Consolidated Edison (NYSE:ED) said Wednesday it has energized the first piece of its Reliable Clean City initiative.
The six-mile, 300-MW power line links the 345-kV Rainey substation with a 138-kV Astoria substation.
Con Ed is building two other power lines in Brooklyn and Staten Island as part of the initiative begun in 2021. Altogether, the three lines have a combined rating of 900 MW, and, with associated substation upgrades, a price tag of approximately $800 million.
When completed in 2025, the three lines will allow for retirement of eight gas-fired peaker units at five other sites across the city by facilitating importation of power generated elsewhere.
With its large nuclear and hydro facilities and a growing number of solar and wind farms, the upstate New York grid is mostly emissions-free. Downstate is densely populated and powered mostly by fossil fuels.
Multiple transmission projects are now in planning or construction stages to bring clean energy to the nation’s largest city from upstate and elsewhere, and to retire the fossil fuel plants blamed for respiratory illnesses in surrounding neighborhoods.
On a similar note, the 558-MW peaker formerly operated by Astoria Gas Turbine Power closed Monday.
The aging plant was denied a state permit to modernize in 2021 because it would not comply with new, stiffer state regulations.
In 2022, the NRG (NYSE:NRG) subsidiary that owned it announced a deal to sell the site to the Equinor-BP entity developing the proposed Beacon Wind project off the New York coast.
The plant will be demolished, and its proposed replacement is the Astoria Gateway for Renewable Energy (AGRE), a 1,230-MW converter station for power generated by Beacon Wind.
In nearby Long Island City, Rise Light & Power is proposing to convert Ravenswood Generating Station, the city’s largest power plant, into a 1,310-MW offshore wind hub. Ravenswood, a longtime target of health and environmental justice activists, has already been partially retired and three more of its generating units totaling 68.6 MW will be retired as Con Ed completes the Reliable Clean City projects.
In a state news release Wednesday, New York Public Service Commission Chair Rory M. Christian tied together the impact of Reliable Clean City and similar projects in the pipeline.
“New York State is in the middle of a fundamental change in the generation and delivery of electricity,” Christian said. “Our priority is ensuring renewable, clean sources are integrated into the grid while polluting sources are being phased out. Given this fact, it is expected that additions and modifications to the utilities’ transmission infrastructure will accommodate the cleaner sources of electricity while ensuring reliability. These are much needed, welcomed changes that will improve all of our lives for the better.”
The Astoria-Long Island City corridor is called “Asthma Alley” in some circles. The construction of the city’s largest power plant a stone’s throw from two of its largest public housing complexes is an example of the environmental injustice that is a parallel target of New York’s clean energy transition efforts.
Queens Borough President Donovan Richards Jr. alluded to this in a Con Ed news release:
“Queens is done with the days of disinvestment in our health — both the health of our families and the health of our environment. There is no mission more critical than our transformation into a borough run on renewable energy, and Con Edison’s Reliable Clean City Project represents a significant step toward that goal. I look forward to working with Con Edison and all of our partners to ensure that Queens becomes a global leader in the fight against climate change and environmental injustice.”
Three Indiana utilities could save their customers a combined $73 million if they scrapped plans to build new gas plants and invested in battery storage instead, according to a new report released Tuesday.
Strategen Consulting, a firm specializing in decarbonizing the grid, concluded Northern Indiana Public Service Co. (NYSE: NI), CenterPoint Energy (NYSE: CNP) and Indiana Michigan Power (NYSE: AEP) should discard plans for new natural gas-fired combustion turbines in their recent integrated resource plans and add 366 MW to 1,156 MW of battery storage instead.
The firm said the utilities could achieve comparable grid reliability with storage. It said the Inflation Reduction Act (IRA), volatile natural gas prices, and MISO’s shift to a new availability-based capacity accreditation for thermal resources mean that gas plant construction doesn’t make economic sense.
“The IRA has dramatically shifted the energy planning space and requires all utilities to reassess their prior plans,” Strategen wrote in the report. “The economic incentives for building clean energy resources provide new opportunities for utilities to provide their customers the most competitive rates while also achieving their clean energy and climate goals.”
The firm analyzed savings potential in battery systems’ first year of deployment based on when the utilities expected to add the gas plants. It found:
CenterPoint Energy could save its customers $3.5 million in 2025 if it replaces a planned 460-MW gas plant with 551 MW of four-hour battery storage;
NIPSCO could achieve savings of $3.43 million in 2027 by replacing an envisioned 300-MW gas plant with 366 MW of storage; and
Indiana Michigan Power could save $66.17 million in 2028 if it swaps its planned 1,000 MW gas plant for 1,156 MW of storage.
Strategen said it didn’t account for gas plants’ stranded asset risk in its findings. The firm said it anticipates savings in subsequent years will be even larger.
The report is a companion to Strategen’s February study that found Duke Energy Indiana could save ratepayers $68.5 million in the first year if it traded its plans for a new gas plant for wind, solar and storage resources. The Advanced Energy United trade association commissioned both studies.
Strategen said advanced energy technology has become cheaper since the utilities finalized their IRPs in 2020 and 2021.
“There has never been a better time for Indiana to look beyond a business-as-usual approach and modernize its energy grid by replacing polluting fossil fuels with low-cost, plentiful clean energy,” Strategen’s Ed Burgess said in a press release.
The firm said though natural gas plants have historically been the generation of choice for emergencies, “recent performance and availability of natural gas plants warrants a serious reconsideration of this preference, as evidenced in MISO and PJM in the latest winter storms.”
It said if combustion turbines cannot be depended on “during the most crucial hours, their value to the utility and overall system reliability drops dramatically.”
“Indiana utilities are on the verge of committing many hundreds of millions of their customers’ dollars on expensive and outdated technology when there are better, lower-cost, and lower-risk alternatives,” said Trish Demeter, Advanced Energy United’s managing director. “Indiana utilities made their plans to build these costly power plants back before fuels got more expensive and renewable energy technologies got a whole lot cheaper. This analysis shows advanced energy tech provides a more affordable path to building a reliable and modern electric grid for Hoosiers.”
WASHINGTON — FERC’s recent efforts to approve certificates for natural gas infrastructure won praise from both sides of the aisle at a Senate oversight hearing Thursday, but the ongoing transformation of the grid generated debate.
The gas industry built the lowest level of infrastructure last year since the Energy Information Administration began tracking the numbers in 1995, said Energy and Natural Resources Committee Chair Joe Manchin (D-W.Va.).
“I’m glad the FERC appears to have heard the concerns last year from everyday Americans and from members of Congress,” he added. “We’re starting to see FERC make decisions at a better pace. FERC approved more than 10 Bcfd of natural gas pipeline capacity and nearly 6 Bcfd of LNG export capacity over the last 12 months; combined, that’s more than triple the capacity FERC approved during the 12 months prior.”
Ranking Member John Barrasso (R-Wyo.) praised interim FERC Chair Willie Phillips for moving more projects under his leadership.
“Chairman Phillips, I commend you for resetting the commission’s agenda,” Barrasso said. “You have brought orders forward for discussion and for action; you have emphasized energy reliability and affordability.”
The praise from the committee contrasted with when Richard Glick was chair and tried to get the commission to consider the global warming impacts of natural gas infrastructure by issuing two policy statements that were ultimately withdrawn after significant criticism. The issue ultimately helped sink his nomination for a second term late last year. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)
Both Republican members of the commission said they were worried about a looming reliability crisis as the grid continues to transform with more renewables coming online and fossil-fueled power plants shutting down.
Commissioner James Danly placed the blame for ongoing reliability risks on FERC’s “maladministration” of the markets.
“FERC has distorted price signals and warped incentives in the markets, interfering with price formation and jeopardizing resource adequacy,” Danly said. “Most of these market-distorting forces originate with subsidies — both state and federal — and from public policies that are otherwise designed to promote the deployment of non-dispatchable wind and solar assets or to drive fossil-fuel generators out of business as quickly as possible.”
The subsidies enable renewables to bid at zero, or lower, and that brings down prices, which in turn leads to early retirements for fossil power plants. Danly opposed the elimination of the minimum offer price rules, which he said were their “economic guardrail.”
Commissioner Mark Christie said that the problem was not with the addition of renewables, but the early retirements of dispatchable power plants.
“The United States is heading for a reliability crisis,” Christie said. “I do not use the term ‘crisis’ for melodrama, but because it is an accurate description of what we are facing. I think anyone would regard an increasing threat of systemwide, extensive power outages as a crisis.”
Even though the commissioners might describe the grid’s transition differently, Christie later said that when it comes to the Federal Power Act, partisan differences rarely matter.
“All four [of us are] lawyers, and that means we have 16 different opinions,” Christie said. “But you know, we only need three votes to get something out and the business is getting done.”
When it comes to the FPA and issues around organized markets, any disagreements generally do not fall along the normal partisan faults, so the commission has been able to find three votes and get orders out, he added.
Phillips listed reliability as FERC’s most important job, and he highlighted the progress the commission has made in addressing issues such as cybersecurity and preparation for extreme winter weather. He also focused on FERC’s efforts to reform transmission planning and operating rules.
“My highest priority in the near term is to finalize a proposed rule that will greatly improve our processes for interconnecting new electric generating resources, reducing the time it takes to bring those resources online,” Phillips said. “In addition, we are working to finalize a second proposed rule on how to plan and pay for badly needed regional electric transmission facilities.”
Sen. Martin Heinrich (D-N.M.) asked whether FERC had plans to address rules around interregional transmission along with its pending proposals on interconnection queues and regional transmission planning.
“Absolutely; I’ve talked about interregional transmission since I was on the commission,” said Phillips. “You don’t have to look any further than recent extreme weather events to see how critically important it can be to maintaining the reliability of the grid.”
Heinrich also urged FERC to avoid re-imposing any federal rights of first refusal in its rule changes. The commission proposed a limited ROFR for joint projects where utilities work on a line with an unaffiliated company, but Phillips said he was open to changing that in the final rule.
“Should these rules be finalized, I expect they will reduce customer costs over time and improve reliability outcomes,” Commissioner Allison Clements said. “Meanwhile, my colleagues and I continue to discuss transmission system matters with state utility regulators at the Joint Federal-State Task Force on Transmission, and I expect the finalized transmission rules to reflect lessons learned at those collaborative sessions.”
In the West, the industry is increasingly working together across the entire interconnection as they deal with the transforming resource mix and more frequent extreme weather events.
“I’ve been really pleased to see the development in the West over the last five years. State regulators across the region, as well as state legislatures across the region, have identified how do we protect customers and reliability on a forward-looking basis,” she said. “And so, they have been thinking deliberately and carefully about developing markets.”
Most of the interconnection is in one of the nascent energy balancing markets now, and those are being extended to offer day-ahead services, while the states continue to consider joining an RTO, Clements said.
While FERC is moving ahead on transmission on its own, several senators noted that they are working on efforts to “reform” the permitting process, with Manchin saying projects need to be developed much more quickly. He has reintroduced a bill that failed to pass last session. (See Manchin Permitting Bill Falls Short in Senate.)
Barrasso and Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Environment and Public Works Committee, released another permitting bill Thursday. The House of Representatives has already passed its own permitting bill, but it lacked anything to do with transmission. (See Republicans Opening Offer on Permitting is Missing Electric Tx.)
Manchin said he hoped that the interest in changing permitting on both sides of the aisle would lead to bipartisan legislation, saying that electric transmission was the hardest part of the bill to negotiate, but that it is necessary.
“The House gave us a piece of legislation with no transmission,” Manchin said. “Any bill is not going to happen without transmission; same with pipelines.”
MISO told stakeholders Tuesday that it hasn’t yet settled on a deadline for developers to submit generation project applications for the 2023 interconnection queue cycle.
Ryan Westphal, manager of generation interconnection, said during an Interconnection Process Working Group (IPWG) teleconference that staff will announce a finalized date during a future IPWG meeting.
Multiple stakeholders asked whether MISO is considering embedding some feasibility checks earlier in the process. Entergy’s Yarrow Etheredge said reforming the application process would give stakeholders more certainty on the number of viable projects, given the sheer amount of generation that entered the 2022 cycle. MISO fielded more than 170 GW of new generation requests last year. (See MISO Insists it can Handle Record-setting Interconnection Queue.)
“Obviously we have more generation in the queue than we have load,” Etheredge said
Westphal said MISO is considering some application process changes but isn’t ready to share proposals.
The RTO has been accepting queue requests since last fall.
Stakeholders are asking the grid operator to clear up its transmission service-request process for incoming battery storage that charges from the grid. They said inconsistencies and ambiguous language exist between MISO’s business practice manuals and tariff as to whether battery storage needs to secure yearly, firm point-to-point transmission service or non-firm service. Staff maintain that storage charging from the grid is required to obtain long-term, point-to-point service.
WEC Energy Group’s Chris Plante raised the issue earlier this year, saying he thought the business practice manuals are light on authority when standalone battery storage connects to the transmission system and intends to charge from the grid.
MISO said it is also hoping to introduce a new relative queue priority with PJM to study proposed generation projects near the seams for potential effects that might require transmission upgrades in each footprint. Westphal said the RTO wants to use a process like the one it rolled out last year with SPP, in which it uses a first-ready, first-served philosophy. Staff first study projects that are best prepared for interconnection, rather than according to the order in which they entered the queue. (See FERC OKs New Queue Priority for MISO, SPP Seams Studies.)
The Massachusetts Department of Energy Resources (DOER) on Tuesday issued a draft request for proposals for up to 3,600 MW of offshore wind generation, the state’s largest solicitation yet.
Pending approval from the state’s Department of Public Utilities (DPU), the RFP would be the state’s fourth for offshore wind and a record for New England solicitations.
“This draft RFP is a signal to the rest of the world that Massachusetts is all-in on offshore wind and ready to be the industry’s hub,” Gov. Maura Healey said in a statement. “Our proposal is also a commitment to Massachusetts ratepayers to chase after all clean energy for our homes and businesses.”
The capacity would be enough to meet more than a quarter of the state’s annual electricity demand. Depending on the outcome of the state’s existing offshore wind project contracts, the latest solicitation could allow the state to meet its goal to procure 5,600 MW by 2027.
This comes as Avangrid’s (NYSE:AGR) 1,200-MW contract from the previous round of bidding remains up in the air, with the company trying to exit its power purchase agreements with utilities, citing increased costs from inflation, supply chain issues and rising interest rates.
The DOER’s proposed timeline | Massachusetts Department of Energy Resources
As the state hopes to avoid similar issues in this round of bidding, the RFP would allow bidders to submit an alternative indexed pricing proposal. This would tie the bid price to a set of economic indices, allowing the price to increase or decrease by up to 15%.
The main consideration for selecting the winning bids in the new round of proposals will be a quantitative assessment of the economic and environmental costs and benefits to ratepayers, which will account for 70 points of the 100-point scoring system. The state will also consider a set of qualitative economic development and project experience factors, which will make up the remaining 30 points.
The experience criteria would include each bidder’s track record in successfully developing similar projects — potentially putting Avangrid at a disadvantage — while the economic development criteria would favor proposals that include community benefit agreements; workforce agreements with labor unions; training programs with local organizations; and employment opportunities for women, workers of color and residents of affected environmental justice communities.
“This RFP is crafted to capture the greatest benefit for Massachusetts’ ratepayers, communities and businesses and to grow our blue energy economy,” DOER Commissioner Elizabeth Mahony said. “With this draft RFP, we are requiring projects include support for environmental justice populations and low-income ratepayers in the commonwealth, and opportunities for diversity, equity and inclusion.”
The draft RFP will likely go to a public comment period with the DPU. If ultimately approved, the DOER has proposed a Jan. 31, 2024, due date for proposal submissions, with projects selected in June 2024.
Ørsted on Wednesday reported that earnings from its offshore wind business hit an all-time high in the first quarter of 2023, as increased installed capacity outweighed a slight decrease in average wind speed from the same period last year.
The Danish company is the largest OSW developer in the world. All totaled, including onshore assets, Ørsted generated 8.9 TWh in the first quarter, about 16% more than a year earlier.
The news was tempered by a significant overall decline in profit from year to year because of currency exchange rates and interest rates, Ørsted said.
Green sources accounted for 89% of Ørsted’s first-quarter power generation. Installed renewable capacity totaled 15.48 GW as of March 31: 8.87 GW of offshore wind, 3.46 GW of onshore wind, 2.05 GW of biomass thermal and 1.03 GW of solar.
Ørsted has multiple OSW projects in the works off the U.S. Atlantic Coast, in stages ranging from concept to construction.
On Monday, Ørsted and partner Eversource Energy (NYSE:ES) marked the completion of fabrication of foundation components in Providence, R.I., for its South Fork Wind project and start of fabrication for its Revolution Wind project.
Construction is underway on the South Fork project, which sits south of Rhode Island and will feed up to 132 MW into the New York grid. The components will be loaded soon and shipped to the work site.
South Fork is sometimes referred to as the first large-scale OSW project in the U.S. Vineyard Wind, an 800-MW project under construction off the Massachusetts coast, also claims that distinction. Both are expected to start generating power later this year.
Company and state officials spoke of Monday’s announcement as a milestone not just for South Fork and Revolution but for the OSW industry and for Rhode Island’s place in it.
“A year ago, we mobilized with a blank slate, to build and create a workforce of more than 125 union crafts, 20 support staff and local subcontractors to support groundbreaking wind projects in the state of Rhode Island,” Stephen Zemaitatis Jr., president of general contractor Riggs Distler & Company, said in a news release. “Fast forward a year to the day, and our work is pioneering the development of cutting-edge products and helping chart the path for a more sustainable future. By providing serial construction of advanced foundation components … we are building foundations for both wind turbines and the future of U.S. renewable energy.”
During an investor call Wednesday, Ørsted CEO Mads Nipper said the company is pleased with its OSW financials but is not immune to the price pressures facing the industry.
In Massachusetts, Avangrid (NYSE:AGR) has moved to rebid its 1,200-MW Commonwealth Wind project, saying it cannot be financed with the power purchase agreements negotiated, and the 1,200-MW Shell-Ocean Winds project now known as SouthCoast Wind has indicated it faces the same problems. Ørsted has taken a $365 million cost impairment on its Sunrise Wind project, which will send 924 MW to New York.
“If we do not see value creation being satisfactory … we are prepared to take a different path,” Nipper said.
Meanwhile, the Ørsted-Eversource partnership submitted the only proposal in Rhode Island’s most recent OSW solicitation: the 884-MW Revolution Wind 2. Commenting in mid-March, Rhode Island Energy, which issued the request for proposals with the state, sounded less than thrilled with it, saying careful review would be required before moving forward with it.
A financial analyst asked Nipper if he thought the proposal would be rejected.
“We hope and believe we will be awarded,” he replied. “At this point we are not guessing as to whether there is a risk for that to be resolicited.”
Continued Feedback
In other offshore wind news this week:
The public comment period closed Monday for the U.S. Bureau of Ocean Energy Management’s proposed Renewable Energy Modernization Rule, which would streamline and modernize regulations first created in 2009 by a predecessor agency to the bureau. The 215 comments posted as of Wednesday ranged from strong resistance by a fishing industry group to a clean energy group citing an urgent need to make OSW development easier, more flexible and more certain.
A group of New England fishers on Tuesday announced formation of the New England Fishermen Stewardship Association, an advocacy group designed to fight OSW development. NEFSA said it is nonpartisan and the first umbrella organization of its kind in the region. It also said it has the additional mission of fighting “needless regulation” and “social catastrophes imposed by woke regulators.”
BOEM on Wednesday announced it would review potential environmental impacts that might arise if Maine is granted the offshore wind energy research lease it is seeking in the Gulf of Maine, where it wants to place up to 12 floating turbines. BOEM said comments are due by June 5, and it will consider them as it prepares an environmental assessment for the potential project.
ERCOT’s final resource adequacy assessment for the summer indicates the grid operator will have “sufficient” installed capacity to meet expected record demand during the next few months.
However, Public Utility Commission of Texas Chair Peter Lake chose to highlight the lack of dispatchable — or thermal — generation to meet that demand. During a press conference Wednesday to provide what has become an annual public update before the summer, Lake used the modifier “on-demand dispatchable” 10 times when referring to power, generation or generators.
For the first time this summer, he said, ERCOT’s data shows demand will exceed “on-demand dispatchable power.”
“So, we will be relying on renewables to keep the lights on during the hottest days of summer,” Lake said.
Ironically, the Texas Legislature has moved bills during the current session that add costs and requirements for renewables. Lawmakers have instead focused on legislation designed to incent the construction of more thermal generation. (See Texas Legislature Moves Bills Remaking the ERCOT Market.)
Lake said that between 2008 and 2020, Texas’ population increased by 24% while the state’s “on-demand dispatchable power supply” grew by only 1.5%. He said demand continues to grow with the state adding the equivalent of the population of Oakland, Calif., (433,823 residents as of 2021, according to the U.S. Census Bureau and other sources) and their “devices” requiring electricity every year.
Oakland has replaced Corpus Christi, Texas, (population: 317,863), which Lake and ERCOT CEO Pablo Vegas used in the example last year.
“The increase in demand for electricity is outpacing the supply of on-demand dispatchable power in this new reality,” Lake said. “Our risk goes up as the sun goes down because it’s still hot at 9 p.m. Our solar generation is all gone, so at that point in the day we will be relying on wind generation on our hottest days. We may not have enough on-demand dispatchable generation to cover the gap between when the sun sets and we lose the solar, and when our wind generation picks up.”
According to ERCOT’s seasonal assessment of resource adequacy (SARA), which assumes typical summer grid conditions, the ISO has enough capacity to meet a summer peak of 82.7 GW. That would smash the current record of 80.04 GW, set last July.
The report says more than 97 GW of summer-rated resources are expected to be available for the summer peak. That includes 65.1 GW of thermal resources, a slight increase from last summer’s 63.5 GW number. The grid operator expects to have on hand another 10.4 GW of summer-rated wind resources and 12.3 GW of solar.
The SARA’s most severe risk scenario assumes a high peak load, extreme unplanned thermal plant outages, and extreme low wind power production. However, Vegas said that probability is less than 1%.
Noting that most of the new capacity added since last summer comes from renewables, Vegas said ERCOT could see more tighter hours than last summer and after the traditional 5 p.m. peak load hour. Scarcity conditions are more likely around 9 p.m., after the sun sets and before wind picks up.
Lake said there were at least 12 days last summer when ERCOT experienced tight conditions between 8 p.m. and 10 p.m. He said less than 20% of all wind turbines were generating, despite data showing “on our hottest days we need 50% of all the windmills generating power at 9 p.m.”
“To help mitigate these risks, we’re going to continue to operate the grid conservatively as we have been doing,” Vegas said. “That means bringing generating resources online earlier to mitigate any sudden changes in generation or demand. We plan to operate a reliable and resilient grid this summer.”
Help for Ramping
The grid operator also will launch a new ancillary service on June 8, ERCOT contingency reserve service, that will address the rapid ramps that can occur when renewable resources are operating.
“The urgency to move forward with meaningful electric market reforms that will incentivize the development of dispatchable generation remains extremely high,” Vegas said. “I’ve described many of the tools that we have to deal with the real-time operational challenges that we have, but these do not substitute for significant market reforms that will incentivize the development of new dispatchable generation and to help preserve older generation until it can be replaced.”
ERCOT also released its semi-annual capacity, demand and reserves report (CDR) for the next 10 years. The report provides forecasted planning reserve margins (PRMs) for the summer and winter peak load seasons, forecasting a 2024 summer PRM of 33.9%. That’s a six-percentage point drop from the November CDR.
The grid operator defines the PRM as the percentage of resource capacity greater than firm demand and available to cover uncertainty in future demand, generator availability and new resource supply. Firm demand accounts for load reductions available through interruptible load programs and incremental load reductions from rooftop solar systems that are not accounted for in the load-forecast models.
According to the report, demand will exceed 85 GW next summer and peak at 71.5 GW during the 2024-25 winter.
The Brattle Group released a study Tuesday that found virtual power plants (VPPs) are cheaper than other currently viable options for resource adequacy, namely storage and natural gas peaking plants.
“Real Reliability: The Virtue of Virtual Power” was prepared for Google (NASDAQ:GOOGL). It found that using distributed energy resources including rooftop solar, smart thermostats (which Google makes), smart water heaters, electric vehicles and batteries also provide additional benefits that the alternatives do not.
The last decade saw utilities spend $120 billion on resource adequacy investments, which was dominated by coal, but saw battery storage rise rapidly in the last few years.
“Electrification, coal retirements and dependence on resources with limited capacity value (wind, solar) will continue to result in a persistent need to maintain sufficient system ‘resource adequacy’ by adding new dispatchable capacity,” the study said.
VPPs involve customers allowing their DERs to be controlled by their utility or a third-party aggregation firm, which then operate them in a way to provide the grid benefits, such as cutting demand during peak hours. That allows the power system to be expanded and operated at a lower cost, reliability to be maintained and emissions cut while the benefits are shared among customers, the aggregator and/or utility, and society at large, the report said.
DER ownership is expected to grow substantially in the next decade with smart thermostats on 34% of homes by 2030 compared to 10% today; rooftop solar growing to 83 GW from 27 GW; light-duty electric vehicles growing to 26 million from 3 million; and behind-the-meter batteries growing to 27 GW from just 2 GW today. That comes on top of friendly policies such as the Inflation Reduction Act, with its promotion of electrification and efficiency, and FERC Order 2222, which requires all organized markets to open up to DER aggregations.
Demand response programs have operated like VPPs for decades in some regions, but many firms are setting up new ones that leverage the expansion of DER technologies in recent years. Portland General Electric is setting up a 4-MW behind-the-meter battery VPP involving more than 500 customers; CPower has introduced a smart thermostat-based VPP to participate in PJM; and ERCOT has set up an 80-MW VPP pilot targeting a variety of end uses.
Brattle’s analysis focused on four commercially proven technologies: smart thermostats, smart water heating, managed charging for EVs and behind-the-meter battery-enabled DR. It compared the costs of providing 400 MW of resource adequacy from VPPs made of those technologies to a utility-scale battery and a natural gas peaking plant.
The different plants were studied in the same utility system where 400 MW produced about 7% of the peak demand and half the generation was made up of renewable power. Brattle designed the model utility to represent some challenging requirements for the VPP, like needing to offer resource adequacy during many hours in both the winter and summer. The resources all had to perform 63 hours a year and seven hours during one peak summer day.
VPPs can curtail load during the highest demand hours and shift it to lower hours, while any smart water heaters in the aggregation are capable of producing ancillary services. The VPPs also cut greenhouse gas emissions and delay the need for transmission and distribution upgrades, with the batteries able to provide backup generation during distribution outages.
“The VPP could provide resource adequacy at a net utility system cost that is only roughly 40% of the net cost of a gas peaker and 60% of the net cost of a battery,” the study said.
RMI has estimated that 60 GW of VPPs could be deployed across the country by 2030 and that would meet future resource adequacy needs at a cost that is $15 billion to $35 billion lower than the alternatives.
“Decarbonization and resilience benefits are incremental to those resource cost savings,” said the study. “Consumers would experience an additional $20 billion in societal benefits over that 10-year period.”
Utilities are pushing back against a proposed rule by the New Jersey Board of Public Utilities (BPU) that would prevent them from owning or operating projects in the agency’s planned permanent community solar program.
But the BPU’s plan has the backing of the state’s Division of Rate Counsel.
The topic emerged as a prominent source of contention in an April 24 BPU hearing seeking stakeholder feedback on the latest draft of the rules, which state that electric distribution companies (EDCs) “are not allowed to develop, own or operate community solar projects.”
New Jersey Utilities Association CEO Richard Henning said he was “surprised and disappointed” at the BPU’s position and expressed the view — shared by representatives of two utilities, Atlantic City Electric and PSEG — that EDCs have valuable experience and expertise to contribute to the community solar sector.
“To have the electric utilities on the sidelines makes no sense,” Henning said. “They have the resources, the program management, the infrastructure to handle organizing and implementing community solar projects like no other.”
Speakers also raised questions about the impact of making program eligibility dependent on a project obtaining an EDC connection study and encouraged the BPU to broaden the types of projects eligible in the program.
Several speakers urged the agency to rethink a rule that prohibits a developer from co-locating two projects on the same property or contiguous properties. They said that complicated projects, such as those on brownfields or a landfill, are more expensive, and combining two projects can increase the capacity and financial reward enough to make the project feasible.
Serving LMI Customers
The draft rules outline a permanent program in which the BPU would approve community solar projects totaling at least 225 MW in each of the first two years, starting this year, and at least 150 MW in subsequent years. Projects can be no larger than 5 MW and will be allocated by the BPU on a first come, first served basis. (See NJ Proposes Modest Community Solar Capacity Hike.)
State officials consider the two community solar pilots a major success and believe the program will play a key role in the state reaching its goal of 32 GW of solar by 2050, about 34% of the state’s generating capacity.
In both pilot programs, the BPU approved projects through a competitive solicitation process, awarding 45 projects totaling 76 MW in 2019 and 105 projects totaling 165 MW in 2021. So far, 25 community solar projects totaling 47.7 MW have been completed and are up and running, according to BPU figures.
Aaron Karp, an attorney for PSEG, said the state’s Clean Energy Act clearly requires the BPU to “set forth standards for projects owned by electric public utilities” and other entities in the permanent community solar program. Moreover, he said, the utility has a long history of “partnering” with low- and moderate-income (LMI) customers and is “uniquely suited to effectively leverage those relationships to ensure that LMI customers can participate in community solar.”
“Utility ownership will not only help the state meet its lofty but important solar goals, but it will also ensure the participation of low- to moderate-income customers,” he said, urging the board to revise its prohibition on EDC project ownership and operation.
Offering comments “on behalf” of Atlantic City Electric, Jocelyn Tyler, manager for DER interconnection at parent company Pepco Holdings, said the utility has gathered “lessons learned” by working to connect community solar projects. That experience, and the fact that “utility-owned solar has seen success in many states,” should warrant the BPU rethinking its position, she said.
“Utility ownership of community solar will lead to increased deployment of renewable energy, benefiting LMI customers, increasing grid resilience and reliability” and help manage peak load stress, “all of which are objectives of the program,” she said.
BPU staff, in an explanation accompanying the latest draft, said EDC ownership or operation is “unnecessary” given that the two community solar pilot programs were heavily oversubscribed, demonstrating “strong interest” in developing community solar by non-EDC entities.
“Staff therefore believes that there is no reason to transfer the risks and costs associated with developing a community solar project from non-EDC entities to the ratepayers, nor for EDCs to have a potential competitive advantage in project ownership,” the BPU staff said.
The experience of the pilot “demonstrates both the strong interest in developing community solar by non-EDC entities (both private developers and public entities) as well as their ability to design projects that serve a broad diversity of customers,” the staff explanation said.
Rethinking Acceptable Projects
Sarah Steindel, staff attorney with the Division of Rate Counsel, said her agency supported the BPU’s position on EDCs. But switching to another topic, she added that the ratepayer advocate would like the regulator to rethink its limitation on where community solar can be located. The draft proposal limits projects to four types: rooftops, carports and canopies over impervious surfaces, contaminated sites and landfills, and man-made bodies of water.
“We would caution the board on limiting the sites to rooftops and so forth,” Steindel said. “This conflicts with the stated goal in the straw proposal of providing maximum benefits at the lowest cost because it tends to increase the amount of subsidies required or reduce the benefits that go to subscribers, or both.”
Eric Millard, chief commercial officer at CS Energy in Edison, N.J., also advocated for a wider variety of project types beyond the “restrictive” selection outlined in the draft. “The draft effectively restricts the siting of community solar projects to areas in the state that have large rooftops or contaminated sites, and that’s a pretty small subset of New Jersey,” he said.
“We think that community solar projects should be allowed in commercial and industrial zoned parcels,” where solar is allowed under land use laws, he said. In addition, he added, the BPU should add “contaminated agricultural land” to the definition of brownfield sites suitable for community solar projects.
Jake Springer, mid-Atlantic policy director for Nexamp, a Boston-based solar developer, cited the difficulty of pursuing contaminated sites as a reason for the BPU to reconsider its prohibition on co-locating projects on the same site. In cases such as landfill or brownfield development, co-location can provide a “tremendous benefit to making those projects cost effective,” he said.
Under any circumstance, “there’s an argument to be made that those types of projects are disadvantaged relative to others, such as rooftop projects, where the permitting requirements are less,” Springer said. “The ability to co-locate up to 10 MW [on a site], as under the pilot, would allow a number of brownfield and landfill projects to go forward.”
Making a similar point, Lyle Rawlings, president of Mid-Atlantic Solar & Storage Industries Association, suggested the BPU could allow developers to seek a waiver from the prohibition based on a project’s “public benefits” or ability to help the state reach its “policy priorities.”
Evaluating Project Maturity
Several speakers also questioned whether the state could reach those priorities and the community solar sector could flourish with the program structure outlined in the draft — especially aspects of the criteria of “maturity” needed for a project to be accepted into the program.
BPU officials say the criteria is designed to ensure that under the first come, first served system, only those projects ready to advance — and likely to be implemented — will be allocated valuable capacity in the program.
Joe Henri, of Atlanta-based solar developer Dimension Renewable Energy, welcomed the BPU’s plan to select projects on a first come basis method, while ensuring their quality and readiness by requiring them to meet certain “maturity” measures. Among them would be a requirement that the developer demonstrate the project will be able to connect to the grid by showing that it has an interconnection study completed and the EDC is ready to sign off on the project.
However, Henri said, that will be problematic in the short term because of the current lengthy delays projects face in connecting to the grid and planned reforms to improve the situation are moving slowly.
“Unfortunately, those rules probably aren’t going to be completely in place and completely clarified until late this year or early next year,” he said. He said it would be ideal for the EDC to sign off on a project before it is selected, but that does not usually occur until late in the proves, so an “interim” milestone that shows the project has the requisite maturity needed, he said.
Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, added that the proposal to assess a project’s maturity by whether the EDC has completed a connection study will not only put great pressure on utilities, but will also make them “gatekeepers to this process,” giving them considerable power in deciding which projects go forward. The draft proposal suggests that requirement for projects greater than 1 MW, and smaller projects must only show they have submitted to the EDC an “interconnection agreement.”
“So that this puts the ball in the utilities court completely for making the decision on who wins and who loses based upon the first come, first served” selection structure,” he said. “To that end, we think it’s important that the industry understand how the EDCs will work through this significant surge in workload [and] the protocols and priorities that they may establish in conducting this work.”
COLONIE, N.Y. — Boosted by new tax credits and growing momentum toward decarbonizing buildings, the 2023 NY-GEO Conference last week was nearly standing-room only, with a record number of attendees.
And the room to stand was limited by all the exhibitors on hand at the geothermal heat pump expo last week, some of them wedged into any available space in the corridors.
Geothermal systems have among the lowest operating costs of any heating/cooling system, but for decades, many potential buyers have been turned away by their high upfront costs.
With local, state and federal policy promotion of the technology, and with IRA tax credits to sharply reduce the installation costs, the industry has turned a corner, one speaker after another declared.
Jens Ponikau, president of the NY-GEO board of directors, recalled being excited to have 62 attendees at the first conference eight years ago and see it grow steadily to 400 last year. More than 700 people registered to attend the 2023 edition.
“Never in my wildest dreams would I have imagined where this technology has gone,” he said.
The industry does still face headwinds, notably a shortage of contractors to drill the bores that act as a source of heat in the winter and repository of heat in the summer. But with structures being one of the largest sources of greenhouse gas emissions, building decarbonization is central to the climate mitigation programs being planned and implemented in New York and elsewhere.
Scott Walsh, director of development for Lendlease, spoke about 1 Java Street, the 790,000-square-foot mixed-use complex it is building on the Brooklyn waterfront. The all-electric building is a significant undertaking, not least because of its geothermal system. Construction crews had to choreograph foundation pile-driving with drilling of 320 vertical bores for the system. (A one-family house typically needs only a single vertical underground loop.)
“It was Santa’s Workshop on our site, to say the least,” Walsh said.
The geothermal climate control system at 1 Java will be larger than any other residential installation in the state, and by serving multiple structures, it is akin to the district community systems that the New York State Energy Research and Development Authority is guiding through a pilot process.
Donovan Gordon, NYSERDA’s director of clean heating and cooling, said the various pilot projects are a good mix of upstate and downstate, and are advancing through the review process. He urged NY-GEO to keep the momentum going by doing good work; people need to trust that ground-source heat pumps will deliver on their promise, he said.
“If we’re selling this product, let’s make sure that it’s reliable and they can count on it when they really need it,” Gordon said.
And then we need to let the world know it, he said.
“One thing I learned very early on is that in order for geothermal to succeed, we need a champion. So, we want to identify who the champions are — certainly at the municipal level; the developer level; the building owner level; wherever we can — and help them so they can really push the cause and get things done within their community.”
Daniel Ellis of Comfortworks said the shortage of drilling contractors notwithstanding, the ground-source heat pump industry is in an excellent position in 2023.
“It takes three things to make the market really fly,” he said. “You have to have high energy costs; you have to have some form of incentive; and you have to have an economy where things are being built and renovated. Right now, I think we’re at a pretty good situation. Anything could change in a heartbeat, economy-wise or whatever, but we have all the things lined up.”
Continual Effort
A plenary discussion was titled “Worst to First,” a reference to the economics of geothermal heat and government support for it as a means of decarbonizing buildings.
The discussion’s moderator said this was a bit of an exaggeration: Geothermal was never really worst, and there still are a few things to unpack in the IRA before it can be first.
But worst to first describes the ups and downs of an industry campaign that started in the Carter administration and has continued with dashed hopes, false starts and steady lobbying to gain recognition and subsidies for geothermal as a legitimate way to save money and the planet.
What could have been a seminal moment for the industry came and went 30 years ago, when the EPA report “Space Conditioning: The Next Frontier” declared electric ground-source heat pumps the cleanest, most efficient means of interior temperature control.
Through politics, legislative horse trading and apparent clerical errors, geothermal became one of the “orphan technologies” excluded from subsidy programs, along with small wind, fuel cells and microturbines, Geothermal Exchange Organization President Ryan Dougherty said.
Things began to look up in 2018, when federal incentives were reinstated, but persistent lobbying — right up to and after passage of the IRA in 2022 — finally turned the page for geothermal, he said.
“But it’s not like flipping a light switch,” Dougherty said. “We’re still in many ways building back.”
A geothermal heat pump system is an expensive upfront investment that will yield immediate dividends for GHG reduction but take years or decades to provide return on investment for the building owner, depending on the cost of fossil fuels and electricity. It is also just one piece of a much larger bill spread over the next few decades. How much the energy transition will cost and how that cost will be allocated is still unknown.
And if the transition is to be anything close to complete or equitable, someone must pick up the tab for the Americans who cannot afford big increases in taxes or utility rates or housing costs.
One session of 2023 NY-GEO was titled “Who Will Pay for Building Electrification,” but it centered more on “Who Must NOT Pay”: the imperative that low- and middle-income residents not be stuck with the bill. It was suggested that all the money being spent to maintain and expand gas utility infrastructure be spent instead on electrifying housing, but no one noted that ratepayers presumably would bear the cost either way.
Then there is the housing itself: About 45% of New York state’s housing stock consists of rental units whose residents have limited ability to make upgrades and whose owners have little incentive to do the work, absent the carrot and stick of government regulation.
In New York City, 67% of the housing is rented and the poverty rate is significantly higher than the rest of the state and nation. An apartment on the Brooklyn waterfront can run $5,000/month. Market-rate units in Lendlease’s high-tech no-carbon complex at 1 Java will go for $7,000 to $10,000/month, CNBC reported last week.
“We have some big challenges because New York has some very old building stock,” said Jessica Azulay, executive director of the Alliance for a Green Economy. “A lot of these older houses are in dire need of repairs, upgrades, weatherization and electrical work before they can electrify.”
Annie Carforo of WE ACT for Environmental Justice related a pilot project that replaced gas stoves with electric induction ranges in 10 apartments in a housing authority building in New York’s poorest county. Everyone loved them, and nitrogen oxide levels dropped 35% in the air in those 10 apartments. But the project had to be fanned out horizontally across the building; the electrical circuitry could support only two induction ranges per vertical stack of apartments in the six-story structure.
Challenges like these are multiplied across the 177,000 units of the New York City Housing Authority, which reports it has a $40 billion backlog of deferred maintenance after decades of funding cuts.
“That is going to be a barrier to doing a lot of this electrification work,” Carforo said. Government funding streams for doing this work are siloed and inflexible, she added.
Drill, Baby, Drill
Outside the meeting rooms at 2023 NY-GEO, NetZero Insider spoke to exhibitors representing a sales company, an installation contractor, a utility, and an inventor and manufacturer. Each offered a distinct perspective, but all gave an upbeat appraisal of the prospects for geothermal heating and cooling.
“I used to come to these events to find moral support!” said Jonathan Tham, administrator of PSEG Long Island’s Home Comfort Program. “There’s definitely a larger interest [now]. I’ve been in this field for more than 30 years. It used to be that I would have to go and sell green environmental technology; now they’re coming to us. But that’s been the case for the last five years; the awareness is there. …
“We’ve changed from thinking about energy efficiency in terms of dollars to carbon. We’re basically saying we don’t want any emissions.”
Tham promotes air-source and ground-source heat pumps with equal enthusiasm. The biggest obstacles to adoption, particularly for ground-source heat pumps, remain the high cost of installation and the limited availability of contractors to do the work, he said.
Aztech Geothermal Service Manager Austin Gross said government incentives are important to continued adoption of the technology. Their cancellation several years ago choked off consumer interest in his company, which is based near Albany and works almost entirely on residential projects.
Incentives were restored and later enhanced by the IRA.
“It’s backed us out of the corner; it’s given us a lot more breathing room to at least be competitive with conventional systems,” Gross said.
Aztech contracts its bore drilling, and like many others during the conference, Gross flagged the shortage of drillers as a problem. Not only are there not enough to begin with, many shy away from drilling geothermal systems. They have enough business drilling water wells that they need not bother with what is a familiar process but an unfamiliar application.
“It’s an entirely new market for a lot of drillers to be able to step into,” he said.
Energy Catalyst Technologies grew out of a young engineer’s frustration at the lack of options to convert his home to geothermal heat. Like many houses in the Northeast, it is an older building with a hydronic heating system — hot water running through pipes — that would be expensive and disruptive to replace.
“A lot of times in a home with radiators — like our own — someone will come by and say, ‘Rip out all the radiators, and let’s put in some air ducts, mini splits or something like that,’” said Marketing Director Emily Desmarais.
So, founder Matthew Desmarais designed a double hybrid heat pump, warming hot water and circulating it through the radiators in winter. In the summer, it generates hot water for domestic use and can double as an air conditioning system for the first floor with a relatively small amount of ductwork, if the basement is unfinished.
Now four years old and out of the startup phase, Energy Catalyst is hoping to grow with the geothermal industry.
Tim Houle of Stark Tech was showing off a water furnace ground-source heat pump at the expo. He sees momentum in the industry, with ground-source heat pumps now getting consideration against their less expensive air-source counterparts or against fossil-fuel systems because of incentives to bring the cost down.
“We’ve been doing it forever; now it’s more of a desired technology,” he said.
Stark works on the commercial scale — schools, office buildings, industrial sites and really, really large houses. The motivation for such conversions ranges from a desire to go carbon-free, to a desire to publicly promote oneself as carbon-free, to simply getting away from expensive oil heat.
There is also a desire or need to get ahead of regulations, Houle said, as a growing number of jurisdictions are mandating that buildings go carbon-free.
New York is poised to be the latest.
As 2023 NY-GEO wound down Thursday, Gov. Kathy Hochul announced a conceptual agreement on the state’s long-overdue 2023-2024 budget. Among the welter of critical policy issues baked into the spending plan is a ban on fossil fuel systems in new construction. (See related story, NY to Begin Banning Gas in new Construction in 2026.)
