sources. Meeting those requirements drives large scale investment in wind, solar, and the transmission needed to connect those resources, and those costs are recovered through electric rates over time. At the same time, the Regional Greenhouse Gas Initiative, or RGGI, places a cost on carbon emissions from power plants. That cost flows directly into the price of electricity, even though those same plants are still required to meet demand during peak periods.

These costs are embedded in rates, not optional, and they scale with how much electricity is used. The result is a system where costs are layered on from multiple directions. New generation, new transmission, and carbon pricing all push rates higher, while the system continues to rely on natural gas and oil for reliability.

More importantly, these costs are not one-time. They are built into policy and increase over time, which means rates rise automatically unless the underlying policy direction changes.

Those costs do not show up all at once, but they accumulate and are reflected in delivered electricity prices. In New England, electric rates are not just set by fuel, they are shaped by policy choices layered on top of the system.

Against that backdrop, adding electric heating increases exposure to those same cost drivers.

Heat pumps are often described as efficient, but that comparison is usually made at the appliance level. High efficiency natural gas furnaces are also very efficient. The difference is how the system performs under stress.

In cold weather, heat pumps add electric load to a grid that is already constrained. That load has to be met in real time. In New England, that means more natural gas generation when it is available, and more LNG or fuel oil when it is not.

Reliability at the distribution level matters as well. Maine experiences some of the longest outage durations in the country, driven by weather, vegetation, and a rural network that is expensive to maintain and hard to harden. For customers, the cause does not matter. If the power is out, electric heat, including heat pumps, is out.

Imports are often treated as a backstop, particularly from Hydro-Québec. In practice, those imports are not firm during regional cold events. Québec also experiences winter peak demand, and when its system is stressed it reduces or stops exports to serve its own customers first.

This is not a one-time event. It is a predictable outcome of how the system is designed. When cold weather hits the entire region at the same time, New England, New York, and Québec are all drawing on their systems simultaneously. In those conditions, Québec does not act as a reserve for New England.

That pattern has shown up repeatedly in recent years, including during Winter Storm Fern. The New England Clean Energy Connect, often referred to as the Corridor, was widely presented as a source of firm winter imports. During peak conditions, it did not provide additional supply. At times, power that normally flows into New England instead flowed north as the system balanced across the region.

At the moment New England needs imported power the most, it should expect less of it, not more.

Policy is pushing this further. Heat pump targets alone are expected to add several gigawatts of peak demand over time, on the order of 4 GW, without a corresponding buildout of firm generation or fuel supply to match it.

If the grid is under stress or outages occur, efficiency is no longer the question. Electric heat depends entirely on the system being available.

In New England, electricity prices are not just about power, they are about access to fuel at the moment it is needed most.

Natural Gas, Domestic Supply, Constrained Delivery

Natural gas is different from the other fuels in one important way. It is primarily a domestic resource, produced in large quantities in the United States, particularly from the Marcellus shale, located relatively close to New England.

That proximity matters. Unlike oil and propane, which are priced in global markets, natural gas reflects domestic supply and demand in most of the country.

The constraint is delivery. Pipeline capacity into New England is limited, and that limitation defines the region’s energy system. The issue is not supply, there is abundant natural gas within a few hundred miles of Maine. The issue is the ability to move that gas into the region when demand is highest.

When pipeline capacity is available, natural gas is typically the lowest cost and most stable fuel. When pipelines are full, prices rise and the system turns to LNG and oil.

Natural gas flows continuously once it is in the system. It does not depend on truck delivery, rail logistics, or on-site storage. For customers with access, that provides a different level of reliability.

The tradeoff is clear. Natural gas offers lower price volatility and continuous delivery where infrastructure exists, but access is limited by the same pipeline constraints that define the region.

What Does This Actually Cost in Maine

Based on current pricing from the Maine Governor’s Energy Office heating fuel price page and typical usage ranges, the differences between fuels are not subtle.

For a 1,500 square foot home, heating oil typically ranges from $3,800 to $4,800 per year. Propane is often higher, between $4,500 and $5,800. Natural gas, where available, is materially lower, often between $1,800 and $2,600. Electric heating falls in between but varies with rates and peak exposure.

For a 3,000 square foot home or small commercial space, the gap widens. Heating oil runs roughly $7,000 to $9,000. Propane can reach $8,500 to $11,000. Natural gas remains significantly lower, typically between $3,500 and $5,000. Electric heating scales with load and becomes increasingly sensitive to peak pricing.

These are not small differences. For homeowners, they show up as higher bills. For small businesses, they flow directly into operating costs and margins.

The Big Picture

New England is not short on energy. It is short on the ability to deliver it when and where it is needed most.

That constraint shows up differently depending on the fuel. Oil is exposed to global markets and refining conditions but moves through a deep delivery system. Propane depends on global markets and local logistics with less margin for error. Electricity depends on a constrained grid and rising policy driven costs. Natural gas is abundant and domestic but limited by pipeline capacity.

These differences determine how each fuel behaves when the system is under stress, which is the only time that really matters.

In Maine, heating is not just about price. It is about which system you rely on when demand peaks and conditions are the most difficult. For homeowners, that shows up in bills and variability. For small businesses, it shows up in margins and risk.

Closing

Most people think choosing a heating system is about finding the lowest cost option, but that misses the point. The real question is which risks you are taking on.

Oil ties you to global markets. Propane ties you to global markets and local logistics. Electricity ties you to a constrained grid and rising system costs. Natural gas ties you to domestic supply, where infrastructure exists.

Those risks show up when demand is highest and the system is under pressure. The system does not care what your thermostat says, it cares what shows up when it is 5 degrees and dark.

1. The Chart Behind the Claim

For years now, we’ve been told that solar and wind are the cheapest sources of electricity. That claim shows up everywhere—in headlines, policy discussions, and investor decks—and it’s usually backed by some version of a simple cost comparison like this.

On its face, the conclusion is obvious. Solar and wind appear to be the lowest-cost options, while gas looks more expensive.

The chart isn’t wrong—but it’s incomplete. And when incomplete math drives policy, the system ends up costing more than advertised.

It measures the cost of producing electricity when it’s available—not the cost of running a grid. Those are very different things.

It’s also worth noting that rooftop solar doesn’t operate in a vacuum. Net energy billing ties compensation to retail rates rather than system value, so deployment follows customer economics—not grid needs. The result is more distribution upgrades, more complex power flows, and costs that don’t always line up with system benefit—all while the grid still has to be built for peak demand.

2. What the Chart Misses

The grid doesn’t run on averages. It runs on the worst day of the year—cold, dark, and still. That’s the moment the entire system is tested, and the moment that determines what it actually costs.

Wind and solar can be cheap when they produce power, but that’s not the same thing as delivering power when it’s needed. Cheap electricity isn’t the same as dependable electricity.

A power system has to be built to meet demand at all times, not just when conditions are favorable. That means having enough capacity available to carry the load even when intermittent resources aren’t producing. It also means maintaining the infrastructure, fuel supply, and operational flexibility to respond when conditions change.

Once you look at it that way, the gap becomes obvious. The cost of producing electricity is only one piece of the puzzle. The cost of making sure it’s there when you need it is what actually defines the system.

3. What This Looks Like in the Real World

If this still feels theoretical, you can see it play out in real time in places that have leaned heavily into solar.

California now produces so much solar power at midday that electricity prices can collapse to near zero—or even go negative, because supply exceeds demand. That sounds like a success until a few hours later, when the sun sets and demand is still high. At that point, the system has to replace a large amount of lost generation very quickly. Dispatchable plants ramp, imports increase, and prices rise as the system scrambles to maintain balance.

Nothing about that is free. The system still has to be built to handle both conditions—the oversupply in the middle of the day and the shortfall in the evening. That means maintaining capacity that sits idle for part of the day and then runs hard when it’s needed most.

Batteries can shift some of that midday solar into the evening, but only within limits. Most grid-scale batteries today are designed to discharge for a few hours, not to carry a system through multi-day weather events or extended winter peaks. Batteries don’t know where electricity comes from—they respond to price. And in many hours, that price is set by a grid still dominated by natural gas.

To rely on them as a full solution, you would have to build enough excess generation to charge them and enough storage to carry the system when that generation isn’t there. That means building significantly more capacity than you otherwise would, and then maintaining a system that is both larger and more complex.

4. The Simple Reality Check

There’s a simple way to test the claim that wind and solar are now the cheapest sources of electricity. Look at the places that use the most of them. If the claim were true, those places should have the lowest electricity prices.

They don’t. States like California, which have invested heavily in solar, consistently have some of the highest electricity prices in the country, while many lower-cost regions rely more heavily on power plants that can run when needed.

At some point you have to decide whether to trust the model or what’s actually happening.

5. What It Actually Takes to Run a Grid

What’s missing from that original chart is everything required to make the system work. A power system doesn’t just produce electricity—it has to deliver it reliably, at all times, under all conditions.

That means maintaining backup generation for when the sun isn’t shining and the wind isn’t blowing. It means building storage to shift energy across hours or days. It means expanding transmission to move power from where it’s produced to where it’s needed. And it means carrying enough redundancy in the system to ensure it doesn’t fail under stress.

None of that is free, and none of it is optional.

Once those requirements are included, the economics change. The question is no longer which resource produces the cheapest electricity in isolation, but what combination of resources can meet demand reliably. That’s a very different problem—and a much more expensive one.

6. The Myth of “Transition”

There’s another assumption buried in this conversation—that we’re “transitioning” from one energy system to another. History suggests otherwise.

We didn’t stop using wood when we discovered coal, and we didn’t stop using coal when oil took off. Each new energy source was added to the system, not substituted for the one before it. Over time, the mix changed—but the system only grew larger.

In fact, the only major fuel we’ve ever truly abandoned at scale was whale oil—and that wasn’t because of policy or preference, it was because something dramatically better came along.

Even today, older fuels don’t disappear. The world still burns enormous amounts of wood for energy, and in many places people still rely on animal dung for heat and cooking.

The same pattern is playing out today. Wind and solar are being added to the grid, but the underlying system that ensures reliability—power plants that can run when needed, fuel supply, and infrastructure—has not gone away.

So far, the result is clear. We haven’t replaced the old system—we’ve duplicated it.

7. We Already Understand This

You can see the same logic in how people heat their homes. In colder regions, people rely on fuels that work when it matters—natural gas, oil, propane—because they can deliver heat on demand. In milder climates, electric heating is more common because the consequences of coming up short are lower.

That’s not ideology, it’s physics. People make decisions based on what works under the conditions they actually face, not what looks best on average.

No one in Maine chooses how to heat their home based on what works in South Carolina.

8. What This Means for New England

That same dynamic is playing out in New England.

On the coldest winter evenings, solar output is effectively zero, wind is often unreliable, and demand is at its highest. The system has to meet that demand regardless of conditions, which means relying on power plants that can run when needed and the fuel supply required to support them.

But the issue isn’t just winter. Solar production is concentrated in the middle of the day, while demand often peaks in the early morning and evening. It also varies by season, producing far more energy in the summer than in the winter, when the system is under the most stress.

That mismatch matters. Even when solar is producing, it often isn’t producing when the system needs it most.

In those moments, the grid isn’t running on what was cheapest to build—it’s running on what is available. And in New England, that often means natural gas, supplemented by oil and imports when the system is tight.

That reality drives cost. The region has to maintain the infrastructure and fuel supply to meet peak demand while also building out additional resources that may or may not be available when needed. The result is a system that is more expensive to operate, not less.

9. Complexity and Risk

As we push toward more wind, solar, and battery systems, we’re not just changing where electricity comes from—we’re changing how the grid operates.

The traditional system relied on large, predictable power plants that provided stability as a byproduct of how they ran. The newer system relies far more on power electronics, software, and coordination to keep everything in balance. That can work, but it’s inherently more complex.

In pilot training, you learn that the best flights are boring. That only happens with preparation, simplicity, and margin for error. As complexity increases, so does the chance something goes wrong. Power systems aren’t that different.

There’s also a dimension here that gets far less attention: risk. Building out these systems increases reliance on global supply chains for critical materials and components, and much of that supply chain runs through China. China dominates the refining of many key minerals and manufactures the vast majority of the world’s solar panels. Producing those panels is energy-intensive, and much of that energy comes from coal.

None of that makes the technology unusable, but it does change the risk profile. We’re shifting part of our energy system—from fuel we control domestically to supply chains we don’t—while making long-term decisions about infrastructure that will be in place for decades.

10. The Bottom Line

The original chart isn’t wrong. It’s just incomplete.

It tells you what it costs to produce electricity under ideal conditions, but it leaves out what it takes to run a system that has to perform under real ones. Once you account for reliability, timing, infrastructure, and risk, the picture changes.

We haven’t built a cheaper system. We’ve built a larger one—one that layers intermittent resources on top of the infrastructure required to keep the lights on when wind and solar aren’t producing.

And that cost doesn’t disappear. It shows up in higher rates, more complexity, and a system that is harder to operate and more fragile.

If you want to understand how Maine’s energy policy actually works, start in Falmouth.

The town operates a large solar array on the capped landfill on Woods Road. The project is an 875-kilowatt installation that produces roughly 1.5 million kilowatt-hours of electricity per year, enough to offset about 70 to 75 percent of the town’s municipal electric use. Over its twenty-year life, the town estimates it will save about $2 million in electricity costs.

Projects like this are easy to support locally. The land is already unusable for other purposes, the optics are good, and the savings show up directly in the municipal budget.

Falmouth is also not a typical Maine town. Its median household income is roughly $125,000, compared with about $70,000 statewide, and its poverty rate is a fraction of the state average. That helps explain why communities like Falmouth are often early adopters of programs like this: they have the administrative capacity, large municipal loads, and financial flexibility to move quickly when opportunities appear.

But the landfill project is only part of the story.

Across Maine’s energy system — community solar, wind farms, and grid-scale batteries — the financial structure is often similar: local benefits paired with costs that spread broadly across the system.

When costs are spread systemwide while savings accrue locally, households and businesses across Maine help pay for energy savings in some of the state’s wealthiest towns — a kind of reverse Robin Hood effect built quietly into the structure of the policy.

To see how the system works, you have to follow the incentives. Once you do, the outcomes that often look confusing — from community solar to rising electricity costs to winter reliability warnings — begin to make sense.

How the System Works

The landfill project in Falmouth is one of the simpler examples of Maine’s renewable policy at work. The town built a solar array on land it already owned and uses the electricity to offset its own demand. Projects like this behave much like any other infrastructure investment: the town puts capital into a facility and receives the resulting electricity savings over time.

Most renewable development in Maine works very differently.

Community solar projects are usually built and financed by private developers who then sell subscriptions to households, businesses, and municipalities. Subscribers do not receive electricity directly from the solar farm. Instead, the electricity produced by the project flows into the regional grid, and subscribers receive bill credits on their electric accounts based on their share of the project’s output.

In Maine this structure operates through the state’s net energy billing program, which sits at the center of most community solar projects. Under net energy billing, electricity generated by a solar project is sold into the grid and subscribers receive bill credits tied to that production.

Those credits are typically calculated close to the full retail value of electricity, including both supply and delivery charges. That detail matters because the solar project is not actually replacing all of those costs. Even when solar panels are generating power, the grid still has to move electricity across transmission lines, maintain local distribution networks, and keep dispatchable power plants available for times when solar output drops.

From the subscriber’s perspective, the arrangement can still be attractive. There is no upfront investment, contracts are typically long-term and predictable, and even modest savings can show up immediately in operating budgets. If a municipal account receives $100,000 worth of solar bill credits in a year, the town might pay the developer roughly $85,000 to $90,000 for those credits and keep the difference.

The cost of operating the electric system, however, does not disappear. Transmission lines still have to be maintained. Distribution networks still have to deliver power to homes and businesses. Dispatchable generation still has to be available when solar output falls.

When bill credits offset those costs on one customer’s account, the system still has to recover them somewhere else. In practice, that means other customers pick up a larger share of those fixed costs.

For developers and investors, the economics are far more predictable. Solar projects are financed with federal tax credits, accelerated depreciation, and long-term subscription agreements that create steady revenue once the project is operating. With much of the capital cost supported by tax incentives and revenue streams largely locked in for decades, the financial risk is far lower than for most merchant power plants.

The same basic structure appears across several renewable technologies. Solar farms rely on net energy billing. Wind projects in Maine often depend on long-term power purchase agreements and renewable energy credit markets that provide revenue even when electricity is produced at times the grid may not need it most. Grid-scale batteries, including the installation developed in Gorham, are compensated through wholesale electricity markets designed to help manage fluctuations from intermittent generation.

These policies do not apply in the same way to dispatchable power plants such as natural-gas or oil facilities. Those plants earn most of their revenue from wholesale energy and capacity markets and must operate reliably during periods of peak demand or face financial penalties.

The system works well when electricity supply is abundant. The real challenge appears during winter peaks, when electricity demand rises sharply and renewable output is limited. At those moments New England still depends heavily on dispatchable generation — often fueled by natural gas, oil, or imported LNG — to keep the grid operating.

The Subsidy Stack

To understand why so much capital has flowed into solar, wind, and battery projects over the past decade, it helps to look at how these projects are financed.

Most people assume renewable projects succeed or fail based primarily on electricity sales. In reality, the financial structure often relies on several layers of policy-driven incentives stacked on top of one another.

The largest of these is the federal Investment Tax Credit, expanded significantly under the Inflation Reduction Act. For solar projects, the credit typically covers about thirty percent of construction costs before a facility produces a single megawatt-hour of electricity.

While federal policy debates have recently focused on scaling back incentives for future projects, the more important reality is that existing projects keep what they locked in. Once a project qualifies, the tax benefits are baked into its economics, and the long-term contracts built around them continue for decades.

Wind projects have historically relied on a different federal incentive known as the Production Tax Credit. Under this program, project owners receive a federal payment for every megawatt-hour their turbines generate during the first years of operation. Today that credit is worth roughly $27 to $28 per megawatt-hour.

That payment arrives before the electricity is sold into the market. After collecting the credit, the project can then sell the same electricity into the wholesale power market like any other generator.

In New England, wholesale electricity prices frequently fall in roughly the same range. That means a wind project may receive a federal payment comparable to the market value of the electricity it produces — and then sell that electricity as well.

This structure allows wind generators to remain profitable even when wholesale prices are extremely low, and it influences how generators behave in electricity auctions and wholesale markets — an issue that becomes important when looking at investment trends across the region.

Investors also benefit from accelerated depreciation, often referred to as MACRS. Instead of writing off a project’s cost gradually over its lifetime, investors can recover most of the investment through tax deductions within the first few years. In practical terms, a significant portion of the capital invested in a renewable project is returned through the tax code long before the project has generated much electricity.

State policies add another layer. In Maine, utilities must meet the state’s Renewable Portfolio Standard, which requires an increasing share of electricity to come from renewable sources. Renewable generators receive Renewable Energy Credits for each megawatt-hour they produce, and those credits can be sold separately from the electricity itself.

The region also participates in the Regional Greenhouse Gas Initiative, a carbon trading program that raises the cost of fossil-fueled generation and directs funding toward energy programs across participating states.

Maine’s net energy billing program adds another major piece to the structure. Subscribers receive bill credits tied to the retail price of electricity rather than the wholesale price generators normally receive. Because retail rates include both energy and delivery charges, these credits can exceed what the electricity is worth in the wholesale market.

Finally, most projects secure long-term contracts that stabilize revenue. Community solar developers sell subscriptions to municipalities, businesses, or households that agree to purchase bill credits for fifteen or twenty years. Wind projects often rely on power purchase agreements in which utilities or large customers commit to buying electricity at fixed prices over similar timeframes.

Taken together, these incentives create a layered financial structure. Federal tax credits lower the cost of building the project. Accelerated depreciation improves investor returns. Renewable energy credits provide additional income tied to state policy. Net energy billing and long-term contracts stabilize revenue for decades.

Electricity sales still matter, but they are often only one piece of the overall financial picture.

How the Market Signals Changed

These incentives do not just affect how projects are financed. They also change how generators behave once they enter electricity markets.

In New England, electricity is bought and sold through organized wholesale markets run by ISO New England. The basic idea is straightforward. Every day — and every hour — power plants offer electricity into the market at the price they are willing to accept. The system operator then takes the lowest-cost offers first and keeps adding generation until enough power is available to meet demand.

The price paid to all generators is set by the last and most expensive unit needed to keep the lights on. That becomes the market price for electricity during that hour.

The incentives described earlier change how some generators behave in that system.

Because wind projects receive production tax credits for every megawatt-hour they generate, they have a strong incentive to keep producing even when market prices fall very low. In some cases they can afford to offer electricity at prices near zero — or even negative — and still make money once the federal credit is included. Since the credit is only earned when the turbines are generating electricity, developers are motivated to keep producing whenever the wind is blowing.

That behavior pushes down the overall market price. When enough subsidized generation enters the system with very low bids, the market price for electricity can fall below the level needed for other types of power plants to recover their costs.

This affects dispatchable power plants most directly — the natural gas and oil facilities that can increase production quickly when demand rises. Unlike wind or solar, these plants generally do not receive layered policy incentives. Their revenues come almost entirely from wholesale electricity markets and capacity payments.

When energy prices stay low for long stretches, those plants struggle to cover fuel costs, maintenance, and capital recovery. Investors notice that quickly. If markets consistently fail to support new dispatchable generation, developers stop building it.

That shift is already visible in New England. Most of the region’s dispatchable fleet was built years ago, and very little new firm generation is being developed today. In contrast, Texas has taken direct action. Through the Texas Energy Fund — a $10 billion voter-approved financing program — the state is actively supporting new dispatchable generation, particularly natural-gas plants. Projects are already advancing under that structure, highlighting how differently regions are responding to reliability and investment signals.

Energy analyst Meredith Angwin describes this problem clearly in her book Shorting the Grid. Electricity markets are supposed to reward the resources needed most to keep the system reliable. When policy incentives reshape those markets, the signals investors rely on begin to change.

The consequences are gradual rather than immediate. The system can appear stable for years as older power plants continue operating. Over time, however, fewer new dispatchable resources are built even as electricity demand continues to grow.

That imbalance becomes most visible during winter peaks in New England, when demand is highest, solar output disappears early in the day, and the region still depends heavily on fuel-constrained dispatchable generation to keep the lights and heat on.

Winter Reality

Some argue that as more solar, wind, and batteries are built, the region will eventually need less gas and oil. The experience of recent winters suggests otherwise.

During Winter Storm Fern in January 2026, solar output effectively disappeared during the peak evening hours — exactly when electricity demand was highest. Wind generation was volatile and could not be relied upon to meet the system’s needs. As temperatures dropped and natural-gas pipelines tightened, the region leaned heavily on dispatchable generation instead. Oil-fired output surged above 4,000 MW, and dual-fuel plants switched from gas to oil to keep the system operating.

Advocates often argue that building enough wind and solar will eventually eliminate the need for thermal generation. But winter in New England doesn’t work that way. Adding more weather-driven generation does not guarantee electricity when conditions line up against it.

As any sailor knows, there may be more boats on the water — but without wind, nobody moves.

Electric grids face a similar challenge. When regional weather patterns suppress renewable output, adding more turbines or solar panels does not necessarily solve the problem. It can simply mean more equipment producing less power at the same time.

That is why the region still relies heavily on dispatchable generation during winter peaks. Natural gas, oil, LNG imports, and stored fuels remain the resources that keep electricity flowing when temperatures fall and renewable output fades.

If current trends continue, New England will be trying to serve a much larger winter peak with an older and thinner dispatchable fleet. ISO New England projects winter demand rising from roughly 20,000 MW today to more than 26,000 MW by the mid-2030s, largely because of electrification of heating and transportation.

At the same time, the region continues to lose dispatchable generators while building very little new firm capacity. Reliability authorities including NERC and FERC have repeatedly warned that winter reliability risks in New England are increasing, particularly during prolonged cold-weather events when fuel supplies tighten.

This does not mean the grid suddenly collapses. It means the margin for error shrinks. The system becomes more dependent on aging thermal plants, imported fuels, and emergency measures during the coldest hours of the year.

As reliability margins shrink, costs rise as well. Electricity markets respond to scarcity with price spikes, and maintaining reliability requires duplicative investment — expanding intermittent generation while still paying to keep backup generation, fuel supply, and grid infrastructure available for the hours when renewable output disappears.

The result is a grid that becomes both more expensive and less predictable. High electricity costs are not manageable for energy-intensive industries. Maine once supported a large paper manufacturing base, but more than a dozen mills have closed in just over two decades as energy costs and global competition eroded the industry’s competitiveness.

Communities from Bucksport to Millinocket learned the hard way that when energy costs move the wrong direction, industries do not hedge — they shut down or leave. Energy-intensive industries go where power is affordable and reliable. When it isn’t, the investment simply goes somewhere else.

None of this is happening by accident. The outcomes reflect the incentives embedded in the system. Federal subsidies, state renewable mandates, Maine’s net energy billing program, and market rules that reward subsidized generation are all pushing investment in the same direction — toward intermittent resources and away from dispatchable power.

Investors respond to incentives. When the rules favor certain technologies and discourage others, capital follows. The structure of the policy determines the structure of the grid that gets built.

The developers building these projects are not behaving irrationally. They are responding exactly the way the policy framework is designed to encourage them to respond.

If New England continues down its current path — discouraging investment in dispatchable generation while winter demand rises — the region risks building a grid that is more fragile, more volatile, and more expensive than the one it replaced.

The lights may stay on. But the system will be harder to run, more expensive to maintain, and far less forgiving when conditions turn against it.