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New York faces soaring energy bills as utilities seek record rate hikes, aging grid infrastructure demands upgrades, and federal renewable policies shift. Consumers struggle with affordability, late payments, and rising costs of delivery and energy supply across the state.

Why is New York Facing Soaring Energy Bills?

New York faces soaring energy bills because utilities are raising rates to cover the costs of grid upgrades, inflation, and policy-driven changes in energy supply.

✅ Utilities seek double-digit rate hikes across the state

✅ Aging infrastructure and storm repairs increase delivery costs

✅ Federal policies and gas dependence push energy prices higher

New Yorkers are bracing for another wave of energy bill increases as utilities seek record-high rate hikes and policy changes ripple through the state’s power system. Electric bills in New York are the highest they’ve been in over a decade, and more than a million households are now at least two months behind on payments, a sign of pandemic energy insecurity that continues to strain budgets, owing utilities nearly $2 billion.

Record numbers of households have had their electricity or gas shut off this year — more than 61,000 in May alone — despite pandemic shut-off suspensions that had offered temporary relief, the highest the Public Utility Law Project (PULP) has ever recorded. “This August was the group’s busiest month ever,” said Laurie Wheelock, PULP’s executive director, citing a surge in calls to its hotline. “The top concern on people’s minds: rate hikes.”

Utilities across the state are pushing for significant price increases, citing aging infrastructure, the need for climate adaptation, and higher operating costs, as California regulators face calls for action amid rising bills. “We used to see single-digit rate hikes and now we see double-digit rate hikes,” said Jessica Azulay, executive director of the Alliance for a Green Economy. “That’s a new normal that is unacceptable.”

Several utilities have requested delivery rate increases of 25 percent or more, with some proposals as high as 39 percent. Upstate utilities NYSEG and RG&E are seeking to raise electric and gas bills by about $33 a month, although regulators are unlikely to approve the full amount.

The companies argue the hikes are needed “to pay for rebuilding an aging grid and expanding its capacity to meet residents’ and businesses’ service demands,” including storm repairs. They also claim the plan would create more than 1,000 jobs.

James Denn, a spokesperson for the Public Service Commission (PSC), said much of the cost pressure stems from “inflation, higher interest rates, supply chain disruptions, the global push to upgrade electrical infrastructure, and, most recently, the rising risk and uncertainty from tariffs,” trends reflected in U.S. electricity price data over the past two years.

While some have blamed New York’s clean-energy transition, a PSC report found that state climate policies account for only 5 to 9.5 percent of the average household’s electric bill, or approximately $10 to $12 per month. The bulk of the increases still come from traditional spending on infrastructure, storm resilience, and system expansion.

On the supply side, costs are rising too. President Donald Trump’s recent policies have threatened renewable-energy investment nationwide, even as states’ renewable ambitions carry significant costs, potentially adding to New York’s woes. His July “megabill” phases out a 30 percent federal tax credit for solar and wind unless projects begin construction by mid-2026. Industry experts warn that the changes could make renewables “more expensive to build” and “increase reliance on gas.”

“It just means more expensive power,” said Marguerite Wells of the Alliance for Clean Energy New York.

The state estimates Trump’s policy shifts could cost New York $60 billion in lost renewable investment. With fewer clean-energy projects moving forward, gas — which already supplies roughly half of the state’s electricity — will remain the dominant source, tying energy prices to volatile global markets and the kinds of price drivers seen in California in recent years.

Governor Kathy Hochul has called affordability “our greatest short-term challenge,” while consumer advocates are demanding reforms to reduce utility profits and overhaul “rate design,” and to strengthen protections such as the emergency disconnection moratorium that applies during declared emergencies.

“There is definitely a groundswell of concern,” Wheelock said. “We go to meetings and we’re getting questions about rate design, like, ‘What is the revenue decoupling mechanism?’ Never had that question before.”

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Nova Scotia Power Rate Increase Settlement faces UARB scrutiny as regulators weigh electricity rates, fuel costs, storm rider provisions, Bill 212 limits, and Muskrat Falls impacts on ratepayers and affordability for residential and industrial customers.

Key Points

A deal proposing 13.8% electricity hikes for 2023-2024, before the UARB, covering fuel costs, a storm rider, and Bill 212.

✅ UARB review may set different rates than the settlement

✅ Fuel cost prepayment and hedging incentives questioned

✅ Storm rider shifts climate risk onto ratepayers

Nova Scotia Premier Tim Houston is calling on provincial regulators to reject a settlement agreement between Nova Scotia Power and customer groups that would see electricity rates rise by nearly 14% electricity rate hike over the next two years.

"It is our shared responsibility to protect ratepayers and I can't state strongly enough how concerned I am that the agreement before you does not do that," Houston wrote in a letter to the Nova Scotia Utility and Review Board late Monday.

Houston urged the three-member panel to "set the agreement aside and reach its own conclusion on the aforementioned application."

"I do not believe, based on what I know, that the proposed agreement is in the best interest of ratepayers," he said.

The letter does not spell out what his Progressive Conservative government would do if the board accepts the settlement reached last week between Nova Scotia Power and lawyers representing residential, small business and large industrial customer classes.

Other groups also endorsed the deal, although Nova Scotia Power's biggest customer — Port Hawkesbury Paper — did not sign on.

'We're protecting the ratepayers'
Natural Resources Minister Tory Rushton said the province was not part of the negotiations leading up to the settlement.

"As a government or department we had no intel on those conversations that were taking place," he said Tuesday. "So, we saw the information the same as the public did late last week, and right now we're protecting the ratepayers of Nova Scotia, even though the province cannot order Nova Scotia Power to lower rates under current law. We want to make sure that that voice is still heard at the UARB level."

Rushton said he didn't want to presuppose what the UARB will say.

"But I think the premier's been very loud and clear and I believe I have been, too. The ratepayers are at the top of our mind. We have different tools at our [disposal] and we'll certainly do what we can and need to [do] to protect those ratepayers."

The settlement agreement
If approved by regulators, rates would rise by 6.9 per cent in 2023 and 6.9 per cent in 2024 — almost the same amount on the table when hearings before the review board ended in September.

The Houston government later intervened with legislation, known as Bill 212, that capped rates to cover non-fuel costs by 1.8 per cent. It did not cap rates to cover fuel costs or energy efficiency programs.

In a statement announcing the agreement, Nova Scotia Power president Peter Gregg claimed the settlement adhered "to the direction provided by the provincial government through Bill 212."

Consumer advocate Bill Mahody, representing residential customers, told CBC News the proposed 13.8 per cent increase was "a reasonable rate increase given the revenue requirement that was testified to at the hearing."

Settlement 'remarkably' similar to NSP application
The premier disagrees, noting that the settlement and rate application that triggered the rate cap are "remarkably consistent."

He objects to the increased amount of fuel costs rolled into rates next year before the annual true up of actual fuel costs, which are automatically passed on to ratepayers.

"If Nova Scotia Power is effectively paid in advance, what motive do they have to hedge and mitigate the adjustment eventually required," Houston asked in his letter.

He also objected to the inclusion of a storm rider in rates to cover extreme weather, which he said pushed the risk of climate change on to ratepayers.

Premier second-guesses Muskrat Falls approval
Houston also second-guessed the board for approving Nova Scotia Power's participation in the Muskrat Falls hydro project in Labrador.

"The fact that Nova Scotians have paid over $500 million for this project with minimal benefit, and no one has been held accountable, is wrong," he said. "It was this board of the day that approved the contracts and entered the final project into rates."

Ratepayers are committed to paying $1.7 billion for the Maritime Link to bring the green source of electricity into the province, while rate mitigation talks in Newfoundland lack public details for their customers.

Although the Maritime Link was built on time and on budget by an affiliated company, only a fraction of Muskrat Falls hydro has been delivered because of ongoing problems in Newfoundland, including an 18% electricity rate hike deemed unacceptable by the province's consumer advocate.

"I find it remarkable that those contracts did not include different risk sharing mechanisms; they should have had provisions for issues in oversight of project management. Nevertheless, it was approved, and is causing significant harm to ratepayers in the form of increased rates."

Houston notes that because of non-delivery from Muskrat Falls, Nova Scotia Power has been forced to buy much more expensive coal to burn to generate electricity.

Opposition reaction
Opposition parties in Nova Scotia reacted to Houston's letter.

NDP Leader Claudia Chender dismissed it as bluster.

"It exposes his Bill 212 as not really helping Nova Scotians in the way that he said it would," she said. "Nothing in the settlement agreement contravenes that bill. But it seems that he's upset that he's been found out. And so here we are with another intervention in an independent regulatory body."

Liberal Leader Zach Churchill said the government should intervene to help ratepayers directly.

"We just think that it makes more sense to do that directly by supporting ratepayers through heating assistance, lump-sum electricity credits, rebate programs and expanding the eligibility for that or to provide funding directly to ratepayers instead of intervening in the energy market in this way," he said.

The premier's office said that no one was available when asked about an interview on Tuesday.

"The letter speaks for itself," the office responded.

Nova Scotia Power issued a statement Tuesday. It did not directly address Houston's claims.

"The settlement agreement is now with the NS Utility and Review Board," the utility said.

"The UARB process is designed to ensure customers are represented with strong advocates and independent oversight. The UARB will determine whether the settlement results in just and reasonable rates and is in the public interest."

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Hydro One CEO Salary shapes debate on Ontario electricity costs, executive compensation, sunshine list transparency, and public disclosure rules, as officials argue pay is not driving planned hydro rate cuts for consumers.

Key Points

Hydro One CEO pay disclosed in public filings, central to debates on Ontario electricity rates and transparency.

✅ 2016 compensation: $4.5M (salary + bonuses)

✅ Excluded from Ontario's sunshine list after privatization

✅ Government says pay won't affect planned hydro rate cuts

The $4.5 million in pay received by Hydro One's CEO is not a factor in the government's plan to cut electricity costs for consumers, an Ontario cabinet minister said Thursday amid opposition concerns about the executive's compensation and wider sector pressures such as Manitoba Hydro's rising debt in other provinces.

Treasury Board President Liz Sandals made her comments on the eve of the release of the province's so-called sunshine list.

The annual disclosure of public-sector salaries over $100,000 will be released Friday, but Hydro One salaries such as that of company boss Mayo Schmidt won't be on it.Though the government still owns most of Hydro One — 30 per cent has been sold — the company is required to follow the financial disclosure rules of publicly traded companies, which means disclosing the salaries of its CEO, CFO and next three highest-paid executives, and financial results such as a Q2 profit decline in filings.

New filings show that Schmidt was paid $4.5 million in 2016 — an $850,000 salary plus bonuses — and those top five executives were paid a total of about $11.7 million. 

"Clearly that's a very large amount," said Sandals. Sandals wouldn't say whether or not she thought the pay was appropriate at a time when the government is trying to reduce system costs and cut people's hydro bills.

Mayo Schmidt, President & CEO of Hydro One Limited and Hydro One Inc. (Hydro One )

But she suggested the CEO's salary was not a factor in efforts to bring down hydro prices, even as Hydro One shares fell after a leadership shakeup in a later period. "The CEO salary is not part of the equation of will 'we be able to make the cut,"' she said. "Regardless of what those salaries are, we will make a 25-per-cent-off cut." The cut coming this summer is actually an average of 17 per cent -- the 25-per-cent figure factors in an earlier eight-per-cent rebate.

NDP Leader Andrea Horwath, who has proposed to make hydro public again in Ontario, said the executive salaries are relevant to cutting hydro costs.

"All of this is cost of operating the electricity system, it's part of the operating of Hydro One and so of course those increased salaries are going to impact the cost of our electricity," she said.

Schmidt was appointed Aug. 31, 2015, and in the last four months of that year earned $1.3 million, but the former CEO was paid $745,000 in 2014. About 3,800 workers were paid over $100,000 that year, none of whom will be on the sunshine list this year.

Progressive Conservative energy critic Todd Smith has a private member's bill that would put Hydro One salaries back on the list, amid investor concerns about Hydro One that cite too many unknowns.

"The Wynne Liberals don't want the people of Ontario to know that their rates have helped create a new millionaire's club at Hydro One," Smith said. "Hydro One is still under the majority ownership of the public, but Premier Kathleen Wynne has removed these salaries from the public's watchful eye."

The previous sunshine list showed 115,431 people were earning more than $100,000 — an increase of nearly 4,000 people despite the fact 3,774 Hydro One workers were not on the list for the first time.

Tom Mitchell, the former CEO at Ontario Power Generation who resigned last summer, topped the 2015 list at $1.59 million.

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Michigan EV time-of-use charging helps DTE Energy and Consumers Energy manage off-peak demand, expand smart charger rebates, and build DC fast charging infrastructure, lowering grid costs, emissions, and peak load impacts across Michigan's distribution networks.

Key Points

Michigan utility programs using time-based EV rates to shift charging off-peak and ease grid load via charger rebates.

✅ Off-peak rates cut peak load and distribution transformer stress.

✅ Rebates support home smart chargers and DC fast charging sites.

✅ DTE Energy and Consumers Energy invest to expand EV infrastructure.

The two largest utilities in the state of Michigan, DTE Energy and Consumers Energy, are looking at time-of-use charging rates in two proposed electric vehicle (EV) charging programs, aligned with broader EV charging infrastructure trends among utilities, worth a combined $20.5 million of investments.

DTE Energy last month proposed a $13 million electric vehicle (EV) charging program, which would include transformer upgrades/additions, service drops, labor and contractor costs, materials, hardware and new meters to provide time-of-use charging rates amid evolving charging control dynamics in the market. The Charging Forward program aims to address customer education and outreach, residential smart charger support and charging infrastructure enablement, DTE told regulators in its 1,100-page filing. The utility requested that rebates provided through the program be deferred as a regulatory asset.

Consumers Energy in 2017 withdrew a proposal to install 800 electric vehicle charging ports in its Michigan service territory after questions were raised over how to pay for the $15 million plan. According to Energy News Network, the utility has filed a modified proposal building on the former plan and conversations over the last year that calls for approximately half of the original investment.

Utilities across the country are viewing new demand from EVs as a potential boon to their systems, a shift accelerated by the Model 3's impact on utility planning, potentially allowing greater utilization and lower costs. But that will require the vehicles to be plugged in when other demand is low, to avoid the need for extensive upgrades and more expensive power purchases. Michigan utilities' proposal focuses on off-peak EV charging, as well as on developing new EV infrastructure.

While adoption has remained relatively low nationally, last year the Edison Electric Institute and the Institute for Electric Innovation forecast 7 million EVs on United States' roads by the end of 2025. But unless those EVs can be coordinated, state power grids could face increased stress, the National Renewable Energy Laboratory has said distribution transformers may need to be replaced more frequently and peak load could push system limits — even with just one or two EVs on a neighborhood circuit. 

In its application, DTE told regulators that electrification of transportation offers a range of benefits including "reduced operating costs for EV drivers and affordability benefits for utility customers."

"Most EV charging takes place overnight at home, effectively utilizing distribution and generation capacity in the system during a low load period," the utility said. "Therefore, increased EV adoption puts downward pressure on rates by spreading fixed costs over a greater volume of electric sales."

DTE added that other benefits include reduced carbon emissions, improved air quality, increased expenditures in local economies and reduced dependency on foreign oil for the public at large.

A previous proposal from Consumers Energy included 60 fast charging DC stations along major highways in the Lower Peninsula and 750 240-volt AC stations in metropolitan areas. Consumers' new plan will offer rebates for charger installation, as U.S. charging networks jostle for position amid federal electrification efforts, including residential and DC fast-charging stations.

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CO2 Tax for UK Offshore Energy Efficiency can accelerate adoption of aero-derivative gas turbines, flare gas recovery, and combined cycle power, reducing emissions on platforms like Equinor's Mariner and supporting net zero goals.

Key Points

A carbon price pushing operators to adopt efficient turbines, flare recovery, and combined cycle to cut emissions.

✅ Aero-derivative turbines beat industrial units on efficiency

✅ Flare gas recovery cuts routine flaring and fuel waste

✅ Combined cycle raises efficiency and lowers emissions

By Tom Baxter

The recent Energy Voice article from the Equinor chairman concerning the Mariner project heralding a ‘significant point of reference’ for growth highlighted the energy efficiency achievements associated with the platform.

I view energy efficiency as a key enabler to net zero, and alongside this the UK must start large-scale storage to meet system needs; it is a topic I have been involved with for many years.

As part of my energy efficiency work, I investigated Norwegian practices and compared them with the UK.

There were many differences, here are three;

1. Power for offshore installations is usually supplied from gas turbines burning fuel from the oil and gas processing plant, and even as the UK's offshore wind supply accelerates, installations convert that to electricity or couple the gas turbine to a machine such as a gas compressor.

There are two main generic types of gas turbine – aero-derivative and industrial. As the name implies aero-derivatives are aviation engines used in a static environment. Aero-derivative turbines are designed to be energy efficient as that is very import for the aviation industry.

Not so with industrial type gas turbines; they are typically 5-10% less efficient than a comparable aero-derivative.

Industrial machines do have some advantages – they can be cheaper, require less frequent maintenance, they have a wide fuel composition tolerance and they can be procured within a shorter time frame.

My comparison showed that aero-derivative machines prevailed in Norway because of the energy efficiency advantages – not the case in the UK where there are many more offshore industrial gas turbines.

Tom Baxter is visiting professor of chemical engineering at Strathclyde University and a retired technical director at Genesis Oil and Gas Consultants

2. Offshore gas flaring is probably the most obvious source of inefficient use of energy with consequent greenhouse gas emissions.

On UK installations gas is always flared due to the design of the oil and gas processing plant.

Though not a large quantity of gas, a continuous flow of gas is routinely sent to flare from some of the process plant.

In addition the flare requires pilot flames to be maintained burning at all times and, while Europe explores electricity storage in gas pipes, a purge of hydrocarbon gas is introduced into the pipes to prevent unsafe air ingress that could lead to an explosive mixture.

On many Norwegian installations the flare system is designed differently. Flare gas recovery systems are deployed which results in no flaring during continuous operations.

Flare gas recovery systems improve energy efficiency but they are costly and add additional operational complexity.

3. Returning to gas turbines, all UK offshore gas turbines are open cycle – gas is burned to produce energy and the very hot exhaust gases are vented to the atmosphere. Around 60 -70% of the energy is lost in the exhaust gases.

Some UK fields use this hot gas as a heat source for some of the oil and gas treatment operations hence improving energy efficiency.

There is another option for gas turbines that will significantly improve energy efficiency – combined cycle, and in parallel plans for nuclear power under the green industrial revolution aim to decarbonise supply.

Here the exhaust gases from an open cycle machine are taken to a separate turbine. This additional turbine utilises exhaust heat to produce steam with the steam used to drive a second turbine to generate supplementary electricity. It is the system used in most UK power stations, even as UK low-carbon generation stalled in 2019 across the grid.

Open cycle gas turbines are around 30 – 40% efficient whereas combined cycle turbines are typically 50 – 60%. Clearly deploying a combined cycle will result in a huge greenhouse gas saving.

I have worked on the development of many UK oil and gas fields and combined cycle has rarely been considered.

The reason being is that, despite the clear energy saving, they are too costly and complex to justify deploying offshore.

However that is not the case in Norway where combined cycle is used on Oseberg, Snorre and Eldfisk.

What makes the improved Norwegian energy efficiency practices different from the UK – the answer is clear; the Norwegian CO2 tax.

A tax that makes CO2 a significant part of offshore operating costs.

The consequence being that deploying energy efficient technology is much easier to justify in Norway when compared to the UK.

Do we need a CO2 tax in the UK to meet net zero – I am convinced we do. I am in good company. BP, Shell, ExxonMobil and Total are supporting a carbon tax.

Not without justification there has been much criticism of Labour’s recent oil tax plans, alongside proposals for state-owned electricity generation that aim to reshape the power market.

To my mind Labour’s laudable aims to tackle the Climate Emergency would be much better served by supporting a CO2 tax that complements the UK's coal-free energy record by strengthening renewable investment.

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France Nuclear Heatwave Restrictions signal reduced nuclear power along the Rhone River as EDF imposes output limits due to high water temperatures, grid needs, with minimal price impact amid strong solar and exports.

Key Points

Temporary EDF output limits at Rhone River reactors due to hot water, protecting ecosystems and grid reliability.

✅ EDF expects halved output at Bugey and Saint Alban.

✅ Cuts align with water temperature and discharge rules.

✅ Weekend midday curtailments offset by solar supply.

The high temperature warning has come early this year but will affect fewer nuclear power plants. High temperatures could halve nuclear power production, with river temperature limits at plants along France's Rhone River this week. 

Output restrictions are expected at two nuclear plants in eastern France due to high temperature forecasts, nuclear operator EDF said. It comes several days ahead of a similar warning that was made last year but will affect fewer plants, and follows a period when power demand has held firm during lockdowns across Europe.

The hot weather is likely to halve the available power supply from the 3.6 GW Bugey plant from 13 July and the 2.6 GW Saint Alban plant from 16 July, the operator said.

However, production will be at least 1.8 GW at Bugey and 1.3 GW at Saint Alban to meet grid requirements, and may change according to grid needs, the operator said.

Kpler analyst Emeric de Vigan said the restrictions were likely to have little effect on output in practice. Cuts are likely only at the weekend or midday when solar output was at its peak so the impact on power prices would be slim.

He said the situation would need monitoring in the coming weeks, however, noting it was unusually early in the summer for nuclear-powered France to see such restrictions imposed.

Water temperatures at the Bugey plant already eclipsed the initial threshold for restrictions on 9 July, as European power hits records during the heatwave. They are currently forecast to peak next week and then drop again, Refinitiv data showed.

"France is currently net exporting large amounts of power – and, despite a nuclear power dispute with Germany, single nuclear units' supply restrictions will not have the same effect as last year," Refinitiv analyst Nathalie Gerl said.

The Garonne River in southern France has the highest potential for critical levels of warming, but its Golfech plant is currently offline for maintenance until mid-August, as Europe faces nuclear losses, the data showed.

"(The restrictions were) to be expected and it will probably occur more often," Greenpeace campaigner Roger Spautz said.

"The authorities must stick to existing regulations for water discharges. Otherwise, the ecosystems will be even more affected," he added.

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