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December 26, 2025

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Nevada Lawmakers Debate ‘30-by-30’ Resolution

A resolution that would express the Nevada legislature’s support for protecting 30% of the state’s lands and waters by 2030 had its first committee hearing on Wednesday.

Assembly Joint Resolution 3 (AJR3) was heard by the Assembly Natural Resources Committee. Committee members asked questions and accepted comments but did not vote on the resolution.

If approved by the legislature, the resolution would urge state and local governments to work with federal agencies to reach a target of protecting 30% of lands and waters in the state by 2030, a goal often referred to as “30-by-30.”

The resolution would also urge local agencies to encourage private landowners to voluntarily participate in land conservation programs.

Reaching the 30-by-30 target would benefit wildlife and help the state meet its greenhouse gas reduction goals, the resolution states.

“Land conservation and restoration increases natural carbon sequestration and is one of the most cost effective solutions to combating climate change,” AJR3 says.

But some committee members wondered whether the resolution should be more specific.

“What does ‘protect’ actually mean?” asked Assemblymember Alexis Hansen (R). “Are we allowed to drive our four-wheeler on it? Are we allowed to camp on it? Are we allowed to graze our cattle on it?”

Christi Cabrera, policy and advocacy director for the Nevada Conservation League, told the committee that different levels of protection could apply to different areas in the state. For example, she said, some levels of protection might allow people to drive vehicles on the land, while other levels would not.

“That’s really the point of this resolution … to start that conversation,” Cabrera said. “Bring stakeholders together and come up with a plan of what can be protected in our state, where those areas are [and] what kind of designations should we be considering.”

Cabrera and the bill’s primary sponsor, Assemblymember Cecelia González (D) presented AJR3 to the committee. The resolution’s joint sponsor is Sen. Fabian Donate (D).

Assemblymember Jim Wheeler (D) wanted to know how the protections called for in the resolution might impact water rights. Cabrera said she didn’t know but would research the issue.

Conservation and business groups submitted a letter in support of AJR3. Among the 18 people who signed the letter were representatives of the Nevada Wildlife Federation, the Nature Conservancy, Patagonia and the Nevada Outdoor Business Coalition.

“A statewide 30-by-30 initiative can position Nevada as a leader in conservation,” the letter said. “Not to mention, conserving lands will help support a booming recreation economy that already contributes significantly to our state’s revenue, boosts local businesses and creates jobs.”

Opponents of AJR3 include a group called Nevada Families for Freedom, which said the resolution does not take into consideration grazing and mineral rights on federal land in the state.

“In addition, almost all the water in Nevada already has legal water rights attached, and there is no water for this outlandish resolution to lock up,” the group said in a letter.

If approved, the resolution would be sent to federal officials including President Biden and Nevada’s Congressional delegation, as well as Nevada Gov. Steve Sisolak and the state Department of Conservation and Natural Resources.

The goal of protecting at least 30% of U.S. lands and ocean by 2030 is part of an international conservation movement. In addition to backing from environmental groups, the 30-by-30 initiative is gaining support from politicians.

California Gov. Gavin Newsom in October issued an executive order setting what his office called a first-in-the-nation goal to conserve 30% of the state’s land and coastal water by 2030 to fight species loss and ecosystem destruction.

Seventy mayors from 29 states and the District of Columbia signed a letter supporting the 30-by-30 initiative, the League of Conservation Voters reported.

Biden has already indicated his support for a 30-by-30 initiative. In a Jan. 27 executive order, he directed the Interior Secretary to come up with recommendations on how the U.S. could meet a 30-by-30 target.

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Mass. Utilities Plan May RFP for 1.6 GW of Offshore Wind

Massachusetts utilities are planning to seek bids for up to 1,600 MW of offshore wind energy in May.

Eversource Energy, National Grid, Unitil and the Massachusetts Department of Energy Resources (DOER) on Wednesday jointly filed a draft request for proposals with the Massachusetts Department of Public Utilities (DPU).

The RFP would be issued May 7, with contracts submitted for DPU approval by April 27, 2022.

In a letter to DPU Secretary Mark Marini on Thursday, DOER said the draft RFP reflects changes from previous offshore wind RFPs based on public comments, consultation with state agencies and lessons learned from prior solicitations.

offshore wind
A new 1.6-GW offshore wind request for proposals in Massachusetts will help grow a U.S. market that currently consists of one operating project — the Block Island Wind Farm off Rhode Island, seen here. | Deepwater Wind

“The draft RFP allows for larger project bids and places a greater emphasis on economic development, diversity, inclusion and environmental justice,” DOER said Thursday on Twitter.

Among the changes is the removal of preferred bid sizes. The draft RFP seeks between 400 and 1,600 MW of total generation capacity, and bids can range from 200 to 1,600 MW.

“By allowing larger bid sizes than prior rounds, a bidder should have more flexibility to design bids to efficiently and cost-effectively use available lease areas, interconnection points, transmission cabling and other infrastructure,” DOER said.

Bid Quality

This solicitation also will be the first-time bidders must address equity in their submissions.

A quantitative and qualitative analysis, weighted 75 and 25 points, respectively, set in previous RFPs would be adjusted to 70-30 to put more emphasis on diversity, equity and inclusion, as well as economic benefits and socioeconomic impacts from siting, according to the draft RFP.

“DOER worked with state agency partners on an RFP provision to direct bidders to submit a workforce diversity plan and supplier diversity program plan that outlines their commitments to actively recruit and promote opportunity for a diverse set of workers and businesses,” DOER said.

The draft RFP also requires bidders to demonstrate commitments to economic development through, among other things, investments in offshore wind-related supply chains, port facilities, research, science and data collection, and environmental justice communities. Project plans will need to mitigate environmental burdens on environmental justice populations, engage with these communities, and track and report on how they are impacted. In addition, plans must show how the project will deliver benefits to low-income ratepayers without adding cost through, for example, energy efficiency and renewable energy upgrades, or rate relief.

Price Cap

As proposed, the RFP would require bidders to submit a price below $77.76/MWh, the price of the previous solicitation’s winning bid by Mayflower Wind. National Grid, however, proposed in the filing that the final RFP include a provision that would reduce the price cap in the event Mayflower goes into service and qualifies for the 30% offshore wind investment tax credit (ITC). The credit was part of renewable energy tax credits included in the COVID-19 stimulus bill signed into law in December.

Mayflower said in January that converting the value of the ITC into a price reduction for electricity generated by the offshore wind farm would reduce its bid price to $70.26/MWh.

Since bids for the latest solicitation would be prepared before an ITC determination is made for Mayflower, National Grid proposed an alternate bid structure. Any bidder would need to provide an alternative price that is lower than $70.26/MWh, if its first bid is between $70.26 and $77.76. DPU will issue a finding on National Grid’s proposal in its final order on the draft RFP.

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Electric Heating Bill Passes Wash. House

The Washington House of Representatives passed a bill Tuesday to encourage all-electric heating designs in publicly owned or leased facilities.

The Democrat-controlled House approved House Bill 1280 by a 57-39 party-line vote. It is now in the Senate Environmental, Energy & Technology Committee.

When publicly owned or leased facilities are built or renovated, the bill would require that an all-electric design — one that would not use fossil fuels for heating — be considered as an option.

Rep. Alex Ramel (middle) is chief sponsor of a bill that would require publicly owned or leased facilities to consider implementing an all-electric heating design during construction or renovations. | State of Washington

“House Bill 1280 takes one small but important step in that direction,” said Rep. Alex Ramel (D), the bill’s chief sponsor. He noted that an all-electric design was installed during the renovation of an elementary school in his hometown of Bellingham — the only time that he is sure this has been done in Washington.

Only a few people from state agencies and energy-conservation organizations testified at two February hearings, all in support of the bill. No one testified against it. Supporters contended the bill would not add any significant costs to new or renovated buildings. They also said all-electric heating systems are cost-efficient and that installing such systems would head off potential later retrofits.

“This will encourage architects to design buildings free of fossil fuels,” Julie Blazek of HKP Architects said at a Feb. 17 hearing. During a Feb. 19 Capital Budget Committee vote, committee Chair Steve Tharinger (D) said: “This does provide some data and guidance” in comparing building designs.

However, Rep. Mary Dye (R) argued that all-electric heating systems are less efficient and reliable than fossil fuel systems, leading to extra costs for taxpayers footing the operating bills. Rep. Mike Steele (R) said all-electric buildings would put extra strains on the Northwest power grid.

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DOE Urges Stakeholders to Rethink Value of Storage

The U.S. Department of Energy is encouraging long-duration energy storage (LDES) owners, those who purchase their services and state governments to rethink how those assets are valued.

LDES, defined as any resource that continuously operates for more than six hours, is all about mitigating risk, Max Tuttman, technology-to-market adviser at the department’s Advanced Research Projects Agency-Energy, said during a virtual “workshop” on energy storage hosted by DOE and several National Laboratories. “It’s the ultimate risk mitigation asset.”

Tuttman believes that LDES developers have to learn to adjust their thinking away from how their technologies provide value to the grid, to understanding how they can provide value to customers. LDES, for example, can bring value through “portfolio balancing” by acting like insurance, Tuttman said.

“Insurance is a product that you pay for that you hope to not use very much, and that you actually don’t expect to have a positive long-term return on,” he said. “Similarly, long-duration storage — if you have a portfolio of other assets, be those generators or load — can play an important role in managing the risk profile of that portfolio.”

DOE energy storage
Policy and regulations can create barriers to market entry for long-duration energy storage, like pumped hydropower facilities. | Shutterstock

Delivering that level of risk management creates value for different customer types, such as data center owners, renewable energy developers or load-serving entities.

“It’s important for technology developers to understand what the source of revenue is for those customers and then understand how long-duration storage can provide value to those customers in the context of their existing business models,” Tuttman said.

LDES also can provide value through asset substitution, he said.

The owner of a utility-scale solar project in California, for example, is using storage to flatten load and lessen transmission congestion, rather than pay for costly network upgrades. In this case, Tuttman said, the developer is replacing a transmission asset with a storage asset.

“You’re using [LDES] to offset the cost of a different asset,” he said. “So instead of keeping a power plant around for reliability, you now have energy storage for reliability.”

Policy Concerns

The way that policymakers and regulators currently value LDES creates barriers to market entry for the technology, Erin Childs, senior manager at Strategen Consulting, said during the workshop. In California, for example, rules for resource adequacy do not provide capacity credits for storage beyond four hours.

“Storage resources that are able to provide longer durations of dispatch really receive no benefits or no compensation for that,” she said. “There is a need to harmonize our capacity and our planning requirements with what we see the grid needing in the longer term.”

LDES companies that Strategen has worked with say they are cost-competitive at six- to eight-hour durations, Childs said. “The market just isn’t buying six to eight hours.”

There is a lot of opportunity for resource adequacy reform, according to Childs, but the process is long and complicated.

“If it takes us five years to do resource adequacy reform, are we willing to wait that long to do any long-duration storage? And if not, then what do we do as we’re getting our market incentives lined up?” she asked.

Childs said that policymakers also need to consider how electric systems will value and compensate much longer storage durations for reserves and reliability.

There is a misperception, she said, that 100-hour storage is just for those days of the year when the sun isn’t shining, the wind isn’t blowing or there are peak demands. Modeling of those longer durations, she argued, show that 100-hour resources charge throughout the year and dispatch 10 months out of the year.

“These are not resources that are put on the shelf … until something really terrible happens,” she said. “They are on the grid; they are dispatching; and there are revenue streams that they can be accessing.”

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FERC Affirms Findings on PJM E&AS Offsets

FERC on Tuesday explained why it declined to act on requests by power generators and public interest groups to rehear a January compliance order on the treatment of energy market revenue calculations in PJM’s capacity auctions (EL19-58-005).

The rehearing requests — one filed jointly by Exelon and Public Service Enterprise Group — were automatically denied in January when FERC failed to act on them within the requisite 30 days.

At issue is the implementation of PJM’s net energy and ancillary services (E&AS) offset calculation used to help estimate the net cost of new entry (CONE) for resources in the RTO’s Base Residual Auction. The offset “is designed to model net revenue that a ‘representative resource’ would earn during its first year of commercial operation,” according to PJM.

FERC last November approved the details of PJM’s offset calculation, which draws on energy market results from the three calendar years before the BRA to inform modeled offers for resources. (See FERC Approves PJM Key Capacity Market Variable.) As noted by Chair Richard Glick in a concurring statement to Tuesday’s order, approval of the offset allows PJM to conduct “its long-delayed, much-needed capacity auction,” the subject of enduring disputes over the treatment state-sponsored resources.

But the commission had also directed PJM to allow combustion turbine resources to reflect in their E&AS offsets a 10% adder to account for “the additional costs and risks that may be incurred by operating the CT reference resource in a manner that fully recognizes flexibility, which is not limited only to peak hours or times of system stress.” No other resources would be eligible to include the adder.

PJM was also ordered to use historical prices to forecast operating reserve and regulation dispatch and revenues for capacity resources, variables also used in the calculation of the E&AS offset for all resources.

PJM Energy and Ancillary Services
FERC headquarters | © RTO Insider

Exelon, PSEG and a group of public interest and customer organizations (PICOs) in PJM, however, petitioned FERC to reconsider those directives. (FERC staff on Jan. 4 accepted PJM’s compliance filing implementing them in a delegated order.)

The PICOs argued that the 10% adder would unjustifiably increase net CONE for CT resources and drive up costs for ratepayers. They also contended that the use of historical operating reserve prices would underestimate the future revenues capacity resources would earn based on recent market changes.

FERC responded by noting “that PICOs’ rehearing arguments opposing the adder are repetitive of arguments that the commission previously considered and found unpersuasive” in a quadrennial review of PJM’s variable resource requirement curve. “We continue to find adequate evidence in the record to demonstrate that including the 10% adder results in a just and reasonable approximation of the costs for a CT unit.”

In rejecting the PICOs’ opposition to the use of historical prices, the commission said it “selected PJM’s proposed approach as a just and reasonable replacement rate given the lack of a futures markets for reserves and uncertainty regarding the actual reserve price impacts of PJM’s reserve market reforms.”

Exelon and PSEG attacked the plan from the other direction, objecting to the fact that the 10% adder wouldn’t be available to other resources. The companies also contested the use of historical prices, arguing that past performance in the small regulation market was not a good indicator of future revenues.

FERC gave these arguments similar treatment: “As the commission explained in the compliance order, PJM reasonably excluded the 10% adder from the modeled offers of combined cycle units and other resources, such as coal units, because, unlike CTs, those resources ‘do not significantly alter their operating schedules based on evolving conditions between the day-ahead and real-time markets.’”

The commission also rejected the generators’ concerns about the use of historical prices. “Contrary to the rehearing arguments of Exelon/PSEG, the use of scaled historical prices to estimate future regulation prices is consistent with the directive in the May 2020 order to use a forward-looking E&AS offset,” FERC said.

Clements Dissents

Despite the commission’s approval, a majority of the commissioners seemed to agree that the petitioners’ arguments had merit.

But Chairman Glick and Commissioner Mark Christie essentially overruled a dissent by Commissioner Allison Clements, arguing that it was imperative that PJM run the BRA for the 2022/23 delivery year.

Clements wrote that there is a “paucity of record evidence” to support the 10% adder. She disagreed with the commission’s assumption that PJM’s application of the adder and use of historical reserve prices “will yield just and reasonable capacity rates;” rather, they could have “material real-world consequences” because they feed into the net CONE value.

Clements pointed to the PICOs’ assertion that PJM’s 10% adder translates to a daily increase in net CONE of roughly $30/MW, which is nearly 12% of the recently posted RTO-wide per-day figure of $260.50/MW for the 2022/2023 BRA. These estimates “translate to significant additional capacity costs to customers,” she said.

Glick acknowledged that Clements “makes a number of good points” but said that “the real problem lies with PJM’s misguided choice of the reference resource to calculate net CONE, rather than in how it implemented the forward-looking E&AS offset in this proceeding.”

FERC has “meddled with one aspect of PJM’s capacity market after another,” said Glick, who has “dissented at nearly every turn” in the capacity market proceedings, arguing that “truly bad public policy” produces rates that are “patently unjust and unreasonable.”

“With that in mind, now is not the time to once again pull the rug out from underneath the auction,” Glick said. He added that there is no “superior alternative to PJM’s proposal to use historical reserve prices as the basis for projecting future reserve revenues.”

“Were such an alternative available, I agree that it would merit a hard look,” Glick said. “But as it is not, we must provide PJM with the certainty it needs to finally run the upcoming auction and then, with that behind us, turn to remedying the more fundamental problems that the commission has created over the course of the last three years.”

Christie said he shared Clements’ concerns about the adder but is “convinced any such changes at this stage would threaten — or indeed obstruct — the ability of PJM to conduct the Base Residual Auction as scheduled this May, which is essential for reliability purposes.”

He added that “the PJM capacity market is not a true market, but is, instead, an administrative construct whose very complexity is inconsistent with transparency.” He said he has been “vocal” about considering the issue in a “general proceeding” such as a technical conference.

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Senators Grill Robb, Asthana over Texas Outages

The February winter storm and resulting dayslong outages in Texas loomed large over Thursday’s meeting of the Senate Energy and Natural Resources Committee, with members pressing representatives of the electricity sector for an explanation of the events and assurances that they are working to prevent future mass failures.

Senate Texas outages
Sen. Joe Manchin (D-W.Va.) | U.S. Senate

However, the committee emphasized that they were not interested in scapegoating a single state. Senators described last month’s disaster — when at one point nearly 49% of total installed generating capacity within ERCOT was unavailable and the operator came “seconds and minutes away” from complete breakdown — as a wake-up call about the vulnerability of the entire national grid. (See ERCOT was ‘Seconds and Minutes’ from Total Collapse.)

“[Let] me be clear: Today’s hearing is not a referendum on Texas,” Chair Joe Manchin (D-W.Va.) said in his opening remarks. “We’ve seen the impact of extreme weather events to our electric grid across the country … [and] we need to incorporate all of the lessons learned from those events into our future planning, particularly as we can expect both our energy mix and weather patterns to be different in the next decade than they were in the last decade.”

NERC CEO Jim Robb expanded on this theme in his written testimony, citing several weather-related incidents in recent years — including the August 2020 heat wave that led to rolling blackouts in California and grid emergencies in other Western states — to argue that no region is immune to disruption. (See WECC Findings Show Complexity of Heat Wave Event.) As severe weather events become more frequent, grid planners will have to be proactive about preparing their systems for stronger impacts.

No Universal Solution

NERC CEO Jim Robb | U.S. Senate

What form that preparation might take was a major topic of questioning, with senators bringing up a variety of measures to ask what impact they might have had on the resilience of the grid during the weather events that Robb mentioned. Hypothetical improvements raised by senators included building out natural gas and other traditional assets to offset the purported unreliability of wind and solar facilities; implementing capacity markets to incentivize generators to make more resources available for potential surges; and expanding or improving transmission facilities to remove bottlenecks between supply and demand.

Attendees generally agreed on the need for more transmission, but they were more reluctant to endorse other recommendations in light of different regional needs. PJM CEO Manu Asthana acknowledged that his RTO’s capacity market was designed to prevent the kind of instability that gripped Texas in February, but he warned that the solution was not likely to be so simple.

“It’s easy to think, ‘Oh, if only Texas had a capacity market, this wouldn’t have happened,’” Asthana said. “I think Texas would have had a higher reserve margin [in that event], but it’s important to note that … Texas had reported a reserve margin for this winter of 43%” in NERC’s Winter Reliability Assessment. “And so it was not a shortage of capacity; it was this incredibly cold weather for which the capacity was not prepared.” (See NERC Warns of Fuel Bottlenecks in Coming Cold Months.)

Texas Faces Heat on Winter Prep

Senate Texas outages
Sen. Mazie Hirono (D-Hawaii) | U.S. Senate

Several members seized on that lack of preparedness, using Robb’s observation that FERC and NERC had issued a cold weather preparedness guideline following the 2011 cold weather event in Texas and Arizona to suggest, in the words of Sen. Mazie Hirono (D-Hawaii), that “they probably didn’t follow your recommendations very well.”

Robb was guarded in his response to Hirono. While he acknowledged that the cold weather preparedness standard currently under development at NERC “no doubt … would have helped” in last month’s crisis, he reminded members that the situation was extremely complex. For this reason NERC and FERC are conducting a joint inquiry to establish the exact causes of the outages.

“I think one of the things that … we will uncover through this inquiry is … if the power plants were weatherized adequately for the conditions that were in place, whether the … natural gas system in Texas would have been able to deliver fuel to those plants,” Robb said.

Senate Texas outages
Sen. John Barrasso (R-Wyo.) | U.S. Senate

Several committee members used the February outages as a way to argue that the transition to renewable generation resources must not be pursued too hastily. Ranking member John Barrasso (R-Wyo.) said in his opening statement that utilities “must work with the grids we have today, not with the grids we wish [for] in 15 or 25 years,” and that traditional generation must be a part of the national energy strategy for the foreseeable future.

“Increasingly the national discussion on electricity has centered around a single metric: how much greenhouse gas does the source of electricity provide,” Barrasso said. “The discussion has failed to pay sufficient attention to the questions of reliability, resiliency and affordability. … We must ensure that our grids can provide electricity at all times, and at prices that American families and businesses can afford. The American public deserves to know what policies and measures are necessary to ensure that that happens.”

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Natural Gas Use Expected to Rise in NY

New York will see an increase in new natural gas plants and the hours of operation of existing gas plants after the state’s Indian Point Nuclear Energy Center closes in April, New York State Energy Research and Development Authority Board Member John B. Rhodes said Wednesday.

However, the long-term role of natural gas in the state’s energy grid is still unknown, he said during a webinar in Our Energy Policy’s Energy Leaders series.

As states in the Northeast grapple with balancing decarbonization with energy reliability and affordability, there is a possibility that thermal power generation, or energy produced by burning liquified natural gas to convert it into electric energy, “needs to be a part of that mix,” Rhodes said. But other solutions, such as battery storage and dynamic load, or adjusting the load demand on the electrical power grid to balance overall grid load with generation, are promising alternatives.

“Our pathway to backing down gas from the power grid is much clearer than it is for heat,” Rhodes said.

New York Natural Gas
As large renewable energy projects ramp up in New York, the state will see a near-term increase in natural gas power plants, such as the one seen here in New York City. | Shutterstock

Rhodes is confident the state will reach its goal of 70% renewables by 2030 set by the Climate Leadership and Community Protection Act in 2019, but “it’s always the case that the last megawatt-hours are the hardest to get.”

The phase out of natural gas from the heating industry, however, has a solution gap, Rhodes said. “Buildings in general are a tough sector for energy transition.”

According to Rhodes, the building sector is not centered on how buildings use energy; it is centered around serving the people that are in them.

Investing in Mitigation

Another challenge to weaning the heating sector off oil and natural gas is buy-in from consumers, Kyle Kimball, vice president of government, regional and community affairs at Consolidated Edison, said during the webinar.

“One of the biggest challenges is uptake — or getting the building decision maker or homeowner to say yes to upgrades” that would improve heat insulation, Rhodes added.

| © NetZero Insider

Property owners can be hesitant to go through the disruption that structure upgrades can entail. But consumer attitudes are changing.

A new poll by the MassINC Polling Group, sponsored by the Barr Foundation and conducted with input from the Massachusetts Executive Office of Energy and Environmental Affairs, found that residents are highly supportive of policies that would help them upgrade their homes, especially incentives for utility companies to help make customers’ homes more efficient.

Although most residents are satisfied with the heating setup they already have, the poll found evidence that those who have made the switch to renewables are glad they did. And a third of those who currently heat their homes with electricity from the grid say their top choice would be electricity that comes from solar.

Rhodes said that in his experience the “awareness and appetite to invest to avoid climate change is a lot higher in 2021 than it was in 2013.”

There remains, however, room for innovation in improving a building envelope practically and affordably to move away from energy sources like natural gas, Rhodes said.

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NJ Regulators Give Microgrid Projects a Thumbs Up

Proposed microgrids in Atlantic City and seven other locations took another step toward reality after the New Jersey Board of Public Utilities (BPU) last week approved $4 million in subsidies for the projects.

The Atlantic City project being developed by independent power producer DCO Energy would provide emergency backup power to Caesars Atlantic City Hotel and Casino, Bally’s Hotel and Casino, The Claridge hotel, Boardwalk Hall — best known as the traditional home of the Miss America pageant — local shops and the city’s main hospital.

The project will involve a retrofit to increase the capacity of the Midtown Thermal Control Center, which currently provides heating, cooling and emergency power to casinos and other facilities, to 19.3 MW.

The BPU’s awards were the result of a two-part competition that began in 2017 under the Town Center Distributed Energy Resources Microgrid Design Incentive Program. Besides Atlantic City, subsidies went to Montclair Township, the Borough of Highland Park, Hudson County, the City of Hoboken, Neptune Township, Woodbridge Township and the New Jersey Department of the Treasury on behalf of the City of Trenton. Atlantic City’s $1.1 million grant was the largest award.

The Atlantic City microgrid will involve a retrofit to increase the capacity of the Midtown Thermal Control Center, which currently provides heating, cooling and emergency power to casinos and other facilities, to 19.3 MW. | DCO Energy

The BPU said the eight projects would provide resilience to 24 Federal Emergency Management Agency Category IV facilities (including hospitals, fire and police stations) and 32 FEMA Category III facilities (including educational facilities and other buildings where more than 300 people congregate).

“In addition, they would deploy 10.5 MW of new or existing solar PV generation and 2.9 MW of new or existing battery storage, resulting in over 24,000 tons of avoided CO2 emissions annually,” the BPU said.

New Jersey’s interest in microgrids dates back to 2012 when Superstorm Sandy battered the state.  After making landfall with hurricane-force winds near Atlantic City, the storm devastated the Jersey Shore, causing major flooding and power outages that left millions in the dark for days. Public Service Electric & Gas, the state’s largest utility, estimated Sandy did about $300 million in damage to its transmission and distribution system. According to IHS Global Insight, the storm, which also hit New York City, caused as much as $30 billion in property damage, making it one of the costliest natural disasters in U.S. history.

“As the recent events in Texas have reminded us, infrastructure resilience is critical to maintaining reliable energy and utility services in the event of an emergency. We learned this ourselves during and after Superstorm Sandy,” said BPU President Joseph Fiordaliso at the board’s March 3 meeting. “But we are moving in a direction that hopefully will never allow what happened in Texas to happen here in New Jersey.”

Power disruptions in Texas and California have brought new attention to microgrids. ERCOT, the nonprofit manager of Texas’ grid, fired CEO Bill Magness last week after the system nearly collapsed during a winter storm that left millions without power. (See ERCOT Board Cuts Ties With Bill Magness.) In January, the California Public Utilities Commission ordered the state’s investor-owned utilities to offer a $200 million microgrid incentive program to communities at risk of public safety power shutoffs because of wildfires. (See Calif. PUC Orders $200M Microgrid Incentive Program.)

Microgrids haven’t been an easy sell to utilities, which see them as a threat to their traditional monopoly business, according to Guidehouse Insights Research Director Peter Asmus, who tracks the microgrid industry.

“Most microgrids are not deployed by utilities,” Asmus wrote in an email. “As such, they are often not located in ideal locations to bolster the resiliency of the larger grid, though that is changing as microgrids can serve as excellent demand response resources. And given recent outages linked to extreme weather — such as in Texas — the need for greater resiliency is clear. But utilities worry that these microgrids are not directly under their control, could perhaps impact the larger grid if they don’t operate properly, and could result in a loss of revenue. ”

The microgrid would provide emergency back-up power to Caesars Atlantic City Hotel and Casino; Bally’s Hotel and Casino; The Claridge hotel; Boardwalk Hall, local shops, and the city’s main hospital. | Google

According to Adam Benshoff, vice president for regulatory affairs at the Edison Electric Institute, utilities often have problems persuading regulators to allow them to recoup the costs of microgrids in rates.

“They’ve had trouble even getting approval for sort of public purpose microgrids — one that will just keep critical online infrastructure like hospitals, police stations fire stations, things like that,” Benshoff said in an interview.  “Sometimes it’s difficult to sell unless you can show real value to the broader customer base.”

DCO acquired the Midtown Thermal Control Center in 2016 from Pepco, the parent company of local utility Atlantic City Electric. According to DCO Chairman Frank DiCola, the biggest challenge facing the company in getting the microgrids established is getting Atlantic Electric to agree to it.

“We need them to work with us in establishing the microgrid,” DiCola said in an interview, adding that he had no reason to expect any problems with the utility company. “But you never can tell,” he added. “We have been talking to them on-and-off for the past couple of years. We want to work in a very cooperative manner with them. They are part of the solution.”

Pepco told NetZero Insider that it was committed to microgrids and other technologies that will bolster the company’s grid reliability,

“As with all projects on our system, we will continue to engage with the project developer and refine this microgrid project to ensure it is in the best interest of our customers and will not affect our ability to provide clean, safe, affordable and reliable energy service for our customers,” it said.

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Vote on Mass. Climate Bill Delayed in Senate

Massachusetts Senate Minority Leader Bruce Tarr (R) on Thursday delayed the vote on an exhaustive climate bill after lawmakers reworked the text to incorporate amendments from Republican Gov. Charlie Baker.

Tarr called for more time for legislators and the public to review the new version of the bill after the changes were released late Wednesday.

Senate Democrats expressed their disappointment that the vote was delayed. The bill has been more than a year and a half in the making in the legislature and would serve as one of the leading mandates for reducing carbon emissions in the U.S.

“Human beings are already too late in responding to human-made problems caused and represented by climate change,” Sen. Michael Barrett (D), lead on the climate bill, said on the Senate floor.

The version of the bill up for a vote maintains several of Baker’s provisions in the amendments he sent back to the legislature in early February, including a specialized energy code that will enforce net-zero building construction for towns that want it. The bill also sets mandatory emissions limits in the transportation, manufacturing and natural gas sectors. (See Baker Returns Climate Bill to Mass. Legislature.)

The latest delay of a comprehensive climate bill for Massachusetts took place Thursday in the Senate, seen here, where Republican lawmakers held up a planned vote. | Montanabw, CC BY-SA 4.0, via Wikimedia Commons

Baker attempted to loosen legal requirements for specific business sectors to meet emissions reduction goals, suggesting the requirements serve as “planning tools” or guidelines for industries, a move supported by the influential employer group Associated Industries of Massachusetts.

The governor also faced pushback from the real estate industry, which called on him to oppose provisions that would allow towns to adopt rules requiring that new buildings meet net-zero emissions. Developers expressed their concerns to Baker about the increase in upfront costs for construction.

“There is always an interest group working through their elected representatives to keep things moving at a painfully slow crawl,” Barrett said on the Senate floor.

Sen. Michael Rodrigues noted that in his 25 years in government, the state legislature has never held a hearing on amendments proposed by the governor’s office for other pieces of legislation.

“We are on the cusp of a sustainability revolution in this nation and in the world,” Sen. Marc Pacheco (D) said. “We can either lead as this bill allows us to do, or we will be behind China and other countries.”

Massachusetts lawmakers held firm on their target of reducing 50% of emissions below 1990 levels by 2030 after Baker proposed reducing emissions by 45% below 1990 levels. Baker claimed the higher target would cost the state $6 billion dollars more than a 45% target.

Environmental advocates in Massachusetts, such as Craig Altemose of the Better Future Project, told NetZero Insider that even 50% by 2030 is not enough to limit the Earth’s warming below 1.5 degrees Celsius.

New language in the bill also incorporates Baker’s amendment to strengthen protections for environmental justice populations by enforcing a cumulative, holistic impact analysis when building new infrastructure.

The climate bill will be brought to a vote in the next Senate legislative session. If the legislature sends the bill to Baker for his signature and he vetoes it, the legislature is likely to have enough votes to override the veto.

“The majority of the Massachusetts Senate remains prepared to take swift action on this bill,” Sen. President Karen Spilka (D) said in a statement.