Rhode Island House Members’ Proposed $13.6 Billion Budget Fails to Fund EC4

PROVIDENCE — The agency that is taking the lead on the state’s climate-change response will have to go another year without a budget, after House lawmakers failed to include funding for the Executive Climate Change Coordinating Committee (EC4) in their spending plan.

House members unveiled their version of a $13.6 billion state budget last week.

Gov. Dan McKee’s budget proposal in January suggested “scooping” $6 million annually from state energy-efficiency money to fund the committee, which operates without funding and relies on a single staff member on loan from the Rhode Island Department of Environmental Management. While the move from the governor was not popular among local environmental groups, the House did not provide an alternative method of funding the EC4.

“The ratepayers scoop of energy-efficiency funds has been removed, which is a good thing, we advocated for that,” said Hank Webster, Rhode Island director of the Acadia Center. “However, we also advocated for policymakers to find another way to fund the EC4’s activities.”

DEM director and EC4 chairman Terry Gray told ecoRI earlier this year that the greater impact would come from the committee having no operating budget. “From my standpoint as the EC4 chair, we need money to implement the Act on Climate,” he said. “The source of the money can be debated, and where it comes from is I think secondary to the fact that we get some kind of investment in the EC4 to make the work happen.”

Still, the fiscal 2023 budget indicates lawmakers are ready to spend money and resources on environmental management. DEM is slated to receive 16 new full-time positions under the House version of the budget, as opposed to the nine it requested earlier this year. At least six of those new hires would be in the department’s permitting and compliance offices, areas in which staffing for years has been seen by outside observers as insufficient.

The Coastal Resources Management Council (CRMC) would receive $150,000 to hire a full-time hearing officer, an attorney, to adjudicate contested decisions by its voting body. McKee had proposed $15,000 for a part-time hearing officer. Hiring a full-time hearing officer was one of the short-term recommendations from a special legislative commission created to study CRMC reorganization.

Lawmakers are also giving $4 million to the Ocean State Climate Adaptation and Resilience (OSCAR) Fund. The fund was created last year by the General Assembly, but at the last minute its funding mechanism — charging a nickel per barrel of oil and petroleum products imported into the state — was stripped from the bill.

“It’s really great news, we’ve been advocating for OSCAR for five years,” said Topher Hamblett, director of advocacy and policy for Save The Bay.

OSCAR awards grants to municipalities to improve climate resiliency by using and improving “natural” features: resizing culverts or restoring floodplains and saltwater marshes, for example. The program is in addition to Municipal Resilience Program grants administered by the Rhode Island Infrastructure Bank.

The House Finance Committee also recommended $25 million from State Fiscal Recovery funds for an electric heat pump incentive program, designed to help low- and moderate-income households buy and install electric heating systems to replace heating oil or natural gas systems. Residential heating accounts for 18.3% of all greenhouse gas emissions in Rhode Island.

Starting in September, the Rhode Island Public Transit Authority (RIPTA) will run a one-year pilot program with free bus service on the R-Line, a popular route starting at Broad Street in South Providence and running to the Pawtucket Transit Center on Roosevelt Avenue. RIPTA will be mandated to track ridership data and submit a report to the Legislature by March 2024 for further evaluation of the program. Sen. Meghan Kallman, D-Pawtucket, and Rep. Leonela Felix, D-Pawtucket, had introduced legislation this session to make all RIPTA bus routes free. The bill was held for further study.

The budget is far from final. Lawmakers’ version of the budget is scheduled for a full vote of the House on Thursday afternoon, and legislators may still make changes on the floor.

Read the full article in ecoRI News here.

Maine plan for wood-fired power plants draws praise and skepticism

A new law encouraging the development of wood-fired combined heat and power plants in Maine is drawing praise for its potential to benefit the economy and the environment.

But some climate activists are skeptical, saying questions remain about whether the program will cut carbon emissions as intended.

The legislation, signed by Gov. Janet Mills in April, establishes a program to commission projects that will burn wood to create electricity and also capture the heat produced for use on-site — heat that would go to waste in a conventional power plant.

Proposals for these facilities are expected to come from forestry or forest products businesses that could use their own wood byproducts to fuel the plants, saving them money on heat and electricity costs and providing an extra revenue stream when excess power is sold back into the grid.

“It’s renewable energy that is produced by local loggers and providing jobs for our local community,” said James Robbins, president of Robbins Lumber in Searsport, Maine, which has operated its own combined heat and power plant since 2018.

Supporters like Robbins say these facilities will uplift struggling sectors of the economy while helping reach the goals of Maine’s climate plan, which calls for the state to reduce emissions by 80% by 2050. Some environmental activists, however, doubt that wood can ever be an efficient fuel and worry that these projects will in fact increase carbon emissions.

“This is really an economic development tool to help prop up mills and not a climate solution,” said Greg Cunningham, director of the clean energy and climate change program at the Conservation Law Foundation.

Economy and environment?

Over the past 15 years, at least four of Maine’s paper mills have shut down, citing competition from overseas, decreasing demand, and soaring energy costs. A sixth had its operations sharply curtailed by an explosion at the facility in 2020.

These closures have meant less of a market for the wood chips and low-grade wood byproducts — often called residual wood — that lumber mills and loggers have generally sold as raw material for paper production. And with less demand, prices fell sharply, Robbins said.

“It created a huge surplus on the market here,” he said.

For businesses struggling to find buyers for their residual wood, the opportunity to build combined heat and power plants offers financial benefits. The systems can reduce or eliminate the cost of heating fuel, and the power produced can be sold back to the grid for additional revenue. These facilities could also help the industry as a whole by creating new markets for residual wood, thus buoying prices.

Robbins Lumber uses the heat generated from its system to power kilns that dry out lumber before sale. The electricity is all sold back into the grid through a power purchase agreement. The arrangement has been doing exactly what it was intended to do, Robbins said.

“We are also burning sawdust, bark, wood chips, and biomass from our outside contractors,” he said. “It’s definitely created a consistent market for residuals, which is what we hoped for.”

Advocates also believe these plants will be environmentally beneficial. If not put to another use, residual wood might otherwise have been left to decompose and release its stored carbon into the atmosphere. Used in one of these systems, however, the wood will displace the fossil fuels that would otherwise have been used to generate the same heat and power.

“Yes, it’s releasing CO2, but it was going to release CO2 through decomposition anyway,” said Ivan Fernandez, a professor at the University of Maine’s School of Forest Resources and a member of the Maine Climate Council. “As far as what the atmosphere sees, [combined heat and power] is a really good tool in the toolbox in our climate response.”

On-site combined heat and power facilities also make it easier for logging operations to thin small or weak trees from the forest and put that wood to use, Fernandez said. This sort of culling helps the larger trees grow yet more and sequester even more carbon, so there is no new loss of carbon capture because of the removal of the smaller trees, he said.

Furthermore, the continual growth of new trees allows for the carbon released by burning wood to be naturally recaptured, said Patrick Strauch, executive director of the Maine Forest Products Council.

“We look at it as a pretty good balance,” he said. “There is no doubt that it contributes carbon to the atmosphere, but our forest resources at the same time are pulling carbon out.”

Climate advocate unconvinced

Not everyone is convinced of the environmental wisdom of wood-fired combined heat and power, however. Burning wood produces more carbon dioxide per unit of heat generated than burning natural gas or heating oil. Many climate advocates worry that the carbon-capture capacity of forests is not enough to offset these higher emissions.

“There is significant disagreement on whether it is truly carbon neutral and emission-free,” said Jeff Marks, Maine director and senior policy advocate for environmental nonprofit the Acadia Center.

In theory, combined heat and power plants can be 75% to 90% efficient, according to some research. By way of comparison, centralized electric power generation and onsite heat production are 31% and 80% efficient, respectively, according to a report from Pennsylvania State University.

But many variables can lower that number. Of particular concern with wood is the moisture level of the fuel used: The more water in the wood, the less efficiently it burns. Residual wood from wood harvesting operations is likely to have a higher moisture content than wood from lumber processing.

Furthermore, the exact rules regulating the new law have yet to be hashed out, leaving more room for doubt, Cunningham said. The law, for example, requires projects to be “highly efficient,” but leaves it to the state Public Utilities Commission to define that term. The legislation also requires a biennial report assessing the success and sustainability of the program but, again, the details are scarce. And the law includes no provisions for the monitoring or enforcement of the rules it creates.

These factors leave Cunningham skeptical that wood-fired combined heat and power could ever be a climate-smart choice.

“It will not be highly efficient — it’s not feasible with a wood fuel,” he said. “It will not to any extent be a climate solution.”

The law caps the program at a total capacity of 20 megawatts statewide, a tiny fraction of the 3,344 megawatts of generating capacity the state already has. Still, the climate implications of the new law matter, Cunningham said.

“The money available in the state of Maine to fight climate change and invest in clean energy programs is finite,” he said. “When any amount of it is siphoned off for an anti-climate program, it’s problematic.”

Read the full article at Energy News Network here.

Federal Regulators Drop Obstacle to Funding Renewable Energy… in 3 Years

An obscure rule that blocks state-subsidized renewable energy projects from finding funding in a key New England energy market will sunset in three years – but renewable energy advocates say that isn’t soon enough to keep consumers from having to pay twice for an impending rush of offshore wind projects

The Federal Energy Regulatory Commission approved a plan by ISO-New England – which operates the region’s electric grid –  to phase out a controversial minimum offer price rule by 2025.

The rule – which was intended to exclude state-funded renewable projects from entering an annual auction of future energy generating capacity at low prices – has been a point of frustration for New England states with ambitious renewable energy goals.

Those states, including Connecticut, contend the rule forces electric customers to pay twice for the same generating capacity – once for renewables through state contracts, and again for mostly natural gas plants through the regional capacity auction.

The rule also made it more challenging to develop new, large-scale renewable energy projects, said Melissa Birchard, director for clean energy and grid reform at Acadia Center.

“We don’t even know exactly how much it’s depressing the development of clean energy,” warned Birchard. “Without the financial support to develop new resources, there’s a whole world of clean energy that may not be getting developed.”

In testimony to FERC, Susannah Hatch, regional lead for New England for Offshore Wind, noted that both the 800-megawatt Vineyard Wind project set to go online next year, and three other projects totaling 2,300 megawatts scheduled to go online in 2025, won’t be able to fully participate in the next two capacity auctions funding projects for 2026 and 2027.

Hatch told CT Examiner that those projects will still be built even though they won’t be able to fully participate in the capacity market. The real issue, she said, is that their capacity won’t be counted in the regional market, so customers will be stuck paying for a different power plant providing redundant capacity, she said – likely a natural gas-burning power plant.

“It will require ratepayers to pay for unnecessary capacity, so bills are going to go up in this day and age when that’s already happening because of foreign conflicts and the price volatility of fossil fuels,” Hatch said.

Birchard said that a limited exception will allow some offshore wind projects to participate in the next two auctions, but that won’t be nearly enough.

“When you add them up, the offshore wind projects alone substantially exceed [the exception],” Birchard said. “And that doesn’t account for battery storage or other clean energy resources.”

Matt Kakley, a spokesman for ISO-New England, said the organization believes the exception is large enough to cover the offshore wind resources that would actually want to enter the market in those two auctions, and that it’s “incredibly unlikely” that the minimum price would come into play for battery storage in that time.

“We’re pleased that the Commission saw this proposal for what it is — a reasonable step forward on New England’s transition to a decarbonized future,” Kakley said. “Despite claims to the contrary, this transition will provide a clear path for clean energy resources ready to enter the market over the next two auctions, while affording the region time to tackle other needed market reforms.”

But with wind projects accounting for 60 percent of proposals for new generation, and solar and battery storage making up another 36 percent – a rule that excludes much of that new generating capacity was unsustainable, ISO-New England told FERC.

But ending the rule too quickly, the ISO warned, could disrupt the market and make the grid less reliable. If, for example, the construction of those projects was delayed after clearing the auction, the renewables might not come online before the legacy plants are shut down. That could leave the region with less electric generation than it needs.

In its decision, FERC said the two-year phase out provides the necessary time for the market to make an “orderly transition” to a new mix of generating resources, including more weather-dependent renewables.

FERC Chairman Richard Glick, who voted in favor of the two-year phase out of the rule, said that despite his vote, he believes ISO-New England could and should have “done better” to end the rule immediately.

But Glick said even the delayed end to the minimum offer price rule represented a major step forward. Glick wrote that under previous orders FERC turned minimum offer price rules into a tool for blocking efforts by individual states to sponsor renewable energy projects.

That fight threatened consumers, the environment, and the viability of capacity markets, Glick said – as frustrated states, including Connecticut, considered abandoning those markets altogether.

“We need to do better and stop stalling,” Birchard said. “We need to keep beating that drum, because there’s a slew of additional reforms that need to take place over the next two or three years so we can move forward with our decarbonization goals.”

DEEP Commissioner Katie Dykes said that the department is still reviewing the decision, but said she is glad that it affirms an end date for the MOPR.

“We must redouble our efforts now on the further, significant reforms of the markets needed for a clean, reliable, affordable grid,” Dykes said.

Read the full article in The Connecticut Examiner here

Federal regulators uphold controversial grid proposal that could slow clean energy

Despite months of protests by clean energy activists and official pleas from public figures including Elizabeth Warren, federal regulators approved a plan by the region’s energy grid operator that could slow the development of clean electricity for two years.

The decision, handed down by the Federal Energy Regulatory Commission ( FERC), late Friday night, affirms a plan by ISO New England to wait two years to remove a mechanism that makes it harder for clean energy projects to enter the competitive market, rather than doing it immediately.

The decision came after months of outcry, including from Senators Ed Markey, Elizabeth Warren, and Bernie Sanders, Attorney General Maura Healey, former state energy and environment secretary Kathleen Theoharides, and scores of clean energy and climate advocates.

It also came with the apparent reluctance of a majority of FERC commissioners, several of whom wrote that they would have preferred to see the mechanism in question — called the Minimum Offer Price Rule (MOPR) — removed by ISO-NE immediately. “Simply put, ISO-NE could have, and should have, done better,” wrote FERC chairman Richard Glick in his comments.

Advocates in the region said they were disappointed by the decision, noting the FERC decision called the grid’s proposal “a just and reasonable outcome” — with the emphasis on “a” — and not the best outcome.

“We’ve been delaying a long time on removing this barrier to clean energy,” said Melissa Birchard, director of clean energy and grid reform for the advocacy group Acadia Center. “And the result is that we’re in a bit of a bind with fossil fuels right now, including the increasing costs of liquefied natural gas, which is an international market that is deeply affected by the events in Ukraine.”

ISO-NE, meanwhile, says that allowing for a two-year transition period before lifting the MOPR is a necessary safeguard to ensure grid reliability. “We’re pleased that the Commission saw this proposal for what it is — a reasonable step forward on New England’s transition to a decarbonized future,” ISO-NE spokesman Matthew Kakley said in a statement.

Kakley noted that during the two year transition period, there will be an allowance for 700 MW of clean energy resources to enter the market, though advocates say that amount is insufficient to meet the region’s clean energy demands. Massachusetts currently has authorized the procurement of 5,600 MW of offshore wind — to say nothing of its battery storage or utility-scale solar projects.

The minimum offer price rule limits what energy projects can bid into what’s known as the forward capacity market. Developers with successful bids are able to procure financing three years in advance, helping ensure that projects have the needed funds to be developed or expanded, and that the grid will have enough energy available in the future.

The minimum offer price rule was created to help insulate fossil fuel power plants from having to compete against renewables that cost less due to state programs and subsidies that exist to help foster clean energy development. It created a floor below which a developer cannot bid, meaning that those less expensive energy supplies, like large-scale offshore wind or solar, aren’t able to compete.

The fear from regulators and the fossil fuel industry was that without such a rule, fossil fuel plants could be forced offline before adequate clean energy was ready to fill the void on the grid, creating reliability problems. The effect has been that fossil fuel-fired power plants have been able to secure bids around the region, despite increasingly ambitious climate plans from the New England states that would indicate otherwise.

Advocates say that in the short term, the decision is a bad deal for consumers in the state. “Let’s say I have a hypothetical wind project that I want to bring online three years from the next auction,” said Jeff Dennis, managing director and general counsel at Advanced Energy Economy and a former director of FERC’s division of policy development. “If I offer in today and get subject to the minimum offer price rule, I get bounced out of the auction,” he said.

If the state goes ahead and builds the projects — as Massachusetts and other New England states are doing — then when that project comes online, consumers will be paying more for their energy, because they will be paying for the energy from the wind project, and for the energy that was already purchased on the forward capacity market three years earlier.

“I think the real risk here is the disconnect that a rule like the minimum offer price rule creates between the ISO New England and its markets and its states and their objectives,” Dennis said.

Converting the region’s energy grid from fossil fuel to clean energy is a key piece of New England’s climate future. As states race to electrify buildings and transportation, the demands on the grid are only going to grow. But if that electricity is still being generated by fossil fuels, emissions reductions goals in the region will not be achieved.

In Massachusetts, getting this clean energy on board quickly is central to achieving the legally mandated goals of slashing emissions to 50 percent of 1990 levels by 2030, and getting to net-zero by 2050. But Massachusetts isn’t alone. Four other New England states — Connecticut, Maine, Rhode Island, and Vermont — have committed to reducing economywide emissions by at least 80 percent below 1990 levels by 2050.

“This delay limits the ability of renewable resources to access the capacity market,” said Eric Wilkinson, electricity market policy director for offshore wind company Ørsted. “When ISO New England urged stakeholders to support the delay, they cited potential reliability concerns as a justification. However, the ISO has itself noted that offshore wind will increase system reliability, especially during the winter months when the concern is the greatest.”

Read the full article in The Boston Globe here.

A key rule on the New England power grid will end, but not for a while

It will be nearly three more years before a contentious rule ends that has made it difficult for renewable energy to get onto the New England grid.

Late Friday night, days before its deadline that fell on the holiday weekend, the Federal Energy Regulatory Commission approved a plan from regional power grid operator ISO-New England to change how it acquires power for the grid in the future.

Connecticut’s Department of Energy and Environmental Protection Commissioner Katie Dykes, her counterparts in other states and even some of the FERC commissioners themselves had preferred an immediate change. The slow transition is already sparking worries that more fossil fuel power generation will get entrenched in the grid before the rule changes.

“FERC’s decision fails to end once and for all the reign of this harmful rule,” said Melissa Birchard, director for clean energy and grid reform at the regional advocacy group Acadia Center. The rule, she said, “will continue to provide a lifeline to the region’s most inefficient fossil fuel generators for at least three more years.”

The rule at the center of this controversy is known as the Minimum Offer Price Rule – or the MOPR. It is the backbone of the ISO’s once-a-year auction that determines what generating resources will go into its Forward Capacity Market, the future power it plans three years in advance.

In the auction, the low price wins, but it includes a formula that is heavily weighted against state-subsidized renewable energy projects — which, while coming down in price, are still more expensive than classic fossil fuel projects like natural gas power.

Connecticut and other New England states have renewable energy and greenhouse gas emissions targets, if not mandates. As a result of the MOPR, ratepayers wind up paying more for power to meet those targets.

Dykes has argued for years for changes to the rules, even threatening to pull Connecticut out of the forward capacity market. In mid-2021, discussions began on ending the MOPR by the beginning of 2023. But at the last minute, the ISO decided to file a plan with FERC that would delay full elimination of the MOPR for two additional years, until 2025.

Dykes and all but one of the other New England states didn’t support the change, but they didn’t oppose it either. “It’s a long way from not opposing to supporting,” she said early this year. She also pointed to the ISO’s contention that a transition period would better insure grid reliability.

She reiterated that stance in comments filed with FERC. But some dozen groups, including Acadia Center, filed comments and responses to comments opposing the slow transition.

Birchard now worries that the ISO will seek to delay the transition when the deadline approaches, or worse, try to revive the MOPR.

“The region deserves modern solutions, not delay tactics,” she said. “Russia’s war against Ukraine and the skyrocketing gas prices New England faces as a result puts in harsh relief the poor results of ISO-NE’s overreliance on fossil gas as a solution to every grid need.”

In an emailed statement, ISO spokesman Matt Kakley said: “We’re pleased that the Commission saw this proposal for what it is — a reasonable step forward on New England’s transition to a decarbonized future. Despite claims to the contrary, this transition will provide a clear path for clean energy resources ready to enter the market over the next two auctions, while affording the region time to tackle other needed market reforms.”

But FERC did not quite see it that way. The vote was 4-to-1, with one of two Republican commissioners opposing changing the MOPR. But the three Democratic commissioners were less than enthusiastic.

Chairman Richard Glick wrote, “I believe that the best outcome here would have been for ISO New England Inc. (ISO-NE) to immediately implement its new Minimum Offer Price Rule (MOPR) — i.e., without the Transition Mechanism. Simply put, ISO-NE could have, and should have, done better.”

Commissioners Allison Clements and Willie Phillips wrote jointly: “While immediate elimination of the MOPR would likely better serve ISO-NE’s customers than the proposal that has been filed, such a proposal is unfortunately not before us.”

The ISO also pointed out that, until the transition is complete, there will be a MOPR exemption for some offshore wind and solar, and battery storage will be in a very competitive position. Kakley also noted that long-term studies and ongoing changes to the market are designed to allow more renewables in.

Birchard said Acadia Center would be willing to work with ISO-New England on other critical energy reforms.

“But we challenge ISO-New England to embrace the clean energy solutions to today’s grid challenges instead of continuing to rely on costly and polluting fossil fuels as a crutch. The region deserves modern solutions, not delay tactics,” she said.

For her part, Dykes said, “We are still reviewing the decision. We are glad that the decision affirms a definitive end date for the MOPR. We must redouble our efforts now on the further, significant reforms of the markets needed for a clean, reliable, affordable grid.”

Read the full article in The CT Mirror here.

Feds approve plan to delay scrapping a New England energy rule that harms renewables

A controversial rule that makes it harder for renewable energy projects to participate in one of New England’s lucrative electricity markets will remain in place for another two years.

Late Friday night, Federal energy regulators approved a plan from the regional grid operator, ISO New England, to keep the so-called minimum offer price rule — or MOPR (pronounced MOPE-er) — until 2025.

The MOPR dictates a price floor below which new power sources cannot bid in the annual forward capacity market — a sort of futures market for power plants promising to be “on call” and ready to produce electricity when demand spikes.

The grid operator holds this annual on-call auction to lock in the power capacity it thinks the region will need three years in the future. Power generators that won a spot in the 2022 auction, for example, are on stand-by beginning in 2025.

By keeping the MOPR around longer, Melissa Birchard of the Acadia Center says it will be harder for the New England states to meet their decarbonization goals.

“The MOPR has held the region back for a long time and we need to see it go away forever,” she said. “This decision falls short of providing the certainty and speed that the region deserves.”

As WBUR detailed in a recent explainer about the MOPR, most everyone agrees the rule needs to go; the debate has been over when it should happen.

Environmentalists, consumer advocates and most New England state leaders wanted the grid operator to scrap the rule in time for the February 2023 auction. But the grid operator decided to support a “transition proposal” — first put forward by a few energy companies with natural gas plants — that would keep it until the 2025 auction.

Notably, Friday’s decision from the Federal Energy Regulatory Commission, which oversees the New England grid operator, was not unanimous. Four out of five members voted in favor of the plan, though some, like Commissioner Richard Glick, did so reluctantly.

Glick, who has been outspoken about the need to reform the MOPR, wrote in a statement that he would have preferred to see the grid operator, ISO New England (ISO-NE), eliminate the rule immediately.

Read the full article in WBUR News here.

CMP to seek 3-year rate hike that would raise average bill by $10

Central Maine Power is asking state utility regulators to approve a three-year reliability and grid upgrade plan that could raise bills for the typical home customer by as much as $10 a month by 2026.

The rate hike would support investments to make the distribution system more resilient to storms, restore power faster after outages and enable more renewable power generators to hook up as the state transitions to a cleaner-energy economy. The proposal, however, drew immediate opposition from Gov. Janet Mills, who called the plan to raise rates “outrageous” and said, “I will fight this.”

CMP notified the Maine Public Utilities Commission on Thursday of its intent to formally file a detailed rate case sometime this summer. The company has dubbed the plan Powering Maine and characterized it as an attempt to keep distribution rates relatively stable and predictable over the next few years.

For an average home customer using 550 kilowatt-hours a month, the plan would increase a total electric bill by roughly $5 a month in 2023, and up to $2.50 a month in each of the following two years.

An average monthly residential electric bill today, including both distribution and supply, is $126. If the full rate request is approved, it would increase that bill by roughly 4 percent in 2023.

The company also is seeking a return on equity of between 10 percent and 10.5 percent, which it says reflects current market conditions. Return on equity is a measure of profitability and financial performance that’s important to investors.

CMP’s request is only for the distribution costs associated with bringing power over poles and wires to homes and businesses. It’s not tied to electricity supply charges, which have surged this year in response to high natural gas prices and world events. CMP doesn’t generate power; it only distributes it.

But Mills said any plan to increase electric bills for consumers already dealing with widespread inflation in the economy “adds insult to injury.”

The governor called on CMP to hold off filing for the rate increase, and said if the utility goes ahead, she will have the Governor’s Energy Office intervene in the case to oppose it.

If the PUC rejects the rate increase, she said, it would send a “clear message to our utilities that their focus needs to be on improving performance, reducing cost burdens and restoring trust.”

Mills’ comments suggest that energy prices may emerge as a campaign issue, as her race for re-election against former Gov. Paul LePage moves closer to the fall.

Late Thursday, the Maine Republican Party attempted to tie CMP’s request for a rate hike to Mills’ policies, contending that a provision in a utility reform bill she introduced that requires utilities to plan for climate change is forcing utilities to spend more money. The bill was co-sponsored by two Republicans who serve on the Legislature’s Energy, Utilities and Technology Committee, Sen. Trey Stewart, R-Aroostook, and Rep. Nathan Wadsworth, R-Hiram.

“It’s the same old tune from Janet Mills: make Mainers’ lives more expensive in order to fund left-wing policies,” Maine GOP Executive Director Jason Savage said in a statement emailed Thursday night.

Acknowledging the impact of any rate increases on household budgets weighed down by today’s high inflation and energy prices, CMP’s president and chief executive, Joseph Purington, said the investments are needed to continue progress on updating the electric grid. The trick is finding a balance in spending that makes the distribution system more resilient but isn’t an undue burden for customers, he said.

“CMP must continue to make smart system updates that improve reliability now and enable the company to successfully perform our role in helping Maine meet its climate change goals,” Purington said.

CMP’s multiyear rate request comes as the manner in which utilities decide how to make investments in their infrastructure is about to undergo a historic change.

In early May, Mills signed L.D. 1959. The new utility reform law beefs up utility accountability, but it also requires companies the size of CMP and Versant Power to take part in an “integrated grid planning” process, aimed at supporting the state’s transition to a renewable energy economy and meeting aggressive climate action goals.

Rate increases are never welcomed by customers, but CMP’s ask carries excess baggage.

Although the company’s performance benchmarks have improved with the PUC in recent years, CMP and its domestic parent company, Avangrid, remain unpopular with many customers and a target of adversaries. A major Avangrid transmission project, the New England Clean Energy Connect, is tied up in court. A campaign to replace CMP and Versant Power with a statewide consumer-owned utility continues to collect signatures in a bid to bring the issue before voters in 2023.

ADVOCATE CALLS FOR SCRUTINY 

In an initial reaction to the filing Thursday, Maine’s top utility customer watchdog said his office will scrutinize the assumptions behind the rate request. By itself, the proposed increase isn’t outrageous, Public Advocate William Harwood said.

“But on top of everything else, the cumulative impact, it adds to the financial burden,” he said. “We’ll have to take a hard look at their justification.”

Harwood also said CMP’s request for a return on equity of up to 10.5 percent seems excessive, and that his office would analyze financial markets to recommend a fair return for investors.

“Our preliminary view based on other utility cases indicates a return on equity closer to 9 percent would be reasonable,” he said.

Regarding the new utility reform law, existing statutes require utilities to provide “safe, reasonable and adequate service.” At issue in the new grid planning process will be how to define reliability, measure to what extent the utilities are meeting the standard now and determine what it would cost to do more, Harwood said.

Approving a rate increase before the PUC adopts those new standards for the state’s utilities and starts the grid planning process would be putting the cart before the horse, said Jeff Marks, Maine director and senior policy advocate for the Acadia Center, an organization pushing for policies to protect the environment and transition to clean energy sources.

Marks said the new law will require the utilities to meet new standards to ensure they are using customer revenue wisely, and it also calls for a wide-ranging plan to enhance the state’s power grid. Deciding on a rate increase before either measure is in place doesn’t make sense, he said.

“These rate hikes show we can’t start too soon,” Marks said. “With this type of rate hike at this point, we need to start the accountability process.”

Marks also said that a comprehensive plan to modernize Maine’s electric grid could help keep rates low, and that giving CMP a rate hike to make some changes before the overall plan is even underway would be premature.

The new grid plan, along with new accountability measures, “will shine a spotlight” on how well the utilities are providing electric service to Mainers, Marks said, adding that analysis should be done before CMP seeks a rate hike, not after.

The proposed rate increase also was criticized by Our Power, a group advocating for CMP and Versant Power to be replaced with a consumer-owned utility, rather than investor-owned companies.

The increase “is far more than CMP customers can handle right now,” said Andrew Blunt, interim executive director of Our Power.

Blunt said the utility’s proposal to put most of the money into improving the reliability of its electric grid “is long overdue,” but he said bigger customer bills will make it easier for Our Power to gather support to put its plan to buy out CMP and Versant before Maine voters. The organization hopes to have enough signatures to gain a spot on the ballot next year.

“Every time they file for a rate increase, it makes ratepayers a little more angry, and for good reason,” Blunt said.

RATE HIKE WOULD FUND UPGRADES

The precise details of the Powering Maine plan won’t be available until summer, but broadly speaking, it covers a handful of topics.

• Automation: The company wants to invest in smart-switch technology to minimize the number of customers affected by an outage and allow its Augusta control center and line crews to restore power more quickly. On Maine’s coastal peninsulas, for instance, it’s common for 1,000 homes to lose power if a circuit trips when a tree falls on a wire during a storm. Adding more switches that can be controlled remotely could cut the number of impacted homes to between 300 and 500, the company said.

• Infrastructure: Installing stronger poles and coated wires that resist short circuits also is part of the package, as is more tree trimming. Falling trees and branches are the leading cause of outages in Maine, a condition being made worse by stronger storms linked to a changing climate.

• Customer tools: As more electric cars come on the road, CMP wants to offer special rates that reward customers for charging when demand is lower, such as overnight. These time-of-use rates are common in other states. Customers with battery storage at their homes or business also could receive credits for feeding power back into the grid when demand is highest.

• Renewable energy: CMP has been criticized for not doing enough to help connect the hundreds of solar-electric projects proposed in recent years. The company recently entered into a settlement agreement with the solar industry aimed at speeding the substation and other equipment upgrades needed to accommodate the influx. The company wants more revenue to expand the effort.

These and other measures would cost between $90 million and $105 million. In preliminary estimates for the PUC, CMP says it would need an additional $45 million to $50 million in the first year, $25 million to $30 million in the second year and $20 million to $25 million in the third year to implement its plan.

NEW LAW’S IMPACT UNCLEAR

It’s too early to know how the state’s new integrated grid planning law will impact the rate case, but some clarity may emerge in the months ahead.

The law directs utilities to develop a range of scenarios every five years, reflecting potential changes such as higher growth in electricity demand brought on by a shift to electric vehicles and heat pumps. They must forecast the energy they’ll need to meet those needs.

This process will kick off when the PUC begins a specified grid planning procedure in November. The utilities then will have 18 months to file plans based on the outcome, which will be subject to public comment.

By December 2023, the utilities also must submit to the PUC a 10-year plan with specific actions for addressing the expected impacts of climate change.

“The commission may use the plan and the input received from interested parties in rate cases or other proceedings involving the transmission and distribution utility,” the law states.

The law authorizes the agency to hire an attorney and two utility analysts, and use consultants to study similar investor-owned utilities and regulatory efforts. The roughly $900,000 total cost will be borne by ratepayers.

“The way I think about it is that the integrated grid planning process with stakeholder input may impact utility investment decisions, which ultimately will be evaluated in rate cases,” said Philip Bartlett, the PUC’s chair.

The long lead time in setting up the reliability targets at the PUC makes it unclear how or if CMP’s current rate request will be affected, said Purington, the CMP executive. But noting that the law contains penalty provisions of up to $1 million for failure to meet the standards, he said the company would have to calculate whether it has enough revenue to comply or if it would need to ask for more.

LAST CMP RATE CASE IN 2018

CMP last filed for a distribution rate hike in fall 2018, seeking an increase of $44.7 million. Before that, rates hadn’t changed since 2014.

In February 2020, the PUC authorized an increase of $17.4 million, or roughly 7 percent over the then-existing revenue requirement. It equated to a 2 percent hike in an average residential bill, edging up from $86.18 a month to $88.87.

The rate increase was less than half of what CMP had requested. It was accompanied by a 1 percent reduction in the company’s return on equity. The reduction, from 9.25 percent to 8.25 percent, added up to a nearly $10 million penalty over the 18 months it was in effect. It was a record reduction for the PUC, levied in response to CMP’s customer service failures following the rollout of a new billing system in 2017.

The action reflected findings of a 2019 Press Herald investigation that found officials at CMP, Avangrid and Iberdrola, their Spanish parent company, cut corners, skirted best industry practices and failed to adequately test a new, error-prone billing system launched in fall 2017. The meltdown of the $56 million billing system revealed a longstanding pattern of corporate mismanagement.

The penalty was lifted last February, after CMP met new service quality benchmarks over the period, although the PUC also opened a new and ongoing investigation into CMP’s management and relationship with Avangrid.

CMP is the state’s largest electric utility, with 646,000 customers mostly in southern and central Maine. It operates 23,500 miles of distribution lines and 2,900 miles of transmission lines.

Read the full article in the Portland Press Herald here

Study lays out options for New England grid operator to help cut emissions

The regional electric grid operator for New England is beginning to study how it could play a new role in cutting power sector emissions.

ISO New England oversees the electric grid for the six-state region, coordinating the real-time flow of electricity as well as operating longer-term markets to make sure an adequate supply of generation is being built.

Traditionally, as with other regional grid operators, its top concerns have been reliability and affordability: making sure it always has enough power to keep the lights on at the lowest possible price.

In recent years, though, many states have adopted a third priority: reducing emissions. Critics say grid operators have been slow to respond, and that their policies have become barriers to states’ climate goals by prioritizing conventional power plants over emerging clean energy resources.

ISO-NE’s recent Pathways study, released in February, lays out four possible frameworks for how the grid operator might integrate clean energy into the grid. They include continuing the status quo, creating a new clean energy market, implementing carbon pricing, and a hybrid scenario.

Advocates say the report is a pivotal — if long overdue — step toward decarbonizing the region’s power supply.

“To date, the ISO’s market designs have been holding back the region,” said Melissa Birchard, director of clean energy and grid reform at environmental advocacy group the Acadia Center. “This study is a first step to changing that.”

Goals and barriers

The New England states have generally set ambitious goals for reducing greenhouse gas emissions. Five of the states have decarbonization mandates that aim to eliminate all or most carbon dioxide emissions by 2040 or 2050. New Hampshire has called for a reduction of 80% by 2050, though this target is not enshrined in law.

To reach these targets, each state has its own combination of incentive programs, regulations, and energy procurement strategies. Connecticut, Massachusetts, and Rhode Island have all committed to significant offshore wind energy procurements, and Massachusetts’ solar incentive program is designed to bring 3,200 megawatts of renewable energy online.

It is widely believed, however, that the actions of individual states will not be enough to achieve the needed carbon reductions across the entire regional grid.

“To meet the decarbonization goals at the state level requires such a monumental shift of capital and investments,” said Dan Dolan, president of the New England Power Generators Association. The current course, he said, “is probably unsustainable.”

For many years, renewable energy supporters, climate activists, and state leaders have contended that the way ISO-NE pursues its goals has created barriers to decarbonizing the grid. For example, the organization’s minimum offer price rule — set to end in 2024 — has made it financially challenging for renewable resources to participate in capacity markets, advocates argue.

“It’s hard for the states to make progress when the ISO’s markets are putting up barriers,” Birchard said.

Four paths forward

The Pathways study is an attempt to begin investigating ways ISO-NE might in fact help drive the decarbonization of the grid over the coming decades.

“It’s asking, ‘What types of wholesale market designs might best help the region get to where it wants to go?’” said ISO-NE spokesperson Matthew Kakley.

The study, conducted by Boston-based economics consulting firm The Analysis Group, lays out four scenarios:

  • Continuing the status quo, in which individual states choose their own policies and enter into long-term contracts with renewable energy suppliers to achieve their targets.
  • Creating a forward clean energy market, a centralized market that compensates clean energy resources for committing to supply power at a future date.
  • Implementing a carbon price, which would require generators to pay for their carbon emissions and then return the money generated to energy consumers.
  • A hybrid scenario combining a forward clean energy market for new non-emitting resources with a carbon price for existing generators.

The study returned a broad-level look at the potential advantages and disadvantages of each scenario. A net carbon price would likely reduce carbon dioxide emissions most cost-effectively, with a forward clean energy market or a hybrid model performing just slightly less effectively. A carbon price and, to a lesser extent, a hybrid approach would also provide incentives for generators to reduce their carbon intensity.

A carbon price, however, would require the highest level of coordination among participating states, while the status quo, in which states operate individually, would naturally require the least coordination.

Now, ISO-NE will be collecting feedback from stakeholders as it determines the next steps forward.

“It’s really intended to be the foundation for broad discussions,” Kakley said.

States to play a key role

Some of the interested parties have already declared their preferred path forward. ISO-NE has long advocated for a carbon price, and the New England Power Generators Association has also made clear that this is their preference as well.

“We’re heartened to see that’s the lowest-cost option under the analysis that was done,” Dolan said.

The New England States Committee on Energy, a group representing the six New England states in regional energy matters, has been active in advocating for better ways to decarbonize the grid. In 2020, the group released a vision statement outlining the ways it felt the current ISO-NE markets placed obstacles in the way of clean energy development.

The group has welcomed the Pathways study as a valuable first step and said it will hold off on endorsing a specific option for now. However, it also acknowledges it “is interested in continuing development of [a forward clean energy market], which each state could elect to use to facilitate financing for new clean resources.”

Whatever path is chosen, there is widespread agreement that ISO-NE will need the support and engagement of the states to make the solution work.

“The states are going to play a key role in whatever market mechanism is selected here,” said Phelps Turner, senior attorney with the Conservation Law Foundation. “They’re going to be key participants and their views are critical in selecting and designing which mechanisms go forward.”

However, even as stakeholders embrace the Pathways study, many feel it has taken too long to get to this point. The need to make decisions and take action is only getting more urgent, Turner noted.

“It’s going to take time to design and implement whichever market mechanism or mechanisms the region decides to go with,” he said. “We’re keeping an eye on the clock here.”

Read the full article in Energy News Network here

New England predicted to see nation’s highest wholesale electricity prices this summer

New England is predicted to see the most expensive wholesale electricity prices in the nation this summer, according to a recent report by the U.S. Energy Information Administration.

The region’s mushrooming costs are indicative of the continuous turmoil of today’s energy markets — a combination of COVID economic recovery, inflation and the ongoing war conflict in Ukraine driving up prices for natural gas and oil.

But making matters worse in New England, experts say, is the region’s reliance on natural gas — perhaps the biggest culprit for its highest-in-the-nation designation.

This past winter, New Englanders already saw themselves paying significantly more for electricity and home heating, and summertime is infamous for high bills because of air conditioning and appliance use.

Average summer residential electricity prices in New England could increase close to 16%, the EIA predicts, compared to 4% nationally. The average monthly price that utility companies purchase electricity for — the wholesale price — could be 167% more than last summer. How and when the wholesale increase presents itself on customers’ bills will vary.

“This is not because of hot weather, this is because we are over-reliant on natural gas,” said Melissa Birchard, director of clean energy and grid reform at the Acadia Center, a nonprofit working to recalibrate the Northeast’s energy system. “Natural gas has become very expensive and hard to get after the Russian invasion of Ukraine.”

Because New England produces no natural gas of its own, “we have to get it from somewhere,” Birchard continued. As a result, “New England consumers are paying the price for an over-reliance on this fuel that’s an international commodity subject to price volatility.”

About half of New England’s electricity is currently powered by natural gas, a climate change-contributing fossil fuel that releases greenhouse gas when burned. ISO-New England, the entity that operates the region’s power grid 24/7, has taken heat from advocates working on the energy transition, who claim ISO is making it difficult for renewable energy options to power the grid, and instead, allowing it to remain largely reliant on natural gas.

ISO-New England, however, refutes that claim. Spokesperson Matt Kakley called it “misleading” to point fingers at ISO-New England for the rate increases in question, citing its federal mandate to be fuel and technology-neutral, and delays in clean energy sources, such as wind power, coming online in New England.

Electricity prices are volatile, but more increases in New England not a surprise

In its short-term summer outlook, EIA acknowledges “realized prices can be extremely volatile and average price forecasts can be very uncertain.” But Birchard said the projected increases aren’t a surprise, considering New England’s wholesale electricity prices increased more than 80% in the first three months of 2022.

Citing milder expected temperatures, the EIA is, however, anticipating lower-than-average electricity use this summer, which could offset the soaring prices. For New England, electricity use — or kilowatt hours — could be 5.6% less than last summer, the administration forecasts.

That would be a drastic change from last year, when multiple heat waves gripped parts of the region during the course of the summer. 2021 ultimately became the hottest year on record both in Boston and Providence, Rhode Island.

ISO-New England has cited a developing trend of more “duck curve” days, indicating lower grid demand in the afternoon than overnight. On May 1, ISO said it observed the lowest mark of demand for grid electricity since it began operating the system in 1997 — a combination of “mild temperatures, sunny skies and typically low Sunday demand.”

The grid operator has cited more rooftop solar installations as a leading reason.

“While these changes haven’t happened overnight, a day like May 1 is a good reminder of the progress New England has made in its transition to the future grid,” said Vamsi Chadalavada, ISO-New England’s chief operating officer.

What is the difference between wholesale and retail electricity costs?

Electricity is produced and sold on a wholesale level to energy delivery companies — like Eversource, National Grid and Central Maine Power — and then from there, sold and distributed to individual customers.

Prices vary across the region based on specific utilities and retail distribution. Utility companies operate on different schedules, setting rates based on what low price they’re able to shop from electric suppliers. Rates are then approved by state regulators and the Federal Energy Regulatory Commission.

According to ISO-New England, a consumer’s retail electricity bill reflects the wholesale market price of electricity as a cents/kilowatt hour (kWh) charge, typically shown on a bill as “basic service” or “default service.” That rate is just one piece of a bill. Bills also include charges for delivery and transmission, among other things.

The price of wholesale electricity can change depending on the time of day, season and location in New England, based on factors like price of natural gas and consumer demand. Utility companies typically set rates two or three times per year, abiding by the varying state regulations to protect customers from fluctuations and immediate hikes. Many companies also have long-term contracts in place as a cushion against price volatility.

Wholesale costs ultimately affect individual consumer bills, but there might not be an immediate impact, explained Birchard. But if companies have fuel adjustment clauses in place, that can allow a rate change to occur more quickly.

“Eventually consumers have to pay,” Birchard said, warning about next winter. Though prices will rise, she said individual bills will not see the “same magnitude of the wholesale price elevation.”

The average summer real-time wholesale electricity price for June-August 2021 in the region was $40.22 ($/MWh), according to ISO-New England, during which time the cost of natural gas had more than doubled over the same period in 2020.

Per EIA’s predictions for this summer, New England’s average wholesale electricity price could skyrocket — a 167% increase from last year. EIA is forecasting retail residential electricity customers in the region could see a 16% increase.

William Hinkle, spokesperson for Eversource, New England’s largest energy provider serving Massachusetts, New Hampshire and Connecticut, said the changing costs of demand and global market forces are “directly passed through to customers with no profit to the company.”

Like Birchard, Hinkle cited New England’s “heavy reliance” on natural gas, high demand and rising prices worldwide as driving costs increases locally. Other contributing factors, he said, include previous prices that were at 10-year lows, the war conflict in Ukraine and extreme weather events within the last year that have impacted gas production in states that produce their own natural gas.

Will electricity rates in New England continue to climb?

For National Grid customers in Rhode Island and Massachusetts, summer electricity rates will actually be a reduction from what they were paying before April 1 and May 1, respectively, but an increase over what they paid last summer.

Ted Kresse, spokesperson for National Grid Rhode Island, said they’re anticipating  customers will see a roughly 2% increase compared to summer 2021. National Grid customers in Massachusetts will see closer to 9%. Both supply rates, though, are reductions from what people were paying this winter.

But looking to its Oct. 1 rate change, National Grid is telling its 500,000 customers in Rhode Island to prepare for both residential and commercial rates that haven’t been seen in the state in at least two decades, if ever.

“We’re happy our customers will see some relief on the price of electricity during the upcoming summer months,” said Brian Schuster, director of customer and community management with National Grid Rhode Island. “But… as energy prices remain extremely volatile due to global issues, the outlook for winter electric prices could mean significant rate increases. And while we can’t control the cost of the energy supply, we do want to encourage customers to prepare now for that potential.”

Under the new estimate of 16.8 cents, the residential rate for Rhode Island customers would be more than 50% higher than last winter’s rate, and more than double the current rate that went into effect April 1.

In Maine, state numbers show electricity supply rates have reached the highest levels in at least 10 years. The 2022 supply rate for most Central Maine Power customers went up more than 80%, adding about $30 to the average monthly bill.

The next rate change for Eversource customers in Connecticut and Massachusetts is scheduled for July 1, and Aug. 1 for New Hampshire. The proposed electricity supply rate change for western Massachusetts, for example, is about an 11% increase from the current rate, while the eastern Massachusetts rate is expected to be filed later this month. That’s not a total bill increase, per se, but rather an increase to the supply portion of the bill.

“We know there is never a welcome time for news of higher prices and we work with our customers every day to find payment assistance programsenergy efficiency solutions or other options to help,” said Hinkle.

Eversource customers can use between 25-35% more electricity during hot summer months, Hinkle said. The company encourages customers who are struggling to pay their utility bills to “reach out so that we can help find the best solution for their individual case, even if they have never qualified for or needed assistance before.”

The exorbitant cost of natural gas will persist as long as the Russian invasion of Ukraine does, too, said Birchard, leaving the New England region vulnerable to those price fluctuations. In addition, New England hasn’t taken strides in clean energy alternatives as fast as other regions, she noted.

“In the near term, the region needs to activate demand management tools to reduce costs over the next year,” she said. “During that time, we need to expedite market reforms to reduce our over reliance on natural gas.”

What is ISO-New England’s role?

Birchard asserted that ISO-New England has been “lagging behind.” Five out of six New England states have set strict emissions-based climate goals, and yet, “ISO-New England has made the electric grid increasingly reliant on natural gas rather than accelerating clean energy,” she contended.

“ISO-New England needs to catch up with the states and protect its consumers from these types of (financial) impacts, as well as climate impacts.”

ISO-New England, which is overseen by the Federal Energy Regulatory Commission, is “one part of a regional energy system” that involves state and federal regulators, argued Kakley — a part responsible for administering wholesale energy markets based on federal law.

“When you look at the evolution of the power system over the last 25 years or so, there has been a significant increase of natural gas in New England that has replaced coal, oil and nuclear,” he said. “As we find ourselves looking at the clean energy transition, we’re seeing those older legacy resources retire, but we’re seeing delays on the development and connection of clean energy resources intended to take their place.”

Read the full article in The Providence Journal here

More energy storage is needed to support wind and solar power, MIT study finds

A new report released Monday by researchers at MIT finds that it’s technologically and financially feasible to use energy storage systems, such as massive batteries or hydroelectricity, to almost completely eliminate the need for fossil fuels to operate regional power grids.

Such systems are becoming in greater demand in New England, and beyond, as more renewable energy powers homes and businesses and they require ways to keep the lights on when the sun isn’t shining or the wind isn’t blowing.

“Our study finds that energy storage can help [renewable energy]-dominated electricity systems balance electricity supply and demand while maintaining reliability in a cost-effective manner,” said Robert Armstrong, director of the MIT Energy Initiative, which commissioned the three-year study.

The authors of the report estimated that the costs of transforming power grids in the Northeast, Southeast, and Texas will range between 21 percent and 36 percent higher than if nothing was done to promote storage-backed renewable energy. The costs will be higher in the Northeast, where there are greater energy demands in the winter.

But they described those costs as “relatively modest” and noted there would be many hours when the costs of electricity would be near zero. That means future power grids are more likely to enable the low-cost charging of increased numbers of electrical vehicles and homes with electrical heating systems. They will be able to be charged when prices dip.

“These cost increases are relatively modest compared to the costs of not doing anything, and especially compared to the costs of climate change, which is an existential threat,” said Dharik Mallapragada, one of the authors of the report.

As of 2019, New England had 62 megawatts of battery storage capacity, according to a report last year by the US Energy Information Administration. There are numerous projects that have proposed adding some 6,500 megawatts of energy storage to the regional grid, with more than 630 megawatts of new storage capacity slated to become operational by 2025, according to ISO New England, the regional grid operator.

Joe Curtatone, president of the Northeast Clean Energy Council, said the report underscored that storage can be used in many locations. The report noted that many existing fossil fuel plants could be converted into storage facilities.

“That means energy jobs all over our region, and the best part is it’s ready to be deployed now,” he said. “We don’t need to be wasting time or money on archaic projects, like the proposed Peabody peaker plant. We should be building energy storage to cover our peak power needs.”

The Baker administration has authorized the construction of a 55 megawatt fossil fuel plant in Peabody designed to operate on the coldest and hottest days of the year to add power to the grid when needed.

Some who follow the renewable energy industry said there was little new in the report.

“All of their conclusions seem like concepts that are widely agreed upon in the energy wonk realm,” said Kyle Murray, a senior policy advocate at the Acadia Center, an environmental advocacy group in Boston. “We in the energy realm have been stressing for a long time that cost-effective storage is absolutely essential for our renewable energy future.

Read the full article in The Boston Globe here.