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Rethinking Grid Reliability in New England: Beyond the Outdated Notion of Baseload Power

For years, grid reliability has been locked into an outdated framework that sees power generation as a rigid hierarchy. In this model, baseload power plants, typically coal, nuclear, or large hydro, provide the system’s foundation. Intermediate plants ramp up as demand rises, and peaker plants fire to handle extreme conditions. This rigid sequence has shaped how we plan, regulate, and invest in electricity infrastructure.

However, clinging to this traditional model is holding us back. Thanks to new technology, smart energy management, and flexible power use, we now have better ways to keep the grid stable—especially in New England, where winter storms, high electricity costs, and limited natural gas supply complicate energy planning.

A recent Duke University study, Rethinking Load Growth, offers critical insight into how large electricity loads like data centers, industrial electrification, and managed demand response, when operated flexibly, can actually enhance reliability and minimize the need for new power plants. Instead of obsessing over the diminishing role of traditional baseload power, the New England grid should embrace this dynamic, adaptive reliability model—one where flexible demand, smart grid coordination, and intelligent load balancing take center stage.

Myth: Renewable Energy is “Unreliable”

Critics of renewable energy often argue that wind and solar threaten reliability because they are “intermittent.” The logic goes that the grid will become unstable without a steady supply of fossil or nuclear power running 24/7. But this fear is rooted in an outdated view of how electricity systems function. The grid does not operate on a simple “always-on” philosophy—it is a highly dynamic system, constantly responding to shifting conditions in supply and demand.

In reality, all power sources are variable—not just renewables. A nuclear plant can experience an unexpected outage. Gas-fired power plants depend on pipeline infrastructure that can freeze or fail, as New England has experienced during extreme cold snaps. Even coal plants have been forced offline due to fuel supply chain disruptions. The notion that “baseload” is inherently reliable is not just misleading—it’s dangerous. In fact, a little over a year ago, the CEO of ISO-NE testified before FERC that reliability would be solid for the next several years, in part because of wind and solar energy and the diversity they add to generation sources.

The Rethinking Load Growth report makes clear that the best path forward is a more flexible, adaptive grid—not a rigid one. Instead of fixating on the predictability of individual power sources, we should focus on the predictability of the system as a whole—and that means integrating smart, real-time demand-side management alongside renewable energy.

A Smarter Way to Keep the Lights On

One of the report’s key findings is that ISO-New England (ISO-NE) and other grid operators already have significant headroom to integrate new large loads without requiring massive new investments in power plants or transmission lines. The study estimates that over 100 GW of flexible load could be integrated nationally with only minimal curtailment of operations.

This is a game-changer for reliability. Instead of assuming that the grid must always meet demand instantaneously with generation, a flexibility-first approach allows demand to adjust in response to grid conditions. AI-driven data centers, intelligent HVAC systems, and automated industrial processes can ramp up or down in real time, smoothing variability without requiring new fossil fuel infrastructure.

For New England, where winter peak demand is driven by heating loads and constrained natural gas supply, this flexibility could mean the difference between stability and blackouts. Instead of burning more fossil fuels, grid operators could shift demand dynamically—pre-heating buildings when renewable supply is abundant, temporarily reducing non-essential loads during peak hours, or leveraging stored energy from electric vehicle fleets.

Smart Grids and Distributed Resources: A Reliable Future

Beyond flexible loads, smart grid technologies and distributed energy resources (DERs) further redefine reliability. Microgrids, battery storage, rooftop solar, and virtual power plants (VPPs) allow for localized energy balancing, reducing dependence on centralized fossil fuel plants.

For example, instead of relying on peaker plants to handle extreme winter cold, ISO-NE could integrate neighborhood-level microgrids powered by a combination of distributed solar, storage, and demand response. When centralized plants are under strain, these localized systems can continue operating—enhancing resilience at a fraction of the cost of new power plants.

Moreover, real-time grid monitoring, AI-driven forecasting, and automated control systems can now predict and respond precisely to fluctuations, which was unthinkable in the old “baseload-first” model. Instead of designing a system that assumes worst-case demand scenarios, we can create one that dynamically adapts to reality.

The Future of the Grid: Smart, Not Rigid

Like other regional grid operators, ISO-New England is beginning to embrace this new paradigm to ensure long-term reliability. That means continuing to:

· Expand demand flexibility programs to reduce peak load strain.

· Modernize how it ensures power plants are available when necessary.

· Invest in real-time grid intelligence to better integrate renewables and flexible loads.

· Facilitate growth of distributed energy resources to enhance local resilience.

It’s time to abandon the hierarchical, generation-first view of reliability that has dominated grid planning for over a century. Grid reliability is no longer about keeping big power plants running 24/7—it’s about using energy in smarter ways. With the right policies, New England and its electric utilities can embrace a clean, flexible, cost-effective energy system that works for the 21st century. We now have the technology, data, and tools to orchestrate a cleaner, cheaper, and more reliable grid than the legacy fossil-based system.

It’s time to leave outdated ideas behind and build a resilient, adaptable system that is ready for anything. The answer is clear: reliability is no longer about baseload but real-time adaptability.

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Nuclear Energy Revival Unlikely, Especially in Maine

As reported in a recent article in the Portland Press Herald (“Nuclear power is making a comeback in the U.S. But not in Maine.” 12/1/2024), over the last few months, the media has been abuzz with reports about restarting old nuclear reactors and a growing interest among tech investors in “small modular reactors” (SMRs). While the public might interpret this as a general trend toward nuclear power, restarting older nuclear plants, like Three Mile Island Unit 1, is an entirely different venture from the ambitious efforts of startups attempting to commercialize SMR technologies. And none are viable options for Maine for the next decade, if ever.

Let’s first deal with the restart of old reactors. Most of the operating nuclear plants in the US entered service with costs that far exceeded initial estimates and required substantial upgrade investments to remain operational. Electricity customers were often saddled with these expenses, sometimes even paying for plants long after their owners took them out of service. Just last year, the only new nuclear plant to be commissioned in four decades came online with costs five to ten times higher than acceptable alternatives, a burden that Georgia ratepayers will carry for decades.

Those plants that might be restarted were taken offline because they became too expensive to compete with cheaper alternatives in their respective markets. Their owners have found single customers willing to pay a premium for their electricity, eliminating their need to compete in the marketplace. While avoiding market risk, the plant owners still face the potential of expensive component replacements in the future. Fortunately, plant owners and their contracted electricity purchasers will bear the risk, not utility ratepayers.

SMRs fall into two broad categories: those based on “light water reactor” designs similar to current nuclear plants and those in the “exotic” category, which include molten salt coolants, fuels that contain more fissile isotopes and require higher energy neutron radiation fields. The financial risks of SMRs, borne entirely by private investors, mirror those of most emerging technologies: challenges in securing ongoing investment, failure to complete federal licensing, uneconomic designs, delayed timelines, and, in some cases, products that ultimately fail to perform as needed for competitive market entry.

The Nuclear Regulatory Commission (NRC) website tracks SMR project licensing, offering details on where these companies stand in the licensing process. In the light water SMR category, only one of the four light water developers, NuScale, achieved design certification last year after a 14-year effort. Immediately after certification, The others are far behind, Shortly after getting its design certification, NuScale announced that their projected costs would be far higher than anticipated, making them uneconomic in most markets, and that they were unlikely to deliver units when promised. NuScale’s stock plummeted and earlier this year they laid off a quarter of their staff and shifted its focus to Romania. Assuming NuScale stays afloat, a US operating license for its first product is still at least a decade away. Among the exotic SMR designs, three companies have applied for test reactor construction permits. Test reactors are important, but still very early in the path to an actual licensed economic product. Since the 1950s, about 20 fast reactor test units have operated, but none proved economical. The current administration in Washington has vowed to eliminate IRA subsidies, which potentially make or break whether or not these new technologies will be economic.

As with the older reactors, the financial risks of SMR development, regardless of the technology, fall entirely on the investors rather than on ratepayers. For SMR developers, the most pressing risk is the potential loss of investor backing before reaching viability. The nuclear industry and at least one political lobbying organization have been conducting a public relations campaign to promote the notion that SMRs are on the brink of success, offering low-cost energy solutions. There are two agendas for this message. First, giving the illusion of near-term viability buoys wary investors worried they would never see a payout. The other agenda is that by making SMRs seem imminent, less attention would be paid to clean technologies, thereby enhancing the continued use of fossil fuels.

So what about Maine? Restarting old reactors is out of the question for Maine. For SMRs in the future, three requirements will have to be met. First, an economically competitive and licensed SMR product needs to be available. NuScale is the front-runner, provided it overcomes its financial woes. Still, it is at least a decade away from such a product. The others, including the fast reactor variants, are way behind. The second requirement would be for a non-utility owner-operator to step forward since Maine electric utilities are not allowed to own power plants. Every new commercial nuclear plant built in the US has been utility-owned because they are uniquely positioned to manage the significant financial risk of delay and costs. Finally, since 1985, the construction of any new nuclear reactors in Maine must be approved by a public referendum (Title 35-A §4302).

The recent wave of nuclear promotion, whether restarting old plants or investing in SMR R&D—reflects a renewed push to reframe nuclear as part of a sustainable energy future. However, each path carries distinct risks and benefits. The high operational costs of restarting existing plants are only justifiable if long-term contracts pay them a premium. For SMRs, substantial investment risks fall on private investors hoping for breakthroughs in cost and technology. Both approaches require caution, transparency, and realistic expectations. While nuclear energy may offer potential benefits in terms of clean energy, its viability in the future energy mix depends entirely on whether the financial and operational challenges of each of its various technologies can be overcome. Commercial nuclear power will, therefore, not be part of Maine’s electricity future, and counting on its contribution runs the risk of delaying or deferring affordable and available actions.

Finally, you might note that this is all about commercial viability, economics and market decisions. The collapse of the industry in the US, as well as any future it might have are due to those factors and had little to do with public risk perception, waste disposal or environmental concerns.

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No, Solar Is Not Raising Your Electricity Bill

(This post was updated in February 2025 to include more recent data.)

Surely, you’ve seen memes or heard claims that all the new solar installations in Maine are why our electricity costs are so high. Those who make these irresponsible claims—including some public officials—either don’t understand how our energy system works or don’t care. But here’s the truth—the opposite is true. 

First, let’s talk about your electric bill. 

Here is my latest one from CMP.

Two important lines are “CMP Delivery” and “Non-CMP Supplier Standard Offer.”

Despite this labeling, many people don’t realize that CMP does not sell electricity—it only delivers it. They are allowed to charge “CMP Delivery” for that service. 

Suppose you are one of the 90% of customers that are supplied by the “Standard Offer.” In that case, the other line on your bill is the cost of electricity bought by the Maine Public Utility Commission from the New England wholesale market. They buy it once a year, usually in November, which fixes the following year’s price.

Over half of that wholesale market comes from power plants burning natural gas, which has a significant influence.

In fact, if you track the ups and downs of gas prices with electricity prices over the last 6 years, they match.

Now, let’s put all the pieces together and look at the total bill. The red parts of the bar are CMP costs. Green is the Standard Offer Supply, and blue is a charge from the regional grid to get electricity into Maine. We’ll talk about the little orange piece in 2023, 2024 and 2025, which is the cost of solar, later.

So what can we do about this? It’s easy to see that supply is the real culprit since 2021, going up 57% since 2021 and delivery going up 44%. In 2025, these two costs are 75% of your bill.

The best way to reduce supply cost is to use less power generated from natural gas. Every new kilowatt hour from cheaper sources like solar or imported power from Quebec replaces a kilowatt hour produced from natural gas. Without these new sources replacing gas, our bills would be much higher. 

The next biggest change is the red bar, the cost of delivering power. The more we make the operation of that grid more efficient, the lower this cost will become.

Now, to the myth- and it is a myth – that new solar panels in Maine are increasing electric bills.

Non-rooftop solar projects are indeed paid extra, and those costs are built into your bill. Those costs are the little orange slice of the chart above, not quite 7% this year. 

But your bill doesn’t tell you about the benefits of solar that keep costs down. 

First, solar energy removes expensive natural gas, which, as we saw, directly affects the standard offer price. 

Second, the old-fashioned way to meet new grid demand was to install more poles and wires – and their costs are in your bill. Putting new solar panels near where customers need power avoids some of that expense.

Then there’s the environmental benefits. In addition to keeping costs low, solar energy reduces our reliance on fossil fuels, lowers pollution, and helps us meet our climate goals.

Other benefits that translate to cost savings as well involve increased reliability and additional revenue obtainable in the wholesale power market. The Public Utility Commission recently added these savings up and concluded that for every dollar of solar included in your bill, you saved about a dollar and 40 cents.

The Public Utility Commission recently added these savings up and concluded that for every dollar of unrecovered costs, there was a savings of about a dollar and 40 cents. See this chart:

So the next time someone tries to tell you that solar energy is raising electricity costs, tell them to do their homework!

This is not to day NEB costs are not important- they are – but we should be focusing on other parts of the bill first. There is an issue with Net Energy Billing that merits discussion immediately- how those costs are allocated to customers. At present, non-residential accounts are being charged in a deeply inequitable way. The PUC is currently examining that method in an ongoing proceeding and will hopefully fix this problem.

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Buidling Maine’s 21st Century Electricity Network

Last legislative session, I introduced a bill instructing the Governor’s Energy Office to assess whether modernizing Maine’s electricity grids by creating a statewide Distribution System Operator (DSO) could decrease electricity costs and enhance reliability. That study began earlier this year. The study’s first phase will determine whether a DSO would reduce costs, enhance reliability, and accommodate decarbonization goals. If these objectives seem attainable, the study’s second phase would outline the system’s design and recommend a roadmap for implementation. The first phase report is due in September.

So why is this important?

Our current grid, largely unchanged for a century, operates as a one-way power delivery system using outdated technology. Modern technology and operating systems, many of which are already installed but underutilized, can transform our local grid into a multidirectional network. In the future, we anticipate a significant increase in distributed energy resources, including generators, microgrids, vehicle-to-grid systems, and stationary storage. As the central grid planner, the Maine DSO could manage the deployment of these distributed energy forms efficiently and operate the market in which they bid and function.

The proposed DSO would:

  • Manage and control our distribution grids as a unified system without owning them,
  • Consolidate grid infrastructure planning currently scattered among multiple utilities and state agencies,
  • Facilitate an open market in distributed generation.

Maine has only recently embarked on integrated system planning, currently overseen by various utilities and state agencies. Centralizing control, operations, and infrastructure planning with the DSO would ensure efficient and transparent statewide planning and implementation for the grid’s resilience, reliability, and new generation interconnectivity. Optimized grid operations could reduce both supply and delivery costs.

To meet its climate goals and ensure cost-effective, reliable distribution grids, Maine needs a shift in perspective on how its electricity delivery system operates, is controlled, and regulated. The technologies to establish a multidirectional, interactive, transactional grid are readily available. What is required now is a robust plan, determination to implement it, and readiness to become a leader in grid modernization.

The ongoing study was featured in a recent Portland Press Herald article on July 8: “Maine to study whether creating local electric grid operator could cut costs, improve reliability” .

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Seeing the Whole Picture: Costs and Benefits of Solar

Yesterday the Portland Press reported on the approval of a rate increase by CMP that included recovery of “subsidies” for solar amounting to an additional cost fo $5/month for the average customer.. I was quoted in the article. While no one likes increasing costs for electricity, focusing only on this cost number alone is like looking at Picasso’s 11 by 25 foot painting Guernica through a small tube. What you see is only a small part of the overall picture. That’s because there are significant, but not well understood, benefits to ratepayers that are far larger and offset these costs.

This cost of solar is real and comes from the fact that when Maine began encouraging local community projects and rooftop installations, an advantageous rate was offered. In fact most small local power markets began exactly this way, and Maine was no different. We passed a bill last year recognized that the advantageous tariff was no longer needed to spur the market and adjusted Maine’s program, closing it after this year. But that is just the cost side of the equation.

The benefits of distributed generation includes the commodity value of the electricity it produces and the value of its different attributes which it provides to the distribution grid. This is not a theoretical concept but is employed in other states. Our problem is that there is no way to show those cost savings on everyone’s bill, so they are unknown and all ratepayers see is the added cost. But these benefits are quite real and include:

· Reducing the cost of wholesale power. Every bit of energy produced by solar projects offsets power that would have otherwise been produced by expensive natural gas power plants. This impact can be seen in real time. If you go to https://www.iso-ne.com/isoexpress/web/charts, look at the upper left chart and click on the yellow orange square, you will see (this is yesterday’s chart). The top line is what electricity use would have been without solar. The blue line is what it really was. That gap, without solar, would have been filled with expensive power from natural gas fired plants,

· Reducing payments for power capacity. Our power grid pays certain power plants to guarantee they be available when called upon, and those payments are passed on through our power costs. Solar (and wind) reduce the number of these plants needed and lowers that cost.

· Reducing infrastructure costs. Utilities invest in poles and wires to meet the highest demand for power anticipated. Local solar power reduces that demand, and that translates to lower investments. Substations and other facilities need to be maintained. Lower peak demand reduces their need for service. By promoting local power sources, NEB helps to create a more robust and flexible grid, better equipped to handle disruptions and extreme weather events. This is particularly important for Maine’s rural communities, where access to reliable energy is essential for economic and social well-being.

· Environmental benefits. Since these local renewable sources of power offset fossil power, emissions of pollutants as well as greenhouse gases are reduced. By promoting clean, renewable energy sources like solar, NEB contributes to a healthier environment for current and future generations. The report quantifies these benefits, estimating that NEB led to a reduction of over 600,000 tons of CO2 emissions in 2023, equivalent to taking over 130,000 cars off the road.

The bill that ends this program at the end of 2024 also required the PUC to do a cost benefit analysis of NEB. Last April the study was completed and the findings were clear: NEB has yielded considerable financial benefits. For instance, in 2023, the program cost $130.76 million but its benefits amounted to $160.33 million. These are not merely abstract numbers but translate directly into cost savings for Maine’s ratepayers. This study shows that every dollar of solar “subsidy” generates a benefit of $1.25.

This is not to say that NEB is perfect. Over time we need to move to a system where energy costs reflect their true value. In the case of electricity, that amount varies significantly by location and the time it was produced. We have a long way to go to transition our existing regulatory structure to one that reflects reality. And, in fact the PUC report acknowledges the challenges associated with NEB, including the need to ensure equitable access for all Mainers. But these challenges are not insurmountable. Expanding community solar projects, exploring innovative financing models, and investing in grid modernization can address concerns about equity and grid resilience.

Most importantly, we need to reform our regulatory structure in a way that recognizes both the costs and benefits of local generation, allowing us to see the whole picture.

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Maine can incentivize CMP, Versant to do the right thing

(Text of op-ed published 11/20/2023 Portland Press Herald by me; Kay Aiken, CEO Of Dynamic Grid; and Rebecca Schultz of Natural Resources Council of Maine https://www.pressherald.com/2023/11/20/commentary-maine-can-incentivize-cmp-versant-to-do-the-right-thing/)

Now that voters have spoken on the Pine Tree Power referendum, it is time for us to come together, roll up our sleeves, and get to work making Maine a leader in clean energy and innovation in the power sector.

We deserve a 21st-century grid to meet our goals outlined in Maine’s ambitious climate action plan “Maine Won’t Wait” and a future of a decarbonized, decentralized, and democratized electrical grid that works for everyone.

The keystone of this plan is the electrification of building heating and transportation. In a recent address, Gov. Mills accelerated the urgency of achieving this vision by setting a goal of 100% clean electricity in the state by 2040.

Adding clean energy sources from large scale down to residential and electrifying heating and transportation demands a radical transformation of our electricity delivery system in both its engineering and regulation. Our electricity grid must evolve from a one-way delivery system to a multi-directional network optimized for efficiency, balancing supply and demand, and, most important, providing value to consumers.

The investor-owned utilities, Central Maine Power and Versant, will continue to own and maintain Maine’s electric grid, but there are crucial regulatory reforms that can help create the right incentive structures to motivate the investments, planning and operations that we need from these companies.

The challenge of redesigning such an advanced electrical system is considerable. Still, the urgency of climate change and the economic benefits of a clean energy economy necessitate swift and decisive action.

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A full expression of how that redesign might look goes beyond what can be covered in this op-ed; what we discuss here is the regulatory framework in which it should operate. The campaign to take over the utilities happened for a reason: Customers were and continue to be deeply unhappy with the cost and performance of their utilities. But we sometimes forget that our regulatory structure is our means of local control; our immediate priority is to underscore the need to fully exercise that control through regulatory reforms that address these ratepayer concerns.

Over the last 100 years, utility regulation was designed to ensure monopoly providers, regardless of ownership, achieve established goals. These rules successfully encouraged the buildout of electric utility infrastructure. The past is not a template for our future.

Deregulation, which began in the late 1980s, introduced competition in the retail and wholesale electricity markets, leading to customer service and reliability declines. In response, states started implementing performance-based ratemaking (PBR) to address these issues. Early PBR efforts sometimes missed the mark due to utility exploitation of weak incentives. However, lessons learned have led to more effective PBR adoption. At least 18 states have already implemented PBR.

Maine took an initial step toward PBR in 2022, creating a utility scorecard to enforce standards in reliability, customer service and billing accuracy, with penalties for non-compliance. The Maine Public Utilities Commission has spent a year developing a system to measure performance which only recently has begun influencing rate cases. An upcoming legislative session will consider bills to enhance the scorecard by requiring the commission to assess performance annually and issue incentives or penalties based on performance relative to established goals. New standards should include metrics related to:

• Effectiveness of infrastructure investments and regulation supporting new local power sources and electrification

• State of grid resiliency against extreme weather events

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• Customer accessibility to affordable electricity

• Speed and efficiency in connecting new local power sources

• Measures taken to encourage shifting the use of electricity to times when it is most abundant and at the lowest cost

• Quality of utility strategic long-range planning

As Maine forges ahead in the design of its future electricity grid, regulatory reform is a critical tool to address ratepayer dissatisfaction. Enhanced PBR can help us shape a utility sector that actively drives our climate goals forward while keeping costs as low as possible. PBR isn’t just regulatory reform; it’s a new commitment to our environment, our economy and the well-being of every Mainer.

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SMOKE, MIRRORS AND MAINE REFERENDUM QUESTION 3

Proponents of Pine Tree Power make some big promises if the referendum passes. Unfortunately, many voters do not have the expertise to distinguish between genuine facts and the misleading assertions behind these promises. Frustrated by unsatisfactory utility performance and costs, some might easily be swayed by seemingly compelling yet baseless arguments. So, let’s test the accuracy of the two central claims made by Pine Tree Power proponents.

Claim 1: Since some consumer-owned utilities (COUs), on average, have better reliability and lower costs than investor-owned utilities (IOUs), changing the ownership of Maine’s IOUs into a COU will result in improved performance.

This claim makes a false equivalence. Pine Tree proponents cite data from over 2,000 primarily small urban municipal utilities. They conspicuously exclude data from rural cooperatives that more closely match our current utilities and their reliability. The Frankenstein of Pine Tree Power, where two IOUs with 21,000 square miles of largely rural territories serving 800,000 customers would be combined, stands in stark contrast to existing COUs. Unlike these urban COUs, which built their own infrastructure, Pine Tree would integrate systems developed and overseen by two different IOUs. Additionally, Pine Tree begins operation with the onus of a massive mortgage of tens of billions and the extra expense of hiring a third-party manager. It would keep the existing union and workforce, implying no labor cost savings. It would forego its exemptions from property taxes.

“Apples and oranges” doesn’t begin to capture the disparities in this comparison.

However, the one legitimate comparison with a COU that can be made is with the Long Island Power Authority (LIPA). LIPA is the sole COU formed by a complete private utility takeover and mirrors Pine Tree’s characteristics. LIPA customers must repay a massive mortgage and pay a third-party company for operations. And LIPA’s performance? After the 13 years it took to create, followed by 24 years of operation, it boasts the nation’s highest commercial rates and highest residential rates in NY and NJ. A recent JD Powers survey ranked LIPA similarly to CMP. Currently, it’s deliberating the replacement of its third third-party operator. Due to persistent customer dissatisfaction, the NY State Legislature twice initiated evaluations for improvement. The Long Island Chamber of Commerce proposed LIPA revert to a private utility only last year. With public hearings in progress, LIPA’s fate remains uncertain. Regrettably, Long Island customers have had miserable service and high rates for 37 years.

Claim 2: Pine Tree will save customers $367 annually for 30 years, starting immediately.

This is the most egregious of Pine Tree’s claims. The source of this savings is based on using 4-year-old assumptions in a computer simulator – assumptions both woefully out of date and found to be deeply flawed by experts – which concluded that the total savings would be $9 billion ($367 per customer per year, beginning in January 2024).

The fact is that Pine Tree proponents have never done a current, peer-reviewed comparative analysis, one that addresses the uncertainties in such an analysis, to support any savings claims.

So, where did the $367 “savings” come from? Four years ago, the Legislature hired a consulting firm to evaluate whether there would be savings from a takeover. Their analysis concluded that a takeover would result in added costs to ratepayers during the first ten years of operation with eventual savings later. However, they stressed significant uncertainties in such a forecast, and a wide range of outcomes were possible. Pine Tree proponents took the consulting firm’s 4-year-old forecasting model, manipulated it with favorable assumptions (subsequently determined to be deeply flawed by other experts), ignored uncertainty analysis, and declared ratepayers would cumulatively save $9 billion over three decades, or $367 annually per customer. The consultant’s forecasting model used by Pine Tree proponents assumed a future that bears no resemblance to what we see today.

A credible analysis would consider variable start dates for the Pine Tree takeover, potential buyout prices, ranges of possible costs for a management company, fluctuating interest rates, and differing economic parameters likely over 30 years. A credible analysis would present a range of outcomes expressed as probabilities. You don’t need a Ph.D. in economics to understand that it is pure nonsense that an analysis with these uncertainties would result in the forecast of any single number. An organization that wants to take over a complex system like an electric utility should know this.

A competent assessment of the cost implications of a takeover, accounting for the uncertainties, would conclude that the most probable outcome is a wide range of added costs, not savings, to ratepayers that range in the billions.

Whether Pine Tree’s baseless arguments are deeply misinformed or deliberate misinformation does not matter. Voters must ask themselves: “Could I trust any group that would make such arguments to run my electric utility?”

While it’s undeniable that our utilities need to be better, the solution isn’t Pine Tree Power. Pine Tree Power might be emotionally satisfying in the near term but will likely make matters far worse. Maine only recently enacted reforms to address performance, with more to come. A “no” vote allows these reforms to take effect and avoids the disaster ensuing if this referendum passes.

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‘NO’ TO PINE TREE POWER DOES NOT MEAN KEEP THE STATUS QUO

The following was published in the Portland Press Herald on September 22, 2023

The ads flooding the airwaves about the November referendum on Pine Tree Power Company make it sound like there are two choices: vote “yes” to takeover CMP and Versant and form Pine Tree, or vote “no” and keep the status quo. Proponents claim that replacing CMP and Versant with Pine Tree will result in lower rates and higher reliability. Opponents of the referendum say that maintaining the status quo is the low-cost option for ratepayers in the future. Neither argument squares with reality. The process to set up Pine Tree represents an existential threat to the achievement of Maine’s climate and grid modernization goals. If it operates, ratepayers will be worse off than now. But a “no” vote is not choosing to keep the status quo. A “no” vote allows very recent utility regulatory reforms to take effect and permits the Legislature to strengthen those reforms in the future– reforms that will correct the poor cost, reliability, and customer service Mainers have been enduring for years. 

Mainer’s dissatisfaction with utility performance is warranted. What Mainers don’t realize is that poor performance is primarily the result of inadequate and anachronistic regulation. Thirteen other states use performance-based ratemaking (PBR), where what utilities earn depends on their performance. Maine only implemented a version of PBR last year – it is a critical first step that the Legislature should further strengthen over time. But it will take time to see the results. Unfortunately, Pine Tree advocates opposed implementing PBR. They blocked a bill I introduced to strengthen the existing law in this session. Frankly, had some members of the Legislature worked on regulatory reforms rather than a utility takeover over the last five years, we’d all have been better off.

Many of our climate action goals necessarily involve our electric utilities. If the referendum passes, the State faces years of uncertainty regarding who is in charge, putting climate and grid initiatives on hold until Pine Tree is fully operational or fails to be established, which could take years, if not a decade, to determine. The takeover of an entire private utility to form a public one only happened once: Long Island Power Authority took 13 years to complete. Many small municipalities have tried to carve themselves out of their current utility- the latest example, Boulder, Colorado, gave up after ten years.

Uncertainty would also delay grid modernization. Last session, we passed a bill to change how our electricity grid is planned and controlled, optimizing its operation for the least cost and highest efficiency. This future grid will encourage local power generation, offering enhanced control over electricity consumption and flow. However, designing this integrated system is complex. It cannot be done until all the uncertainties of Pine Tree are resolved.

And it’s not worth the wait. Claims that Pine Tree would reduce costs and reliability are pure conjecture. If one were to create an electric utility from scratch, the data on public utility costs and performance clearly suggest that a public ownership model would be ideal. But the takeover and then combination of two different utilities with three different service territories, one of which is not even connected to the New England grid, keep the union intact, continue to pay property taxes, pay an outside company – likely a utility – to run the company and pay an enormous sum to acquire them is a totally different set of circumstances. As an example, Long Island Power Authority, now in its 24th year of operation, was rated just behind CMP in the most recent JD Powers customer satisfaction survey. Pine Tree would begin its operation with a mortgage costing tens of millions. This mortgage will need to be recovered from ratepayers in addition to its operational costs. The reality is that any reasonable analysis of the cost impact of a takeover – one that considers the uncertainties in a 30 or 40-year future look – is additional ratepayer costs that range in the billions.

Passing the referendum might be emotionally satisfying in the short term; however, it would also undermine Maine’s climate and grid objectives for years. And if Pine Tree Power became operational, we would be worse off than we are now. I urge voters to reject the referendum, give regulation time to work, and let your legislators know you are counting on them to continue to modernize our grid and reform the ways utilities are regulated.

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The future of solar energy in Maine hinges on passing LD 1986

(Op-Ed published in Bangor Dail News, 7/4/23)

The future of solar energy in Maine and our state’s climate goals could be at risk, depending on which of two bills is potentially enacted by the Legislature this week: LD 1347 or LD 1986. Both bills aim to address the way solar projects are compensated for the electricity they generate, but only LD 1986 will actually support solar development and our state’s clean energy goals.

Currently, solar projects are paid the retail rate for power, which is higher than its market value. This cost difference needs to be recovered. Both bills recognize that the current method overpays for solar power compared with its actual value. It is crucial to change this system so that we only pay for the true value of solar energy.

LD 1347 has been largely drafted to protect a few industrial interests, but would have a direct impact on tens of thousands of customers with rooftop solar and participants in community solar. If enacted, this bill could significantly hinder the future growth of individual and community solar projects throughout Maine. Last week, the Biden administration announced a $7 billion grant program to promote local solar, and LD 1347 would create barriers for individual Mainers and Maine companies to compete for these funds. It would also make several categories of potential projects ineligible.

On the other hand, LD 1986 has been developed in close coordination with the Governor’s Energy Office and is supported by some ratepayers and solar providers. It also aims to end the current method of compensation, however, it does not jeopardize existing projects. Instead, it proposes a correction in how new projects are paid, aligning them with a value established by the Public Utilities Commission, similar to the approach used in other states.

The payment method used for solar developers and homeowners is called net energy billing, which is quite complex. It involves determining the true value of solar power, understanding how it interacts with the distribution grid system and recognizing its impact on customer bills.

Unfortunately, there has been a lot of misinformation going around about this policy, including an attempt to lobby on behalf of LD 1347 in the court of public opinion. For example, many people have been falsely told that the high cost of electricity is due primarily to net energy billing. In reality, solar power has actually reduced the need to purchase expensive natural gas power, potentially lowering the standard offer price. Many have also argued that LD 1347 would reduce rates while LD 1986 does not. In truth, both bills aim to reduce costs, but they employ different approaches.

Additionally, there have been incorrect assurances that LD 1347 would have no commercial consequences. However, many companies have made it clear that existing projects might not continue if this legislation is enacted, and several ongoing projects could be terminated.

And finally, many have been misguided by the notion that only large grid-scale solar projects are necessary. While grid-scale solar is indeed crucial, it alone cannot meet the demands of electrifying our grid. We require substantial amounts of both grid-scale and locally generated solar power, and LD 1347 could be detrimental to locally generated projects.

Mainers should take pride in our leadership on climate issues and our forward-looking Climate Action Plan. LD 1986 fully supports these goals and ensures continued progress. On the other hand, I believe LD 1347 is contrary to our state’s aspirations in achieving these climate goals and deserves a “no” vote in both chambers of the Legislature when it comes up for a vote. Please contact your state representative and senator and urge them to defeat LD 1347 and pass LD 1986.

The future of solar energy in Maine depends on it.

Gerry Runte

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Nuclear power won’t help Maine reach its clean-energy goals

(Published in Portland Press Herald on May 24, 2023)

In Maine and in state legislatures across the nation, the nuclear industry lobby is promoting a renewed call for investments in nuclear technology as a source of clean energy. In the Maine Legislature, there have been three bills this session – L.D. 486, L.D. 689 and L.D. 1549 – that would promote nuclear power plants in our state.

While it’s important that Maine pursues solutions to provide affordable, clean energy, nuclear power isn’t the answer – and likely never will be.

Since launching my career in the energy industry in 1975, I have repeatedly witnessed campaigns heralding the pending emergence of nuclear power. In the mid-’70s, there was a promise that 1,000 reactors would be up and running by 2000, producing power “too cheap to meter.” As recently as a decade ago, the U.S. was reportedly again on the cusp of a nuclear renaissance. But this renaissance and other, earlier predictions never materialized. In this latest campaign, the spotlight is on small modular reactor technology.

However, there is no market for commercial nuclear power plants in this country, and there has not been one for 30 years, if ever. Only one new nuclear site, Plant Vogtle in Georgia, has been built on American soil since the mid-1980s. Public apprehension, concerns over nuclear waste and the environmental movement are often cited as reasons that nuclear energy hasn’t lived up to expectations. But none of these issues has been the real roadblock to the construction of nuclear plants – it has just been plain old economics.

Commercial nuclear power is a business, and like all businesses, it requires a market-competitive, customer-appealing product. The hard truth is that when a product isn’t financially viable and there are more cost-effective alternatives available, market demand evaporates. Nuclear power has failed in the competitive market of electricity generation, where there are less complex, more affordable choices.

Vogtle is expected to start operations this year, six years behind schedule. Its total cost is at least $35 billion, more than double the original projections. And its electricity will cost several times more than its most expensive alternative. Vogtle is by no means unique in this regard; similar plants in France and Finland that have started operations in the last few months have experienced the same exorbitant costs and late delivery. Vogtle is just the most recent example of nuclear technology consistently falling short of lofty expectations.

Will small modular reactors change this narrative? No matter the kind of nuclear plant, all units require an operating license from the U.S. Nuclear Regulatory Commission, a grueling process that can span decades. To date, only three developers of small modular nuclear technology have initiated an application with the NRC. The one company making the most progress, NuScale, started its application in 2009, yet it is still roughly a decade from completion. Earlier this year, NuScale declared delivery setbacks and a doubling of projected costs that may already be uncompetitive. It seems inevitable that their costs will continue to climb and delays will stretch further – a familiar refrain.

A few experimental, small, liquid sodium-cooled fast breeder reactors are also being promoted. Despite research into this technology dating back to the early 1950s, commercial success has yet to be achieved. These “fast” reactors are even further away from becoming commercially viable than the three that have already filed applications with the NRC.

Maine will undoubtedly need more clean and affordable electricity sources as we head into the future, and there are a variety of technologies that should be considered as we build our portfolio. Those options include technologies that are nearing commercialization and offer credible delivery and affordable electricity without the baggage of nuclear power.

It’s important that the state not be swayed by this most recent campaign promising cheap nuclear electricity just over the horizon. It was just over the horizon 50 years ago, and will remain just over the horizon 50 years from today.

From Commentary in the Portland Press Herald, May 24, 2023