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November 8, 2024

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BlackRock Decision Unearths FERC Wariness of Investor Influence on Utilities

FERC on Wednesday agreed to reup BlackRock’s (NYSE:BLK) blanket authorization to buy stock in utility companies for another three years, but not without some of the commissioners saying they were wary of the power of massive investors to shape energy companies’ decisions (EC16-77-002).

The four participating commissioners (Commissioner James Danly having recused himself) saw no reason to upend a precedent set more than a decade ago by FERC, which allows the company to own up to 20% of any individual utility.

The investment giant had first requested a blanket authorization in 2010. FERC approved it at that time and has extended it twice since.

“We find that the reauthorization will not have an adverse effect on competition, rates or regulation,” the commission said. “As applicants explain, there have been no changes in material facts and circumstances since issuance of the blanket authorization order that would alter or affect the commission’s prior analysis.”

The reauthorization was not without opposition: Consumer advocacy group Public Citizen filed a protest arguing that it is “impossible for a fund manager of BlackRock’s size and scope to remain a passive investor.”

“BlackRock’s accumulation of voting securities constitutes control over utilities, and its horizontal power over competing utilities harms competition,” the group wrote, calling for a hearing to assess the company’s influence.

FERC denied that request, writing that BlackRock has given it enough assurance that it will not be able to influence utilities. But commissioners from both parties said that they had taken heed of Public Citizen’s warning and are eager to closely examine the way FERC examines such requests in the future.

“I acknowledge Public Citizen’s concerns about the lack of analysis on the effects on competition, just and reasonable rates, and regulation related to the accumulation of acquired interests in public utilities,” wrote Democratic Commissioner Allison Clements.

She said that FERC should take a look at the analysis it requires when evaluating blanket authorizations to make sure any transactions they lead to “do not have an adverse effect on competition and that entities granted such blanket authorizations lack control over the utilities whose interest they acquire.”

Republican Commissioner Mark Christie also said that the worries raised by Public Citizen were “compelling” and called for future scrutiny into investment companies’
control over utilities.

BlackRock in particular, Christie wrote, has been “openly aggressive” in trying to influence corporate policy using its financial power.

“The important question is whether huge asset managers like BlackRock are able to exert undue pressure on regulated public utilities or their holding companies to engage in practices that may undermine their primary responsibilities of delivering reliable power to consumers at just and reasonable rates,” Christie wrote.

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Siting Official Raises Habitat Concern over Wash. Solar Growth

A Washington energy siting council member is requesting a look at the cumulative effect of solar farms on the state’s Yakima River Valley after the agency recently received applications for two new projects in the area.

Yakima County in Central Washington is split west-to-east by the valley, with a U.S. Army training ground covering its north side and the Hanford Nuclear Reservation bumping against the northern half of the county’s east border.

The area is predominantly shrub-steppe, a treeless, sagebrush-filled semi-desert that is home to unique vegetation and animals, including greater sage grouse, which are listed as endangered by the state. Yakima and the surrounding counties are host to many solar proposals.

Shrub-steppe still covers a good chunk of Eastern Washington, but farms and towns have been gobbling up land for more than a century. The shrub-steppe has shrunk from an estimated 10.4 million acres filled with unique birds and critters in the 19th century to 40% of that today.

North Carolina-based Cypress Creek Renewables submitted applications to state’s Energy Facilities Site Evaluation Council (EFSEC) on April 7 to develop two 80 MW solar farms — High Top and Ostrea — near the county’s eastern border, just south of the Army training center.

At least two other solar farms are under consideration. EFSEC is considering whether it will approve the 80 MW Goose Prairie Solar project in the western part of the valley, while the Yakima County government is considering approval of the Black Rock solar farm near Goose Prairie.

Washington has a patchwork approach to approving wind and solar projects, giving renewable energy developers the choice of seeking permits from either the state or host county governments. If a developer chooses the state option, the EFSEC reviews the application and makes recommendations to the governor for a final decision.

During a Tuesday briefing on the High Top and Ostrea projects, EFSEC member Mike Livingston noted that the two projects are on a chunk of land that connects the Army’s Yakima training center and the Hanford reservation, both of which protect shrub-steppe lands within their borders. Livingstone said the four projects are strung along the training center’s southern boundary.

Livingston said solar farms might block unique species such as sage grouse from traveling from one area to the next.   “We need a cumulative impact study [on the environmental effects],” he said. “We’re going to lose the connectivity we have in this area.”

Livingston is not the first Washington official to raise a red flag on the potential impact of solar on the state’s shrub-steppe areas. Last September, Department of Fish and Wildlife staff and members of the state’s Habitat Committee expressed concern that solar developers were neglecting to investigate sensitive species and habitat impacts before locking into project development sites. (See Eastern Wash. Solar Projects Endanger Sensitive Habitat.)

Cypress Creek expects construction of the two solar farms to take nine to 18 months. The company has requested an expedited approval process from EFSEC, meaning a public hearing must be conducted by June 6.

Cypress Creek has built roughly 8 GW of solar projects and owns and operates about 1.6 GW of solar across the country, the company’s director of development, Tai Wallace, told the EFSEC.  “We’ve developed quite a few projects of this scale.”

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Solar Sector Braces for Tariff Probe Impact

A U.S. Commerce Department investigation into claims that China circumvented U.S. tariffs on solar components is already having a chilling effect, with developers and industry groups saying they are seeing component price hikes, delivery delays and shortages as manufacturers in the countries under investigation pull back on exports to the U.S.

In an investigation launched March 25, the department is looking into whether crystalline silicon photovoltaic cells imported from Cambodia, Malaysia, Thailand and Vietnam are really made there, or if they are actually made in China and shipped through those four countries to avoid anti-dumping and countervailing duties that would otherwise have to be paid by Chinese manufacturers.

Anti-dumping duties are levied when the department concludes that a foreign supplier or manufacturer is selling goods on the U.S. market at below-market prices. The department places countervailing duties on a product when it assesses that a foreign government subsidized the supplier or manufacturer to reduce the price in the U.S. market. Crystalline silicon photovoltaic cells are used in the manufacturing of solar panels.

Even though the Commerce Department has only just started the investigation and made no conclusion, manufacturers and suppliers in the four countries are limiting exports to the U.S. out of fear that further tariff increases will be levied retroactively if the department eventually rules that circumvention took place, industry groups and developers say. The Solar Energy Industries Association (SEIA) has said that more than 80% of solar modular imports come from the four countries, and the probe as a result will affect a wide swath of the solar sector.

“These actions are so detrimental to what we’re trying to do,” Mike Kruger, CEO of Colorado Solar and Storage Association, said about the department’s decision to launch the probe. “My folks doing large-scale projects are already looking at renegotiating [power purchase agreements], potentially pushing out due dates for their projects” by as much as six months, he said. Some developers just won’t bid on jobs, because they don’t know either how much the panels will cost or when they will be available.

Kruger added that solar developers are faced with trying to work out whether to price jobs at the existing solar panel price or at the price elevated by higher tariffs that will take effect if the Commerce Department concludes that circumvention is taking place.

“It’s created a lot of challenges here in the short term,” said Jefferson Gerwig, director of procurement for South Bend, Ind.-based Inovateus Solar, which develops solar and energy storage projects for commercial, industrial, municipal and utility customers.

Some manufacturers have raised prices by a “significant” amount, and some have changed the delivery terms on their products, no longer offering to bring them to the buyer’s door and instead requiring that the customer pick them up at the factory. That way the buyer would be responsible for any tariff increase levied in the future, he said.

“This is going to have an impact on our pricing,” he said. “And it’s going to require us to go back and rebid many of our active proposals. So, it is having immediate impacts. We are having to shift numbers and let our customers know that the validity of their quotes needs to be updated, based on these initial price increases that we’re seeing.”

Tim Powers, development and policy manager for Inovateus, said the uncertainty of getting products has created a “mad rush to get modules as quick as possible. And that just puts a supply-and-demand constraint on the entire industry, and that causes challenges for everybody.”

‘Existential Crisis’

The investigation, and the reaction of the solar industry, highlights the tension between efforts to create a domestic solar panel manufacturing industry in the U.S. and developers seeking the lowest priced equipment for their projects as the nation seeks to accelerate its solar generation capacity power to meet its zero-emission goals.

The turbulence in the panel supply sector comes as the industry already is facing equipment shortfalls, delays and price hikes because of supply chain problems, mainly caused by the country’s emergence from the COVID-19 pandemic.

With the probe underway, the Commerce Department said it will identify the key exporters or producers in each of the four countries and request “quantity and value” data about their shipments of photovoltaic cells and modules. The department will make a preliminary determination in the case in August, and SEIA said it expects the department to make a final determination in January. It could lead to even higher tariffs on solar panels, the organization said.

SEIA said on April 7 that it had surveyed 412 solar companies nationwide, of which 78% said that panel deliveries had been canceled or delayed since the Commerce Department announced the investigation. Fifty-six percent said the investigation put at least 70% of the projects in their pipelines at risk this year.

SEIA CEO Abigail Ross Hopper called the department’s investigation an “existential crisis” for the solar industry and criticized the fact that the case is based on the “industry killing claims” of only one company.

“The proponents of this case say that harsh tariffs are necessary to grow domestic manufacturing; that this case will have no adverse impact,” she said in a SEIA webinar earlier this month. “And if it does cause harm, that’s OK: The ends justify the means. They’re wrong.”

But the Coalition for a Prosperous America (CPA), a trade group that advocates for domestic producers, welcomed the investigation.

“Despite the fear mongering and lobbying by special interest groups that advocate for Chinese solar manufacturers, the Biden administration has chosen to side with American companies and workers,” CPA Chairman Zach Mottl said.

Coping With Shortages

In New Jersey, concern at disruption to the flow of solar panels is “freezing … slowing” development and causing “significant price impacts,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, which represents 26 state and national solar companies. Price hikes put developers in a bind because they can’t adjust their two main sources of revenue — state incentives and the price of energy — to offset the rise in project costs, he said.

In a Feb. 24 letter to Commerce Secretary Gina Raimondo, DeSanti urged the department not to start the investigation, saying that the inquiry could “could threaten existing and future solar projects that rely on imports, in addition to the well paid solar jobs that these projects create.”

New Jersey, like other states, is looking to rapidly expand its solar capacity to help reduce carbon emissions. Gov. Phil Murphy has set a goal of reaching 100% clean energy by 2050, with a goal of increasing solar capacity from about 3.84 GW at present to 17.2 GW by 2035. The state’s strategy for expanding the solar sector includes introducing a community solar program, increasing the number and capacity of grid-scale solar projects, and refocusing the state’s solar incentive programs while also reducing the cost to ratepayers. (See NJ Solar Pipeline Surges While Installations Drop.)

That kind of dramatic expansion, however, would suffer if, as the developers say, they couldn’t get the equipment needed to follow through with projects.

Scott Elias, director of Mid-Atlantic state affairs for SEIA, told the New Jersey Board of Public Utilities (BPU) on April 7 that the investigation “is already needlessly causing serious harm to the industry, including right now and right here in New Jersey.” He said that “no importer of record is going to bring solar cells or panels into the U.S. and risk the imposition of a retroactive 50 to 250% duty.”

“Solar customers do not have the capacity to absorb these massive costs,” he said. “And planned projects are unfortunately not going to be moving forward.”

In Colorado, Kruger said that in the longer term, developers that are forced to slow down business because of higher panel prices or delivery delays, as well as lay off workers, could find it difficult to take on new people in the future because of the tight labor market.

“So, this is just really frustrating,” Kruger said. “The uncertainty; the unknown: It’s immediately impacting the large-scale projects but will impact everybody in the not-too-distant future.” That will put in jeopardy the state’s efforts to cut emissions with solar energy, he said, predicting that instead of the state seeing the hoped-for double-digit growth in solar capacity over the previous 12 months, it will simply repeat the modest increase of 2021.

Yet the blowback from the investigation is not hurting all sectors of the industry.

Renova Energy, a Palm Desert, Calif., solar installation company, said that it has yet to be affected by the investigation and does not expect to see much impact in the future. One reason is that the company buys all its equipment from SunPower, which has a wide diversity of panel manufacturing sources that are outside the four Asian countries under scrutiny — among them Mexico — and, therefore, is unaffected by the Commerce Department’s action, Chief Sales Officer Nate Lewis said.

Renova officials also said the company’s focus on rooftop solar installations with higher quality panels, which have a higher energy conversion rate and longer life, means that it does not use the lower-end panels that are made by the manufacturers in the Commerce Department probe.

“We typically don’t look for the lowest cost equipment; we’re looking for the best value for our customers,” Lewis said. “And the cheap Chinese product doesn’t work well in our environment.”

A Fair Playing Field

The dispute over Chinese solar panel imports stretches back a decade, since the U.S. International Trade Commission concluded that Chinese producers of crystalline silicon photovoltaic cells had dumped and subsidized imports into the U.S., which placed anti-dumping and countervailing trade duties on those products.

Six months ago, the Commerce Department rejected a request by trade group American Solar Manufacturers Against Chinese Circumvention (A-SMACC) seeking an investigation into unlawful circumventing of antidumping and countervailing duties in the solar module market. Announcing the request in an Aug. 16 release, A-SMACC said it wanted to “ensure that the playing field for American solar manufacturing is level and ready for the scaled investments necessary to address climate change.”

“This targeted enforcement action ensures that the United States’ status as an innovation and manufacturing leader will not be endangered by exploitative trade practices that harm the American worker,” A-SMACC said.

But the Commerce Department rejected the request, saying that it could not conduct an investigation unless A-SMACC identified its members, which the department would need to know to ensure that the complainants were legitimately “interested parties.” The organization declined, claiming that that such information was “proprietary.”

The Commerce Department, however, launched the current investigation after Auxin Solar, a California-based manufacturer of solar panels, made similar claims.

The department is required to investigate several factors about the products, according to a memo explaining the decision to investigate. One is whether the solar panels are produced in the four countries using merchandise produced in China.

Other factors include how significant the work done in the four countries and whether the merchandise produced is “a significant portion” of the final value of the product that is shipped to the U.S., the memo says.

Shortfall of R&D, Investment

Auxin says that Chinese manufacturers and suppliers responded to the anti-dumping and countervailing duties by changing their tactics. Instead of “fairly pricing” their products, the producers shipped imports from “third-country export platforms,” the company told the department in its complaint.

“Their relentless predatory pricing has been fueled by China’s non-market subsidization of the upstream solar supply chain, intellectual property theft conducted by China’s People’s Liberation Army [the country’s military] and inhumane forced labor practices,” Auxin said.

Auxin provided evidence that producers in Cambodia, Malaysia, Thailand and Vietnam obtained products used in the production of solar panels — such as silicon wafers, silver paste, silane, solar glass, aluminum frames and junction boxes — from China, the department said in the memo. The company also showed that the four countries had experienced “recent surges” in the import of those products, it said.

In addition, China has as much as “99% of the worldwide solar wafer capacity, 95% of the worldwide solar ingot capacity and 64% of solar-grade polysilicon capacity,” the memo says. “According to Auxin, this demonstrates that the solar cell producers in Cambodia, Malaysia, Thailand and Vietnam would likely obtain solar-grade silicon wafers from China.”

Auxin also argued that the four countries had not made the kind of investment in polysilicon enrichment facilities to support the volume of production it was claiming, especially compared to the extensive Chinese investment in the same thing, according to the memo. And the countries also had made “minimal” investment in R&D related to completing and assembling solar cells into modules and so relied on Chinese knowledge rather than “developing their own technology,” the memo said. In addition, the comparatively small size of production facilities compared to Chinese facilities showed that the production facilities in the four countries are “limited,” the memo said.

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Massachusetts Senate Passes Bill to Amend OSW Price Cap Rules

The Massachusetts Senate on Thursday passed a bill 37-3 that would adjust the state’s existing offshore wind procurement price cap if enacted.

As passed, the bill amends Gov. Charlie Baker’s proposal (H.4204) to remove the existing OSW price cap, allowing instead a 10% increase over the winning per-megawatt-hour bid of the state’s previous procurement round. Under the current process, regulators cannot approve a bid that exceeds the winning bid of a previous procurement.

The total bid increase, however, must come from performance-based economic development and employment opportunities that support low- and middle-income populations and diversity, equity and inclusion programs.

Baker’s proposal became part of An Act Driving Climate Policy Forward (S.2819) (Drive Act) through a series of amendments (H.54524) in the House of Representatives that compile a broad set of policies for decarbonizing energy, transportation and buildings. The bill preserves Baker’s proposal to transfer the authority for selecting winning bids from the state’s utilities to the Department of Energy Resources (DOER).

The Drive Act is now before the House for final reconciliation and will go to the governor for his signature.

An amendment to the Drive Act introduced by Sen. Julian Cyr (D) and adopted during Thursday’s session would create a new phase in the state’s 83C OSW procurement process by tacking on 4.4 GW to an existing 5.6 GW procurement authorization.

The new authorization “would have Massachusetts realize one-third of President Biden’s goal to have 30 GW of offshore wind by 2030,” Cyr said on the Senate floor. “It establishes the trajectory for Massachusetts to realize the 15-20 GW of OSW needed under the pathways forecast in the Massachusetts 2050 Decarbonization Roadmap.”

Cyr’s amendment includes protections for coastal and marine environments and wildlife as well as provisions to ensure that federally recognized tribes have a voice in the OSW development process.

Funding

The Drive Act reduces Baker’s proposed $750 million Clean Energy Investment Fund in H.4204 to $100 million. Directives for the center’s funding include clean energy research and workforce and port infrastructure development.

An additional $100 million would be allocated to an Electric Vehicle Adoption Incentive Trust Fund and $50 million to a Charging Infrastructure Deployment Fund. Incentives under the EV fund support passenger car or light-duty truck purchases under $50,000.

A new interagency coordinating council would oversee the infrastructure deployment fund and deliver a report on deployment strategies to the legislature within a year of the bill’s effective date.

Transportation

A plan by the Massachusetts Bay Transportation Authority to electrify its bus fleet by 2040 would become law under the Drive Act, and all the authority’s passenger bus purchases or leases would have to be zero-emission vehicles starting in 2028.

An amendment introduced by Sen. Brendan Creighton (D) and adopted by the Senate would direct MBTA to purchase only electric rail cars by 2031. In addition, the authority would have to develop emission-reduction plans for each of its commuter rail lines.

Senators defeated another amendment that would have required electrification of public fleets, including state fleets and school buses, by 2035.

“Adoption of the provision requiring a phased plan for the electrification of commuter rail that prioritizes environmental justice communities is a welcome decision,” Veena Dharmaraj, director of transportation for Sierra Club Massachusetts, said in a statement.

Sierra Club, she added, is “disappointed” that legislators are reluctant to set fleet electrification targets.

“Communities across the state should not have to wait until 2050 to benefit from pollution-free school buses and municipal and transit fleets,” she said.

Buildings

In keeping with Massachusetts’ efforts to establish a net-zero stretch code that local governments can adopt, the Drive Act would allow a demonstration project for up to 10 municipalities to restrict fossil fuel use in new building construction. DOER would collect data from the project to help assess the effect of fossil-fuel free development on building emissions and costs.

An amendment introduced by Sen. Rebecca Rausch (D) and passed by the senate would direct utilities to provide public annual reports on the amount of natural gas and electricity used in buildings of more than 25,000 square feet.

Environment Massachusetts supported the amendment.

The bill “doesn’t do nearly enough to address the energy we use in our buildings,” Ben Hellerstein, state director for the nonprofit, said in a statement.

Senators defeated a separate amendment that would have established a large buildings energy performance standard like one passed last year for Boston.

The bill also addresses the decision-making process for the Department of Public Utilities’ ongoing investigation (Docket 20-80) into the role of gas distribution companies in reducing greenhouse gas emissions. Regulators would be required to hold an adjudicatory proceeding before approving any state gas utility’s decarbonization plan submitted under the investigation.

Adjudicatory processes would allow constituents to participate as intervenors in hearings and depositions.

Massachusetts’ gas utilities filed proposals with the DPU in March for reducing gas system emissions. Stakeholders have asked the DPU to expand the opportunity for input on the utilities’ proposals in the docket, including provision of technical evidence and cross-examination of utility witnesses.

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PJM MIC Briefs: April 13, 2022

Start-up Cost Offer Development Endorsed

PJM Market Implementation Committee members last week unanimously endorsed a revised proposal from the RTO and its Independent Market Monitor to address start-up cost offer development.

At the MIC’s April 13 meeting, Tom Hauske, principal engineer in PJM’s performance compliance department, reviewed the joint proposal to revise Manual 15: Cost Development Guidelines that came out of discussions at the Cost Development Subcommittee (CDS).

The CDS initially brought two proposals for first reads to the October MIC meeting. (See “Start-up Cost Offer Development,” PJM MIC Briefs: Oct. 6, 2021.) But a vote on the proposals was postponed to allow more discussions and have stakeholders reach consensus on a single proposal.

Manual 15 currently allows the start-up costs for combined cycle units to include fuel costs after generator breaker closure and synchronization to the grid, a feature not available to other unit types, such as steam and nuclear plants. The revisions align start-up costs for all units with a soak process, or units that use steam turbines.

Steam unit start-up cost offer procedure (PJM) Content.jpgPJM’s revised steam unit start-up cost offer procedure. | PJM

 

For units with a soak process, including steam, combined cycle and nuclear units, some of the soak costs are included in the start-up costs from PJM’s notification to the “dispatchable output” and from the last breaker open to the shutdown process.

Units that don’t have a soak process, like combustion turbines and reciprocating engines, maintain the status quo, with start-up costs that include costs from the time of PJM’s notification to the first breaker close and from the last breaker open to the conclusion of the shutdown process.

“We’re not implementing soak time at this point,” Hauske said. “We’re just allowing generators that have a soak process to include those costs in the startup cost.”

The revisions feature several other changes to Manual 15 to provide additional guidance and clarification, Hauske said, including equations to calculate start-up costs, station service calculations for units with and without a soak process and unit-specific parameter limits on includable costs.

Manual 15 currently allows generators to include an additional labor cost in their start-up costs, Hauske said, but generators already are permitted to include the labor cost in the unit’s capacity offer through its avoidable cost rate (ACR). The proposal calls for eliminating the labor cost language in the tariff and Operating Agreement offer cap sections and the start-up cost calculation so all the operating labor is includable in the ACR.

Hauske said PJM will provide a six-month window for implementation to allow market sellers the opportunity to have their fuel costs or net generation used for the offset to be reviewed by the Monitor prior to the proposal going into effect.

The proposal will be presented as a first read at the April 27 Markets and Reliability Committee meeting.

Stability Limit Changes

Zhenyu Fan, senior engineer in PJM’s real-time market operations, provided education and a first read of conforming updates to Manual 11: Energy & Ancillary Services Market Operations and Manual 28: Operating Agreement Accounting regarding stability limits in markets and operations.

In early 2021, stakeholders endorsed PJM’s proposal on stability limits capacity constraints that included language limiting lost opportunity cost (LOC) credits for any generation reduction required to honor the stability limit in the RTO. The limiting of LOC compensation led to debates among PJM members. (See “Stability Limits Endorsed,” PJM MRC/MC Briefs: Jan. 27, 2021.)

FERC ruled in February that PJM is within its rights to refuse (LOC) payments to generators that are temporarily required to limit output to prevent loss of synchronization and additional strain on the system during transmission outages. (See FERC: PJM Right to Block Gen Stability Limit Payments.) The tariff changes take effect June 1.

Zhenyu said PJM will use a new generator output constraint to enforce the stability limit for real power megawatt-only limits. He said the shadow price of the constraint will not be included or reflected in locational marginal pricing (LMP).

To provide greater transparency, Zhenyu said PJM added a new section to Manual 11 related to stability limits that describes the modeling, clearing and reporting process on the stability limit in the market. Updated language related to stability limits in Manual 28 included additional clarification that LOC credits are not paid for megawatts associated with a stability limit reduction.

Proposed stability limits (PJM) Content.jpgPJM’s proposed stability limits modeling and market clearing process. | PJM

 

Paul Sotkiewicz of E-Cubed Policy Associates said he disagreed with FERC’s decision on LOC payments. Sotkiewicz also disagreed with the proposed manual language, saying the changes don’t provide for “workarounds or a reconfiguration change” between PJM and the transmission owners to find ways to eliminate a stability problem.

“There’s a very easy workaround that eliminates the transient stability problem, and what I find alarming here is that there’s not going to be any effort made to do that,” Sotkiewicz said.

Phil D’Antonio of PJM asked Sotkiewicz to elaborate on a possible solution in the manual language. D’Antonio said his perspective has been that adjusting the system in an outage situation resulting from instability and limitations can end up “pulling the system apart even more.”

Sotkiewicz said he would want to look for “easy switching options” that are available to “eliminate the transient stability limit.”

“We’ve actually been in conversations with PJM operations, and we have found those solutions in the past,” Sotkiewicz said.

D’Antonio said he’ll take the suggestion back to PJM’s operations group for additional discussions before the next MIC meeting.

The committee will be asked to endorse the manual revisions at the May MIC meeting.

Intelligent Reserve Deployment Changes

Damon Fereshetian, senior engineer in PJM’s real-time market operations, provided a first read of additional updates to Manual 11 and Manual 28 related to intelligent reserve deployment (IRD).

Stakeholders in December endorsed a PJM proposal to improve the deployment of synchronized reserves during a spin event. (See “Synchronous Reserve Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.)

The proposal created an IRD, which is a security-constrained economic dispatch (SCED) case simulating the loss of the largest generation contingency on the system and for which approval of the case will trigger a spin event. The proposal included taking the megawatts of the largest generator contingency and adding them to the RTO forecast to simulate the unit loss. PJM can then flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.

Fereshetian said Manual 11 changes include the addition of new language that an approved IRD case “supersedes” any other approved real-time SCED cases for the same target time to be used as the reference case for the locational pricing calculator (LPC). In the verification section, PJM added clarifying language that the response to a synchronized reserve event is “based on the resource following dispatch instructions and is capped at the expected response.”

Manual 28 included minor clarifying changes.

The MIC will be asked to endorse the revisions at its May meeting.

Manual 29 Revisions

Natasha Holter, manager of PJM’s market settlement operations, provided a first read of revisions to Manual 29: Billing as part of the periodic review.

Holter said there were no “substantive changes” in the manual language and mostly included updates to terminology and reference materials.

Several new subsections were added to the manual, Holter said, including one called “Billing Notifications” that features language providing guidance on how to obtain notifications for billing statements. Another subsection, “Billing Adjustments,” added language to describe what a billing adjustment is and how to identify one.

Stakeholders will be asked to endorse the revisions at the May MIC meeting.

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Mass. Democrats Take on ISO-NE over MOPR

Several big voices in Massachusetts and D.C. politics are turning up the heat on ISO-NE as FERC considers the grid operator’s proposal to delay elimination of its contentious minimum offer price rule (MOPR) by two years.

In a speech outside ISO-NE headquarters last week, Sen. Ed Markey lambasted the organization as secretive, part of an “oil and gas conspiracy,” and standing in the way of the transition to clean energy.

“Instead of giving us the green light for our clean energy revolution, ISO New England is proposing to send us on a detour,” Markey said. “By proposing to delay the elimination of a rule that puts fossil fuel generation ahead of cleaner, cheaper alternatives, ISO New England is risking reliability and cost savings for residents across Massachusetts.”

Known for his affinity for wordplay and developing new acronyms, the senator said the MOPR should be called “Minimizing Our Potential for Renewables,” and that ISO-NE should be called the “dependent” system operator because “it’s dependent on gas and oil.”

“They have been in the past, they are today and their rules say they want to be in the future as well,” Markey said.

Markey’s speech also elicited support from Department of Energy official Jigar Shah.

“Time to find solutions instead of holding up clean energy projects waiting for more studies,” tweeted Shah, director of the DOE Loan Programs Office.

The two-year “transition” to eliminating the MOPR from ISO-NE’s capacity market, now in front of FERC for a decision, has received a high level of scrutiny from environmental advocates, elected officials and the renewables industry who have questioned ISO-NE’s claims about reliability worries stemming from an influx of renewables and possible corresponding retirement of merchant generators. (See ISO-NE Sends MOPR Filing to FERC, Teeing up Big Decision)

In an email to RTO Insider, ISO-NE spokesperson Matt Kakley defended the process that produced the proposal.

“Our robust, federally-approved stakeholder process includes the ISO, the energy industry, representatives from the New England states and advocacy groups. ISO New England’s proposals are fully examined and discussed before undergoing review by our federal regulator prior to implementation,” Kakley said.

Markey’s claims of conspiracy, Kakley added, are “so outlandish they do not warrant a response.”

“In addition, we are independent of the resources competing in the wholesale markets and do not favor any resource type over another. In fact, ISO New England employees work every day to ensure that all energy resources can compete in the market, can interconnect safely to the regional power grid and can operate reliably,” he said.

A Senatorial Plea to FERC 

Markey also wrote a letter, along with Sens. Elizabeth Warren (D-Mass.) and Bernie Sanders (I-Vt.) calling on FERC to reject the filing and force ISO-NE to immediately remove the MOPR.

“At the very moment when New England should be fully embracing the transition to renewables and the related socioeconomic opportunities, this decision to undermine state actions and renewable energy deployment is a terrible and ill-timed mistake,” the senators wrote. 

They specifically called on federal regulators to use their authorities under Sections 205 and 206 of the Federal Power Act to “require immediate reform” of the MOPR.

“In doing so, FERC will signal that renewable energy should be allowed to fully and freely compete in wholesale markets,” they wrote. “This will ultimately lead to lower prices for household customers and facilitate our overdue and necessary transition to a decarbonized electricity grid.”

Experts have said that FERC could respond to the filing in several possible ways, including accepting it, rejecting it outright or sending it back with a finding that the status quo is unjust and unreasonable and an explicit order to immediately terminate the rule.

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Extra Large PG&E Battery Project Goes Live

A major battery storage project built by Pacific Gas and Electric (NYSE:PCG) and Tesla (NASDAQ:TSLA) is ready to help California deal with the reliability problems it encountered in the past two summers, PG&E said Monday.

The utility said its 182.5-MW Elkhorn Battery facility had been “fully energized and certified for market participation by” CAISO earlier this month. The project’s 256 Tesla Megapack battery units sit on 33 concrete slabs on Monterey Bay and can discharge 730 MWh of electricity for up to four hours, providing energy and ancillary services to the grid.

“We are ushering in a new era of electric system reliability and delivering a vision into the future for our customers with the commissioning of the Tesla Megapack system in Moss Landing,” PG&E CEO Patti Poppe said in a news release. The utility owns and will continue to operate the units, it said.

The Elkhorn facility now ranks among the world’s largest battery energy storage systems (BESS), and it sits beside the No. 1 largest, Vistra’s (NYSE:VST) 400-MW Moss Landing facility, along with Vistra’s gas-fired Moss Landing Power Plant.

Moss Landing’s racks of non-Tesla batteries were shut down after overheating incidents in September and February triggered fire alarms, set off sprinklers and melted equipment.

“Vistra is in the process of conducting repairs, commissioning facility systems and implementing enhancements to improve the original design of the facility,” the company said in its initial findings on the September incident, released in late January about two weeks before the second incident occurred.

PG&E purchases Moss Landing’s output, along with energy from four other large BESSes: the 200-MW Diablo Storage System in Contra Costa County, the 60-MW Coso Battery Storage in Inyo County, the 63-MW NextEra Blythe system in Riverside County and the 50-MW Gateway system in San Diego County. All went online in the last two years.

Batteries for Reliability

In June 2021, the California Public Utilities Commission ordered PG&E and the state’s two other large investor-owned utilities, Southern California Edison and San Diego Gas & Electric, to procure 11.5 GW of new resources in the next three years to head off shortfalls.

It ordered the IOUs and other load-serving entities to purchase another 3 GW of additional capacity through supply- and demand-side programs to prevent shortages during potentially extreme heat waves in the summers of 2022 and 2023. (See CPUC Orders Procuring 3 GW of Capacity.)

The transition from fossil fuels to clean energy in California and other Western states has increased wind and solar generation while coal and gas plants have retired.

Reliability problems arose during Western heat waves in 2020 and 2021, as solar power waned on hot summer evenings but demand remained high. CAISO ordered rolling blackouts in August 2020 and declared energy emergencies both years.

Responding to the CPUC orders, PG&E said it hopes to have 3,300 MW of in-state battery storage under contract by 2024. More than 955 MW of that is already connected, and about 1,400 MW of storage capacity is scheduled to come online in 2022 and 2023, it said. PG&E won approval from the commission Thursday to contract with nine more proposed battery storage projects, totaling 1,600 MW, that could start operating between 2024 and 2026.

CAISO said it has added more than 2,400 MW of battery storage since the 2020 blackouts and expects to add 2,100 more by June.

The ISO posted a video in March on “California’s historic embrace of battery storage to support the grid as we transition to a carbon-free system.”

“Last summer was a pivotal moment for battery storage, and we felt it was important to document the story and to share our experiences and the lessons we learned,” CEO Elliot Mainzer said in a statement on the video.

“The potential of lithium-ion batteries had been talked about and anticipated for a long time,” he said. “Now they are a central part of our toolbox to make sure that supply and demand are balanced, and the system remains reliable even during the most challenging conditions.”

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BPA Set to Go Live in Western EIM in May

The Bonneville Power Administration is on target to enter the Western Energy Imbalance Market (WEIM) in early May after agency executives met Monday to make a final determination on its market readiness.

“BPA is on track to start participating in the Western EIM on May 3. Barring any unforeseen setbacks, we are a go,” agency spokesperson Doug Johnson told RTO Insider.

The federal power marketing agency was initially scheduled to begin transacting in the WEIM on March 2, along with Pacific Northwest utilities Avista and Tacoma Power, but in January it decided to delay entry by two months because of customer training and technology issues. (See BPA Postpones Western EIM Entry by 2 Months.)

During a stakeholder meeting in late March, BPA officials said the agency was on course for the May 3 entry despite remaining issues related to market technology. But they noted that they would still meet privately April 18 to make a final decision, citing the need for a smooth integration to best serve stakeholders. (See BPA ‘Full Speed Ahead’ on May EIM Entry, but Issues Remain.)

The decision came without fanfare or notice on the agency’s website. Johnson called it a “procedural, but important, step in our march to participation.”

That march began in 2018 with a long series of stakeholder meetings leading to a September 2019 signing of an EIM implementation agreement, followed by last September’s official decision to commit to joining the market. Over the course of those developments, BPA was already engaged in an exhaustive process to prepare its customer base of publicly owned utilities for the complexity of market integration.

BPA will be the most significant entrant into the WEIM since the market commenced operation in November 2014 with PacifiCorp, and its two utilities’ six-state territory, as its pioneering member.

With 15,000 miles of high-voltage transmission and 31 hydroelectric projects under its control, BPA will be the largest transmission and hydro provider in a market that now includes 16 members with territories spanning most of the Western Interconnection.

The agency controls about three-quarters of the transmission in the Northwest, making its system a vital link between the Northwest’s massive network of hydroelectric dams and WEIM areas in California and the Southwest that are becoming increasingly reliant on solar energy. The flexibility of hydro generation is particularly well suited to firming up the variable output of intermittent renewable resources.

BPA also owns more than 50% of the capacity on the California-Oregon Intertie, which links the Northwest into the CAISO system in Northern California, and — along with the Los Angeles Department of Water and Power — is half-owner of the Pacific DC Intertie, a 500-kV line that delivers energy into Southern California. LADWP began participating in the EIM last year.

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NY Climate Council Ramps Up Natural Gas, Alt Fuels Planning

New York’s Climate Action Council on Monday agreed to form new committees to help develop the state’s plans for reducing natural gas use, expanding alternative fuels and adopting economy-wide measures to cut emissions.

The CAC is holding public hearings through June 10 on its draft scoping plan that lays out steps needed to achieve the emission limits set by the Climate Leadership and Community Protection Act. The council has received 8,000 written comments and heard 200 people comment through four of 10 hearings, CAC Director Sarah Osgood said.

The original timeline to end the public comment period in mid-May proved unrealistic, she said. (See NY Officials Set 2022 Schedule for Climate Plan.)

“While others would prefer that the climate actions happen faster, we also heard concerns about affordability of electricity and the cost of the transition, specifically the cost associated with moving homes to all electric,” Osgood said. “A number of commenters expressed concerns about potential job losses among energy and utility workers and encouraged the council to take action that would ensure that the issue would be addressed.”

Administrators are planning to provide a distilled summary of the comments a month after the close of the comment period, Osgood said.

Committee Tasks

State officials and contractors presented outlines of what committees on gas system transition, alternative fuels and economy-wide measures could focus on in the coming months, with the council meeting at least monthly or more often as the workload increases over the summer, Osgood said.

The CAC will recruit volunteers for the committees to start meeting in May so the council can complete a final scoping plan by year-end that shows how the state will reduce economy-wide greenhouse gas emissions 40% by 2030 and no less than 85% by midcentury from 1990 levels, she said.

The gas transition will outline a coordinated plan to downsize the gas system, led by the Department of Public Service and supported by the New York State Energy Research and Development Authority (NYSERDA), Long Island Power Authority, New York Power Authority and the Department of Environmental Conservation.

The committee will consult with utilities, environmental justice groups and sectoral experts and draw upon successful plans in other jurisdictions, as will the alternative fuels committee in developing draft guidelines on the use of hydrogen, renewable natural gas and other biofuels.

DEC Deputy Commissioner Jared Snyder opened a discussion about the economy-wide committee, which will look at the certainty of emission reductions, the certainty of carbon price impacts on disadvantaged communities and affordability, and some competitiveness issues, such as the risk of leakage from carbon pricing.

NYSERDA will provide the council with analyses on existing carbon pricing knowledge and experience in other jurisdictions as well as the effects of a price on carbon specifically in New York, said Vladimir Gutman-Britten, assistant director of policy and markets.

“We want to share data on some of the key policy design choices in pursuing a system like this and the particular tradeoffs that might come with it,” Gutman-Britten said. “This analysis will help elucidate the impact of such a carbon tax on emissions and a variety of macroeconomic metrics, such as economy-wide energy spending, leakage of emissions and economic activity.”

State planners, he said, are not endorsing a policy of carbon pricing but choosing it because of limitations on modeling tools available, adding that “while we will be evaluating this one type of policy, we still think it would provide insights into how other approaches might work.”

Additional analysis may include potential effects of a large-scale investment program, including a sense of scale and the kinds of emissions reductions such a program might be able to yield under different spending choices, Snyder said.

The idea is “to unpack the kind of impact that pricing and an investment program might have on specific clean energy solutions … key technology things like EVs, heat pumps and things like that so we can better understand how the economics of those solutions change as a result of different policy choices the state will make,” Snyder said.

Kevin Hansen senior vice president and head of public policy at Empire State Development, the state’s main economic development agency, urged the economy-wide committee to continue “to think about impacts on businesses and workers and the issue of leakage.”

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ERCOT Technical Advisory Committee Briefs: April 13, 2022

TAC Passes Contentious Outage Measure over Staff’s Objections

ERCOT stakeholders on Monday declined to consider staff’s appeal of a tabled revision request that would create a process allowing the grid operator to review, coordinate and approve or deny all planned outages.

The Technical Advisory Committee instead approved its version of the nodal protocol revision request (NPRR1108), as amended by several joint commentators. The measure now goes before the Board of Directors for its consideration April 27-28.

The measure was passed unanimously, 26-0 with a pair of abstentions, during an emergency webinar Monday after it was tabled following more than an hour of discussion last Wednesday during TAC’s regularly scheduled meeting.

The measure was also tabled at the Protocol Revision Subcommittee (PRS) last November over concerns that staff’s proposal was inflexible and could lead to an inability to get planned outages completed. That would lead to decreased reliability in the months when there is higher demand on ERCOT’s generation fleet, they said.

Staff drafted NPRR1108 to meet the requirements of legislation passed last year in the wake of the February winter storm that nearly brought the ERCOT grid to its knees. Senate Bill 3 included a provision that the grid operator “shall review, coordinate and approve or deny requests by providers of electric generation service … for a planned power outage during any season and for any period of time.”

Under ERCOT’s original proposal, staff would review and coordinate all planned outages, including those submitted more than 45 days before the outage’s planned start. The revisions would:

  • define a process for calculating a maximum megawattage of planned outages that would be allowed for each day of the next rolling 60 months, based on a capacity assessment;
  • require that a planned outage, or change to an approved outage, submitted more than 45 days in advance of the planned start time would no longer be “accepted” but would be approved on a first-come, first-served basis if the resulting aggregate planned outages are below the daily maximum megawattage for each day of the proposed outage’s duration; and
  • require that a planned outage or change to an approved outage submitted less than 45 days in advance of the planned start time would be evaluated against the maximum daily planned resource outage capacity (MDRPOC) and for impacts on transmission reliability.

Dan Woodfin, ERCOT’s vice president of system operations, complained that the grid operator last November asked for stakeholder feedback within months. The lack of input has pushed back the methodology’s implementation to fall 2023, he said.

Reliant Energy Retail Services’ Bill Barnes, acting as the PRS advocate, said the NPRR included many inputs subject to discretion.

“Stakeholders needed to fully assess the methodology needed to see the results of the calculations,” he said, explaining why the measure has remained tabled.

The two sides have traded competing versions of their comments, with ERCOT filing the last Sunday night. In the comments, staff proposed to allow nuclear generators to schedule planned outages, even if the resulting outage capacity would exceed the MDRPOC. They also agreed with the residential consumer segment that they should prove a report to TAC on the MDRPOC’s effects.

Stakeholders stuck with the joint commentators’ filing, which requires the MDRPOC for outages more than seven days ahead of the operating day be posted twice each to provide greater transparency and reduce the risk of potentially large changes when “stale monthly long-term MDRPOC projections” are replaced by the near-term projections less than seven days ahead of the operating day.

They also call for outage guardrails that are sensitive to concerns about weather variations during outage seasons to provide predictable minimum outage windows for resource owners and still allow ERCOT to deny outages on days over the MDRPOC.

ERCOT legal counsel Nathan Bigbee fired back Monday over the notion that the outage-approval process should be subject to TAC approval.

“There seems to be kind of a disconnect between industry in general and the ISO over what exactly the methodology should be,” he said. “It seems likely the methodology we prefer is a methodology TAC would not endorse. Having that control would lead us down a path less in the interest of reliability. That’s why we don’t think it’s appropriate. Ultimately, the board is going to be the arbiter of those decisions.”

ERCOT can file additional comments on NPRR1108 with the board or appeal the decision to the Public Utility Commission for an appeal.

Unsecured Credit Limit Lowered

TAC on Wednesday approved a measure that reduces unsecured credit limits from $50 million to $30 million, but not before a back-and-forth between one member and a staffer over uplift that resembled Monty Python’s classic “Argument Clinic” sketch.

“I fundamentally disagree with your concept of how the market works,” Kenan Ögelman, ERCOT’s vice president of commercial operations, told Morgan Stanley’s Clayton Greer.

PRS amended NPRR1112 in March to reinstate unsecured credit limits. ERCOT responded with comments that said eliminating unsecured credit “will reduce the inconsistent cross-subsidization of credit exposure and provide a more level playing field for market participants.”

Members disagreed. Garland Power and Light’s Dan Bailey said staff’s response was “the most ridiculous problem ERCOT has tried to solve without solving the problem.”

“From a market and consumer standpoint, taking a nuclear approach to credit is a little bit questionable,” he said. “Why ERCOT would think this is the right direction to go has left me scratching my head. I’m baffled to see that ERCOT is going down this path.”

TAC rejected an motion to amend the measure with ERCOT’s comments, 3-16 with 11 abstentions. It attracted approval only from the two residential consumer representatives and retailer Reliant Energy.

A motion to approve PRS’ recommended version passed 23-2 with five abstentions. The residential consumer representatives cast the two opposing votes.

RUC Process Changes Endorsed

The committee approved a pair of rule changes related to reliability unit commitments (RUCs), which have been increasingly used by ERCOT since last summer as part of its conservative operations approach.

NPRR1124 is intended to ensure generation resources recover their actual fuel costs when they are RUCed by setting the start-up price and minimum-energy price to the start-up cap and the minimum-energy cap.

The measure was opposed by all six consumer segment representatives, who objected to consumers bearing the increased costs.

TAC also approved a motion related to NPRR1092, which lowers the RUC offer floor to $250/MWh from $1,500/MWh, as amended by clarifying ERCOT comments April 6. Members approved the measure in March, pending an impact analysis from staff. (See “RUC Offer Floor Lowered to $250,” ERCOT Technical Advisory Committee Briefs: March 30, 2022.)

Staff said it will cost between $50,000 and $75,000 and take four to six months to change the RUC offer floor, as proposed by the Independent Market Monitor. The measure still needs regulatory approval and prioritization.

The motion passed 25-1, with Luminant opposing and two representatives each from the cooperative and independent power marketer segments abstaining.

Ögelman Addresses Concerns with Board Interactions

Ögelman responded to stakeholder concerns about their interactions with the board’s new Reliability and Markets Committee, saying that the directors are still working through the structure they want.

“The board’s trying to figure out how they want to do business and what they might want to do differently,” he said. “Right now, we have to beg everyone to be patient with us and work with the board to give them the processes they want. They have a vision … they’re just not ready to share it yet.”

Ögelman was responding to a clarification request from the Wholesale Market Subcommittee, which reports directly to TAC. ERCOT’s bylaws require TAC to report to the full board, rather than a board committee; any bylaw changes would require a vote of the full membership, Ögelman said.

Two More SCT Directives Approved

TAC endorsed staff’s response to two additional directives issued by the PUC related to the Southern Cross Transmission (SCT) project, a merchant long-haul HVDC transmission line that would connect ERCOT with systems in the SERC Reliability region.

In responding to the 14 PUC directives, ERCOT staff found they would not need to study and determine transmission upgrades to address congestion caused by SCT (No. 6). Staff determined in the second directive (No. 8) that as of Jan. 1, 2021, DC ties should be required to have at least a 0.95 power factor leading/lagging reactive power capability, which several revision requests have already addressed.

The SCT would be capable of carrying 2 GW of power between Texas and SERC over a 400-mile, double-circuit 345-kV line. The project has FERC approval and a waiver from the commission’s jurisdiction. It also has a certificate of convenience and necessity granted by the PUC in 2017 to Garland Power & Light, which owns the project’s western endpoint.

The PUC last year directed its staff to file a memo asking the proceeding’s parties for suggestions on accelerating the project, which has been under regulatory review for more than seven years (46304). (See Texas Regulators Boost Southern Cross Project.)

ESRs’ Minimum Duration Set at 2 Hours

TAC’s unanimously approved combination ballot included a recommendation from the Reliability and Operations Subcommittee to set a minimum duration threshold of two hours for energy storage resources (ESRs). Lower-duration ESRs would be prorated to their continuous real power capability for two hours.

The combo ballot included two additional NPRRs, a Nodal Operating Guide revision (NOGRR), two revisions to the Planning Guide (PGRR) and a change to the Settlement Metering Operating Guide (SMOGRRs):

    • NPRR1117: aligns the protocols with the Settlement Meter Operating Guide revisions to allow for losses in short runs of connecting lines to be disregarded when the ERCOT-polled settlement meter (EPS) is not physically placed at the point of interconnection (POI).
    • NPRR1125: clarifies that ERCOT may use available financial security held for other market activities should there be payment defaults in either of the two securitization proceedings. The change also specifies the prioritization for applying the securities when there are concurrent defaults for either invoices or escrow deposit requests.
    • NOGRR239: delineates the responsibilities for providing security for data transmitted between ERCOT, qualified scheduling entities and transmission operators.
    • PGRR096: establishes requirements for the consistent representation of distribution generation resources, distribution energy storage resources, settlement-only distribution generators and unregistered distributed generation in steady-state base cases.
    • PGRR098: enables corrective action plans to be developed under certain outage scenarios to the existing reliability performance criteria.
    • SMOGRR025: allows for losses in short runs of connecting lines to be disregarded in instances where the EPS meter is not physically placed at the POI and requires calculation to verify that the watts copper losses are below 0.001%.