Month: May 2026

Tom Steyer has made electricity bills the centerpiece of his California governor campaign, promising to cut household rates 25 percent by taking on investor-owned utility monopolies. With Maine’s own rates climbing, the comparison is tempting. It doesn’t hold up. The reasons why reveal what Maine actually needs to do instead.

California has the second-highest electricity bills in the continental U.S. Maine is not far behind. The Standard Offer supply rate rose about 20 percent for 2026. CMP asked the PUC to approve roughly $35 more per month over five years — the PUC ultimately dismissed the proposal. People are frustrated, and for good reason.

Some of Steyer’s ideas would work in Maine. Some are already in place. Others are designed for a state with fundamentally different plumbing.

What does Tom Steyer’s plan to cut California electricity rates actually include?

Tom Steyer’s California electricity rate plan has seven main elements: cutting utility return on equity from roughly 10 percent to 8 percent; shifting from spending-based to performance-based utility compensation; using existing grid capacity more efficiently through technologies like dynamic line ratings and advanced reconductoring; financing transmission through public bonds rather than utility equity; enforcing interconnection deadlines; making data centers pay their own grid costs; and expanding community choice aggregation so customers can buy power from someone other than the local utility.

Strip away the campaign framing and the plan rests on a handful of moves. He’d cut utility ROEs about two percentage points, from roughly 10 percent to 8. He’d shift California from a system that pays utilities for spending money to one that pays them for results. He’d push utilities to get more out of the grid we already have — dynamic line ratings, advanced reconductoring — rather than building expensive new lines. He’d use public bonds rather than utility equity to finance some transmission projects, lowering the cost of capital. He’d require utilities to meet interconnection deadlines for new clean energy projects. He’d make data centers pay their own way rather than pushing costs onto households. And he’d expand community choice by letting customers buy power from somewhere other than the local utility.

Most of that diagnosis is correct. Monopoly utilities have perverse incentives to overspend on capital projects, and regulators haven’t pushed back hard enough. A few of those tools carry over to Maine cleanly: performance-based regulation, getting more out of existing wires, making large new loads pay their own way. The 25 percent headline doesn’t survive contact with the math.

Why won’t Steyer’s California utility reforms lower Maine bills the same way?

Steyer’s plan targets problems Maine has already partly solved or doesn’t have. Maine separated generation from wires in 1997 — the structural reform at the center of his proposal. Maine’s utilities are earning well below their authorized returns today, so an ROE cap would change nothing. And the largest cost drivers on a Maine electricity bill — wholesale energy prices, FERC-regulated transmission, and storm cost recovery — are not utility-monopoly-profit problems at all. None are touched by Steyer’s plan.

Three structural differences explain why.

Maine already deregulated supply. In 1997, the Legislature required CMP and Versant to sell off their generating plants. Our utilities are wires-only; generation is bought through the competitive ISO New England market. California’s three big utilities still own and contract for generation directly. The structural reform at the center of Steyer’s plan is something Maine completed nearly thirty years ago. The savings that were supposed to follow never fully materialized, and consumers here remain heavily exposed to wholesale-market volatility.

The ROE math runs the wrong way here. Steyer’s California utilities earn above 10 percent on equity, and his plan would push that to roughly 8 — a real two-point cut. Maine’s utilities have an authorized ROE just above 9 percent but are currently earning under 6. They’re running more than three points below their cap already. A statutory ceiling on a number Maine utilities aren’t reaching saves nothing today. Capital markets also price aggressive ROE caps as regulatory risk, which flows back into the cost of debt and outlasts whatever political point the cap was meant to make. And even setting that aside, distribution profit is under 4 percent of a typical Maine bill. An effective cut saves a household a couple of dollars a month, not a couple hundred a year.

The biggest cost drivers sit outside state utility regulation entirely. Standard Offer supply is shaped by natural gas prices and the wholesale market. Transmission costs are regulated at FERC and allocated regionally. Storm cost recovery now adds about $20 a month to the average bill. Public policy charges, including net energy billing, exist because the Legislature put them there. None of these are utility-monopoly-profit problems.

What should Maine’s electricity affordability program actually do?

Maine’s electricity affordability problem requires five separate reforms, ordered roughly by where the dollars are. The biggest lever is Standard Offer procurement reform, followed by binding grid planning with real performance consequences, cost-causation rules for large new loads, serious engagement at the FERC and ISO-NE level where transmission costs are set, and a new approach to storm cost recovery that stops burying one-time expenses in the rate base for decades. Together, these can hold bills steady and bend them down over time.

An honest affordability program for this state doesn’t have a single villain. It has a set of cost drivers, each with its own fix. Much of the real value isn’t immediate rate reduction — it’s avoiding locking another generation of unnecessary infrastructure and financing costs into the system. What follows is the work, ordered by impact.

How should Maine reform Standard Offer electricity procurement to stabilize bills?

Maine’s Standard Offer supply contracts are short-term and closely indexed to natural gas, which means every cold winter or pipeline disruption flows directly onto household bills. Longer contract structures, more diverse fuel exposure, and disciplined hedging would do more to stabilize residential rates than any change to CMP’s authorized return. This requires the PUC, the Public Advocate, and the Legislature to treat procurement design as seriously as they treat rate cases.

This is the single largest near-term lever, and it doesn’t require breaking up a monopoly. It requires taking procurement design seriously — the kind of detailed, unglamorous work that doesn’t show up in campaign ads but changes what people actually pay.

How can Maine make grid planning binding with real performance consequences?

Maine’s Integrated Grid Planning process is supposed to identify what the grid needs before utilities build anything, but today it’s largely advisory. A utility can walk into a rate case asking for a capital project even when the IGP recommended a non-wires alternative. The fix is structural: require IGP recommendations to govern what gets approved in rate cases, tie utility earnings to delivery against the plan, and put hard deadlines with financial penalties on interconnection. The PUC’s open performance-based regulation inquiry is the right venue.

The tools Steyer gets right — outcomes-based regulation, getting more out of existing assets, blocking unnecessary capital spending — live here for Maine. The PBR inquiry is the right vehicle. The question is whether Maine puts real mechanisms in place or ends up with another advisory process.

How should Maine require large new loads like data centers to pay their own grid costs?

Data centers and other large new loads should pay for their own delivery infrastructure, post curtailment commitments, and contribute to a reserve fund that protects existing ratepayers if the load doesn’t materialize as promised. A 25-megawatt threshold, clear cost-causation rules, and a reserve mechanism are not anti-growth. They distinguish growth that lowers everyone’s bill by spreading fixed costs from growth that raises everyone’s bill by socializing risk.

These rules aren’t complicated. They’re the difference between growth that works for ratepayers and growth that doesn’t. Maine is in the middle of that conversation right now.

Why does Maine need to engage more seriously at FERC and ISO New England on transmission?

About a quarter of a Maine electricity bill is transmission, and most of those costs are decided at FERC and at ISO New England, not in Augusta. State regulators and legislators rarely engage at those forums in proportion to the money at stake. Investing real capacity at NESCOE, in FERC proceedings, and in regional transmission planning reform is where some of the largest bill changes for Maine ratepayers will be won or lost over the next decade. Public bond financing for specific projects can lower capital costs where it fits.

This work is slow and unglamorous. It doesn’t produce press releases. But it’s where the dollars are. Public bond financing for specific transmission projects can lower the cost of capital meaningfully, provided it’s bounded carefully so it doesn’t get confused with a return to the public-power ballot fight Maine voters resolved in 2023.

How should Maine stop putting storm costs into the rate base for forty years?

Maine currently defers storm costs above CMP’s $10 million annual reserve into rate cases, where they accrue carrying costs and are amortized over decades. Proactive hardening gets capitalized into the rate base, where ratepayers pay a return across the asset’s full life. Every major storm becomes another permanent layer of capital. Maine should adopt securitization authority for large one-time storm costs and a separate plan-driven cost recovery clause for proactive hardening — the combination used by Florida and more than half of U.S. states.

Resilience investments are necessary. The problem is how Maine pays for them.

Costs above CMP’s $10 million annual storm reserve are deferred and amortized through rate cases, with carrying costs accruing in the meantime, while proactive hardening gets capitalized into rate base, where customers pay a return across the asset’s multi-decade life. Every major storm becomes another permanent layer of capital with a return layered on top. Given how often Maine gets hit now, that compounds quickly.

Florida’s Storm Protection Plan Cost Recovery Clause, created by statute in 2019, requires utilities to file ten-year hardening plans recovered through a separate rate clause — outside base rates, with annual prudence review and true-ups. It still includes a return on capital, but it forces hardening into a public, plan-driven process and prevents utilities from quietly folding whatever they want into base rates under the storm-response label. FPL recovered roughly $787 million through this clause in 2025, all under an approved plan.

More than half of U.S. states now allow utilities to securitize large storm costs through low-interest recovery bonds. Ratepayers repay the actual storm cost without also paying decades of utility equity returns on top of it. Maine still relies largely on deferral and amortization through traditional rate mechanisms.

The combination Maine should pursue: securitization authority for large one-time storm costs, a separate plan-driven recovery clause for proactive hardening, a stronger storm reserve, and serious pursuit of federal storm-recovery dollars. None of this eliminates storm costs — those are coming regardless. It changes how many decades ratepayers spend paying them back.

California worries about wildfire. Maine worries about ice storms. The lesson is the same: how you pay for resilience matters as much as whether you do it.

Closing

This isn’t a 25 percent rate cut. It’s a program that, taken together, can hold bills steady against the cost pressures coming at Maine over the next decade and bend them down modestly over time. It’s also a program Maine has already started building, in pieces, through the PUC’s PBR inquiry, the IGP docket, the data center conversation, and the post-LD 1959 accountability work. The job is to finish it.

A slogan about 25 percent cuts is easy to make. The actual work is slower, more technical, and harder to fit on a mailer. But it’s the work that actually changes bills.