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November 16, 2024

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NPCC Warns of Tight Summer Margins in Ontario

Canada’s Ontario and Maritimes provinces may have to rely on energy imports and operating procedures to meet energy needs this summer, the Northeast Power Coordinating Council said this week; however, the regional entity expects no other challenges for utilities in its footprint.

NPCC’s 2023 Summer Reliability Assessment, released on Wednesday, reported that the region — which includes the six New England states, New York, Québec, Ontario and the Maritimes (New Brunswick and Nova Scotia) — is expected to have about 158,800 MW of installed capacity for the months of June, July and August. That figure includes projects expected to be in service over the course of the summer and represents a decrease of about 600 MW from last summer. (See NPCC Predicts Tighter Margins for Summer 2022.)

Adding in 2,144 MW of net interchange, representing purchases and sales with areas outside NPCC, and 2,313 MW in dispatchable demand-side management assets, the region is expected to have 163,338 MW of total capacity for the summer.

The coincident peak demand during NPCC’s peak week, beginning Aug. 20, is 105,200 MW, up from the 104,601 MW predicted for last year’s peak week of July 24. During that week the net margin will be 10,047 MW, slightly tighter than last year’s peak week margin forecast of 11,586 MW.

Predicted resource fuel types (NPCC) Content.jpgNPCC’s predicted resource fuel types for the week beginning Aug. 20 | NPCC

 

Overall demand figures are based on a 50/50 system load forecast, representing a prediction with a 50% chance of being exceeded. Like last year, the assessment also includes a 90/10 forecast, which has a 10% chance of being exceeded, and an “above 90/10” forecast representing a “low-probability, high-impact composite scenario [relying] heavily on individual area risk assumptions.” Under the 90/10 forecast, net margin shrinks to 4,090 MW, while the most extreme scenario results in a deficit of 7,270 MW for the region.

While the majority of NPCC’s subregions report adequate margin for at least the 50/50 scenario, Ontario is currently predicting negative margins for multiple weeks under the 50/50, 90/10 and above-90/10 forecasts. This is largely because of planned generator outages during those weeks.

Ontario’s forecasted peak demand is 22,439 MW for the 50/50 scenario, 24,420 MW for 90/10, and 27,021 for above 90/10. The area’s peak week begins July 23 under the 50/50 and above-90/10 scenarios and July 16 in the 90/10 scenario. Because of generation additions including two new hydroelectric plants, the area’s generation has experienced a net increase since last summer of 178 MW.

NPCC said that Ontario’s deficits may require its Independent Electricity System Operator to call on imports from neighboring jurisdictions or “additional operating actions,” even during 50/50 conditions. However, the RE also acknowledged that IESO is working with generation owners to reschedule the outages scheduled for these weeks. Noting the amount of system upgrades and maintenance scheduled over the next few years, NPCC “strongly encouraged” market participants to coordinate with IESO so that outages can be scheduled appropriately.

Other than the Maritimes provinces, which show “a likelihood of using their operating procedures,” including reducing their 30-minute reserves and initiating interruptible loads to mitigate resource shortages during the 50/50 scenario, no other area expects to have issues meeting demand this summer. Regional forecasts under the 50/50 and 90/10 scenarios are:

  • Maritimes: peak demand of 3,612 MW (50/50) and 3,845 MW (90/10), with total capacity for peak week of 7,775 MW under both scenarios. Two solar farms are expected to enter service before or during summer, while a hydro station is expected to be retired, resulting in a 9-MW net increase in capacity.
  • ISO-NE: peak demand of 24,664 MW (50/50) and 26,479 MW (90/10); total peak week capacity of 30,346 MW. The addition of about 3,500 MW of behind-the-meter solar PV and 2,004 MW of energy efficiency demand reductions is expected to reduce peak load by nearly 3,000 MW.
  • NYISO: peak demand of 32,049 MW (50/50) and 33,883 MW (90/10); total peak week capacity of 41,374 MW. New York’s resource additions include 556 MW of land-based wind, although the retirement of several combustion generators means a 205-MW decrease in installed capacity from last summer.
  • Québec: peak demand of 22,859 MW (50/50) and 23,900 MW (90/10); total peak week capacity of 44,654 MW. NPCC said the province is expecting no issues with resource adequacy and “is prepared to assist other areas, if needed.”
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Con Ed Completes 300-MW Line for Cleaner NYC Grid

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.”

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Report: Energy Storage Would Save Indiana Utilities $73M

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.”

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Senators Praise Phillips, FERC’s Output at Oversight Hearing

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.”

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MISO: No Deadline Yet for 2023 Queue Applications

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.)

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Mass. DOER Issues Draft RFP for Region’s Largest OSW Solicitation

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.

DOER proposed timeline (Massachusetts Department of Energy Resources) Content.jpgThe 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.

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Offshore Wind Power Boosts Revenue for Ørsted

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.
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ERCOT, PUC Repeat Call for Dispatchable Generation

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.

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Brattle Group Finds VPPs Cheapest Alternative for Resource Adequacy

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.”

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Utilities’ Role Debated in NJ Community Solar Plan

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.”