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November 8, 2024

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MISO Considers Adding Smaller Congestion Relief Projects

MISO said Tuesday that it’s contemplating adding a class of smaller, congestion-relieving projects under its annual transmission planning.

Engineering adviser Ben Stearney told stakeholders during a Planning Subcommittee meeting that staff was inspired by its Targeted Market Efficiency Projects (TMEPs) process with PJM. MISO studies TMEPs for interregional purposes only, not under its own regional planning.

Stearney said the RTO may introduce additional TMEP-style planning to its annual Transmission Expansion Plan (MTEP) to alleviate the footprint’s increased congestion. He said “a TMEP-like process in a regional context” with a traditional production cost analysis could produce smaller transmission projects that clear congestion near existing generation resources.

Under MISO’s TMEPs process with PJM, projects must cost less than $20 million, completely cover installed capital cost within four years of service and be in service by the third summer peak from its approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.

Stearney said staff are conducting an “exploratory investigation” and could introduce a TMEP-like component in time for MTEP 23. MISO will begin building the MTEP 23 economic models near the end of the year.

WPPI Energy engineer Steve Leovy said he appreciated the evaluation because congestion costs have skyrocketed in the last two years and because MISO hasn’t conducted a market congestion planning study as part of MTEP since 2019. Leovy said the grid operator lacks “ongoing economic planning occurring in the near term.” He pointed out that MISO’s long-range transmission planning looks out at least 10 years, leaving immediate congestion fixes unaddressed.

The RTO’s members late last year questioned whether MISO’s planning is sufficiently addressing mounting transmission congestion.

Leovy has said generators in the footprint’s northwestern system with firm transmission service are feeling congestion’s squeeze and has said MISO’s economic modeling may not be capturing all congestion-relief opportunities.

The RTO might be assigning network upgrades that don’t consider all impacts of new generation projects given the raft on new projects in the Northwest, Leovy contends.

Last month, MISO’s Independent Market Monitor warned that MISO’s day-ahead and real-time congestion increased this winter by 142% and 118 %, respectively, compared to last winter. The Monitor said about half of the real-time congestion could be attributed to wind generation. (See MISO Says System Volatility Here to Stay.)

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NJ Tries to Balance Solar Growth vs. Farmland Protection

Drafted to help achieve an ambitious goal of nearly quadrupling New Jersey’s solar output over the next decade, new rules proposed by the state Board of Public Utilities (BPU) to govern what land can be used for projects received a moderate reception last week, with little outright opposition but a stream of queries and suggested improvements.

More than a dozen speakers — among them solar developers, environmentalists and farming advocates — raised a host of thorny issues, among them how the rules would work in practice, what protections for soil are in place and how flexible the guidelines would be when enforced. Key among the issues raised by developers were concerns that the cost of compliance would be so great that projects would become unviable.

“I do think that job No. 1 should be to make sure that we can accomplish these purposes at the lowest possible cost,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition.

Matthew Tripoli, director of project development at CS Energy, said the company supported statewide standards that would apply to all projects.

“It’s a great idea to have having the rules be extremely clear, as it looks like [that’s what] the attempt is here with these guidelines,” he said. “We’re just a little concerned that the guidelines as proposed don’t really seem to provide much flexibility and seem to value [agriculture] impacts over and above all others.”

Ethan Winter — Northeast solar specialist for the American Farmland Trust, which works to protect farmland and promote environmentally sound farming practices — said the BPU should place greater scrutiny on what soil would be affected by proposed projects and how to reduce the impact.

“We would encourage New Jersey to set a high standard in terms of minimizing and avoiding soil disturbance in the first place,” he said.

The release of the guidelines follows growing concerns in New Jersey, as in other states nationwide, over the impact of rising demand for space on which to site solar projects on farmland. Aggressive demand for land, and related high-priced lease and purchase offers from developers, has forced farmers to decide whether to accept the income from solar opportunities or reject it to protect their farms and way of life. (See NJ Solar Push Squeezes Farms.)

A similar dynamic has played out in Ohio, where solar supporters see a 350-MW project on 1,880 acres of prime farmland bringing much needed revenue for schools. In San Diego, local officials see solar developments as key to cutting carbon emissions and eye farmland as the place to put them.

In New Jersey, there is an additional dynamic: The pressure to develop farmland has been elevated by an explosion in the demand for warehouse space from e-commerce and logistics companies that serve the Port of New York and New Jersey and the massive New York-area population.

Evaluating Solar Sites

The hearing was the second into the siting proposals, which were drafted as part of the state’s new Competitive Solar Incentive (CSI) program.

The program governs utility-scale projects and net-metered commercial installations larger than 5 MW. It is part of the state’s Successor Solar Incentive (SuSi), which the BPU approved in July as part of a reshaping of the state incentive programs designed to reduce the cost of projects while stimulating the development of certain types.

New Jersey Gov. Phil Murphy wants the state to reach 100% clean energy by 2050, with solar a key part of the equation. The state’s official Energy Master Plan calls for deploying increasing amounts of solar: 5.2 GW by 2025; 12.2 GW by 2030; and 17.2 GW by 2035. Yet the state’s new installation capacity in recent years has been well below what would be needed to reach those goals.

The location guidelines under the CSI program divide potential solar sites into four categories, each of which treats the projects differently. One category covers land on which any development is prohibited, which includes preserved farmland and areas that contain prime agricultural soil. A second category — such as wetlands or forest land protected by the state — allows construction only if the BPU approves a waiver. A third category allows the siting of a solar project subject to a cap that limits how much of that land can be developed for solar capacity statewide. And the fourth category is land for which there are no restrictions on what solar developments can be undertaken.

The rules also set out guidelines designed to mitigate the impact on the land of an approved project as it advances to completion. The rules include a requirement that the developer hire an environmental monitor, take stormwater management measures and implement soil stabilization measures.

The aim of the rules is to “minimize as much practical and potential environmental impacts, and include consideration of existing and prior uses of the property, any conservation or agricultural designations associated with the property and the amount of soil disturbance,” Steven Bruder, planning manager for the State Agricultural Development Committee, told the hearing. “The soil protection guidelines are intended to apply whenever the intention is to return lands to agricultural use [at] the end of the life of the solar installation project.”

That scrutiny will include a “six-year-monitoring period” that will include an evaluation of the site every other year, said Frank Minch, director of the Department of Agriculture’s Division of Agriculture and Natural Resources.

Protecting Soil

The close evaluation of the site made sense to Amy Hansen, policy manager at the New Jersey Conservation Foundation, who said she also owns and operates and organic fruit and vegetable farm. She urged the state to ensure that the project inspector has a good knowledge of “soil health.”

“I think it’s important to not be under the impression that topsoil will ever return to its original condition once it’s been removed and moved,” she said. “Removal of topsoil will negatively impact the soil structure and chemistry, as soils form over thousands of years. It’s a delicate balance. So, I think protecting soils, especially prime and soils of statewide importance, really needs to be a strong requirement.”

That kind of close attention to the soil, however, raises concerns for Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, who said that parts of the industry already embrace some of the BPU’s proposals, such as hiring an environmental monitor. He said a “workable siting process is imperative” if the state is to create enough new capacity to meet its goal of 1,500 MW of large-scale solar facilities by 2026, and suggested that some of the guidelines go too far.

For example, a BPU requirement that the developer conduct a soil compaction test every 250 feet before and after construction could be “unduly burdensome and impractical for larger facilities,” he said. And a requirement that land be seeded and mulched within “seven days of disturbance” is impractical; the time period should be extended to 90 days, he said.

“We really do think this is moving in an OK direction,” he said. “But we do think we need to further balance the need for permitting more solar projects with protecting property rights and sensitive ecosystems.”

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Massachusetts Transportation Bond Bill Seeks to Unlock $4B in IIJA Funds

Massachusetts Gov. Charlie Baker gave testimony Tuesday for a transportation bond bill that would unlock $4.1 billion in funding from the Infrastructure Investment and Jobs Act (IIJA) signed by President Biden in November.

The bill (H.4561) would authorize the state treasurer to issue up to $5.6 billion in bonds to ensure the state can meet federal matching requirements for varying percentages of infrastructure project costs.

“We’ve developed a plan to invest billions of dollars in communities throughout the commonwealth over the next five years using the resources from [the IIJA],” Baker said. “That’s why we filed this legislation to authorize $9.7 billion to prepare for the resources and funding that will come to the commonwealth through this bill.”

Baker signed a $16 billion transportation bond bill in January 2021 that included $4.4 billion in federal funding for the next two years. At that time, Baker said, his administration expected to ask the legislature to authorize additional funding for transportation in the near term, but passage of the IIJA altered their plans.

The IIJA “increases the annual level of federal funding that goes well beyond what we had anticipated for the next five years,” Baker said.

Baker introduced the new bond bill on March 21, declaring it an emergency measure that requires action before the end of the legislative session in July. He acknowledged that the bill creates a lot of work for the legislature in a short time and will attract an “enormous amount of interest.”

Funding in the bill includes $200 million for the Executive Office of Energy and Environmental Affairs (EEA) to implement programs for public alternative fueling and EV charging stations, e-bikes, EVs for hire or sharing, and medium-duty EV trucks.

Of the total allocation for the EEA, Baker said, $150 million is set aside for investments that promote equity and improve public health, such as EV incentives for low-income families or electric school bus purchases. EEA’s remaining $50 million allocation will be used for matching funds to help the state compete for discretionary grants.

A $1.4 billion allocation to the Department of Transportation would support modernization of the transit system, including the Massachusetts Bay Transportation Authority’s (MBTA) plan to electrify its fleet of 1,100 buses by 2040. A bill (S.2292) currently before the Joint Transportation Committee would advance the deadline for MBTA’s fleet electrification to 2030. The committee has until April 29 to report that bill to the legislature.

The DOT would receive another $43.4 million from the bond bill for projects that improve regional transit networks and facilities through, among other things, rehabilitation of facilities to support clean vehicles. Facility upgrades necessary for MBTA’s full bus fleet electrification will cost $4.5 billion, according to the authority.

Additional allocations to the DOT that support the state’s climate laws include $2.8 billion for projects on the interstate and non-interstate federal highway system, including EV charging infrastructure; and $145 million for planning across all transportation modes, including supporting reduction of greenhouse gas emissions from transportation.

To help the state compete for discretionary and grant program funding in the IIJA, the bond bill includes a $3.5 billion authorization, Baker said. While the state awaits grant program guidance, he added, “it’s critical that … we have the authorizations in place so we will be able to move quickly and efficiently to deliver additional federal funding to the commonwealth.”

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CARB Seeks More Inclusive Clean Cars 4 All

As California prepares for an expansion of the Clean Cars 4 All program, officials are working on strategies to make sure the clean vehicle purchase incentive for low-income residents goes to those who need it most.

The California Air Resources Board (CARB) has proposed a household income limit of 300% of the federal poverty level for drivers to receive the incentive under the expanded program.

But the income limit could be just one piece of a needs-based approach to the incentive, said Aaron Hilliard, manager of the Alternative Strategies Section within the Incentives & Technology Advancement Branch at CARB.

“[We’re] looking at potentially other metrics for determining who is in the greatest need, other than just income,” Hilliard said.

Hilliard’s comments came during a CARB workshop on Monday to discuss the statewide expansion of Clean Cars 4 All. CARB staff described the workshop as a kick-off meeting on program expansion, with many details yet to be ironed out.

CARB’s Anthony Poggi said the agency is looking at how it would prioritize applicants in disadvantaged communities. The strategy will include working with community-based organizations and Access Clean California, a program that helps lower-income residents find clean energy benefits for which they’re eligible.

Program implementation is another variable in the Clean Cars 4 All expansion, according to Hilliard, who said CARB has heard comments about the drawbacks of first-come, first-served vehicle incentive programs.

Air District Involvement

In Clean Cars 4 All, an eligible driver agrees to scrap their old car in exchange for an incentive to buy a new or used hybrid, plug-in hybrid or zero-emission vehicle.

The Clean Cars 4 All incentive is currently offered by four California air districts: the Bay Area Air Quality Management District (AQMD); the Sacramento Metropolitan AQMD; the South Coast AQMD, which calls the program Replace Your Ride; and the San Joaquin Valley Air Pollution Control District (APCD), which calls the program Drive Clean in the San Joaquin.

The San Diego County Air Pollution Control District is getting ready to launch the program. CARB provides funding to air districts to administer the program.

A CARB regulation currently limits Clean Cars 4 All participation to air districts with a population of 1 million or more. And drivers receiving an incentive must live in a zip code that contains a disadvantaged community census tract.

But under the statewide expansion, those restrictions would be dropped. Poggi said the statewide expansion would not affect existing programs in the four air districts or the one in San Diego. Instead, the statewide program would be complementary to those programs.

CARB plans to recruit a statewide administrator to run the expansion program. The agency expects to release a solicitation for the position in early June.

Requirements Debated

For the statewide expansion of Clean Cars 4 All, CARB has proposed a household income limit of 300% of the federal poverty limit, which works out to $65,880 for a household of three or $79,500 for a household of four. About 90% of program participants already meet this income requirement.

Beverly DesChaux, president of the Electric Vehicle Association of Central Coast California, suggested targeting the incentive to drivers whose cars are “big, fat polluters.” The size of a car, its age and how much it’s driven could be factored in, she said.

DesChaux also called for restricting the Clean Cars 4 All incentive to plug-in hybrid or zero-emission vehicles and eliminating non-plug-in hybrids from the program.

“A hybrid … is simply a gas car that has a little electric motor that boosts the mileage a little bit,” she said.

Poggi said that hybrids were being included in the statewide program to give participants options on what to buy. He noted that air districts are being given flexibility on whether to include hybrids in their programs.

LaDonna Williams, programs director with All Positives Possible, a non-profit organization promoting disadvantaged communities’ right to a clean environment, said CARB’s proposed changes would make Clean Cars 4 All more inclusive.

Disadvantaged and low-income populations, particularly African-American communities, have fallen through the cracks in the past, she said.

Williams also cautioned against dictating drivers’ choice of car, even if a polluting vehicle might be offensive to some. Not everyone has money to cover the expense of a newer car, she said.

“Because we see someone driving a big vehicle or a gas car, that might be our personal opinion, but we also don’t want to end up being policed,” Williams said. “Because, again, at the end of the day, we know what population is going to be targeted the most for that, so we want to keep these options open.”

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NERC Director Joins WECC Exec Team

WECC said Tuesday that Steven Noess, NERC‘s director of regulatory programs, will join the West’s regional entity as its new vice president of reliability and security oversight beginning April 29.

Noess will take over a role previously filled by Steve Goodwill, who last fall became WECC’s senior vice president of strategic engagement.

At NERC, Noess leads a working group that supports “the alignment, effectiveness and oversight” of the Compliance Monitoring and Enforcement Program (CMEP) activities within the ERO Enterprise, according to a WECC release.

He recently co-led a team of 50 experts on the FERC-NERC inquiry into the February 2021 cold weather event that caused numerous outages and derates across Texas, leading to the largest manually controlled load-shedding event in U.S. history. (See FERC, NERC Release Final Texas Storm Report.)

In his new position, Noess will oversee development of WECC’s own CMEP and manage teams within the RE’s Oversight department, including Entity Monitoring, Risk Assessment and Registration, and Enforcement and Mitigation.

“Steve [Noess] brings in-depth oversight knowledge to the role, which will enable him to immediately take the lead in this critical position,” WECC CEO Melanie Frye said Tuesday in a statement. “His extensive ERO Enterprise-wide regulatory knowledge, coupled with his ability to successfully collaborate with external stakeholders to achieve reliability goals, will be an additional asset for WECC.”

Noess joined NERC in May 2011 as a standards developer, a position in which he led efforts to complete version 5 of the ERO Enterprise’s Critical Infrastructure Protection program, according to his LinkedIn profile. He was subsequently promoted to the roles of director of standards development and director of compliance assurance and program oversight before taking on his current position.

Prior to joining NERC, Noess was an attorney at the Minnesota legislature, where he managed development of legislation related to economic development, employment law and business and professional codes/licenses. He also helped develop administrative rules for executive branch agencies. He previously served as a captain in the U.S. Army and was deployed to Iraq in 2003, where he was awarded a Bronze Star.

Noess is a graduate of the U.S. Military Academy at West Point and holds a Juris Doctor from the University of Minnesota.

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SEC Chair, Investors Defend Draft Climate Disclosure Rule

Securities and Exchange Commission Chair Gary Gensler and officials of two large investment funds on Tuesday defended the SEC’s proposed disclosure rule for climate risks, saying it will bring consistency and transparency.

Gensler said the proposed rule, released following a 3-1 vote in March, is consistent with the commission’s “long tradition of disclosures,” which began with reporting of companies’ financial performance and executive pay. (See SEC Seeks Standard Disclosures for Climate-related Business Risks.)

“The core bargain from the 1930s was, and still remains, that investors get to decide which risks to take,” Gensler said during a webinar by Ceres, a nonprofit that promotes corporate sustainability practices. “Risk by definition often involves events that have not yet occurred — the future. So back in 1964, the SEC started to offer guidance about disclosure of risk factors. The agency later adopted disclosure requirements related to management discussion and analysis in the late 70s. Then, they also added environmental-related disclosures. … The same principle applies again and again: Investors get to decide which risks to take, as long as the public companies provide full and fair disclosure and are truthful in the disclosures.”

Gensler urged investors and filing companies to submit comments on the rule before the May 20 deadline. “We’ve already gotten a lot of feedback: some of it for the proposal, some against. That’s what we need to hear,” he said. “And we need to hear the reasons too. We need to hear all sides of this. We consider all of those comments in determining whether and how to adjust the release as we move forward.”

The SEC’s proposal is based on the international Financial Stability Board’s Task Force on Climate-Related Financial Disclosures (TCFD). It would require disclosure of climate-related risks with a “material impact on its business, results of operations or financial condition.”

The rule also would require publicly traded companies to disclose their greenhouse gas emissions, including Scope 1 (company vehicles and facilities) and Scope 2 (purchased electricity, steam, heating and cooling for the company’s own use).

Disclosure of Scope 3 emissions (including indirect emissions from purchased goods and services and the transportation and use of a company’s products) would only be required if they are material or if the company has set a GHG emissions-reduction target that includes Scope 3.

Manchin: ‘Not Necessary’

Earlier this month, Sen. Joe Manchin (D-W.Va.) joined with Republicans in criticizing the rule, saying it undermined “the all-of-the-above energy policy that is critical to our country right now.”

“I cannot help but consider the true need for that mandate when the commission itself reports that ‘nearly two-thirds of companies in the Russell 1000 Index, and 90% of the 500 largest companies in that index,’ already publish sustainability reports that include information about climate risks,” Manchin said in an April 4 letter to Gensler. “In that sense, one could argue that the proposed rule aims to solve a problem that does not exist.”

But Ceres President Mindy Lubber said her organization’s analysis of comments filed with the SEC last year found “overwhelming support” from investors and companies for mandatory standards that are consistent with those used globally.

Lubber said the current voluntary reporting “is not good enough.”

“We want information to be accessible, clear, real and consistent. And right now it’s not. It is inconsistent, at times incomparable, and many cases, not strong enough quality — thus the need for the SEC [rule],” she said. “The investors we’re working with feel like they’re flying blind on investment decisions in their portfolios.”

Anne Simpson, global head of sustainability for Franklin Templeton, which manages $1.5 trillion for investors, also supported the rule, saying it was responsive to the needs of investors. “Risk is a good thing. Risk is where we make the returns. But we have to be able to appraise risk,” she said.

She also said companies that excel in their reporting on sustainability typically have lower costs of capital and that the rule will relieve their “survey fatigue.”

“Typically, a big company will be receiving several hundred surveys a year, most of most of which focus on climate risk, among other issues,” she said. “Having these standardized reporting guidelines will actually make a huge difference for companies.”

Joe Amato, chief investment officer for Neuberger Berman, which manages $500 billion in investments, said investors often have to rely on third-party estimates based on sector or industry averages that “fail to consider important company-specific nuances. And this clearly makes for less efficient capital markets.”

Joe Allanson, Salesforce’s executive vice president for finance ESG (environmental, social and governance), said his company five years ago became one of the first to include ESG reporting in its 10-K filings.

“I still vividly recall the internal debates back then, of how much to report, what to say, what legal exposure we might be taking on. It was quite personal to me, since I was one of the signers of the 10-K,” he said. “But the current proposal helps to alleviate much of the anxiety that I had experienced years ago because I find the proposal quite thoughtful and responsive to preparer concerns.”

Concern over ‘Chilling Effect’

Cynthia Curtis, senior vice president of sustainability for real estate services company Jones Lang LaSalle, said her company also sees the need for increased disclosure and transparency, noting that buildings are responsible for almost 40% of the world’s greenhouse gas emissions.

“That said, we all are also a little … ‘anxious’ is too strong a word. But we just don’t want companies to be backing off of commitments. … If you haven’t made a Scope 3 commitment, will this make you hesitate to lean into establishing a Scope 3?

“You know, quantifying the impacts of climate change, of course, is very hard. And putting it in your SEC filing just raises the bar. … So I just think we do need to pump the brakes a little bit and ensure we get the language right for the level of disclosure and the phase-in of the safe harbor, so that it promotes more disclosure and doesn’t result in some of that chilling effect.”

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NYISO Business Issues Committee Briefs: April 11, 2022

Manual Updates for GFER Results

The NYISO Business Issues Committee on Monday approved revisions to the Transmission and Dispatch Operations Manual regarding updates required to share Generator Fuel and Emissions Reporting (GFER) survey results with all New York transmission operators (TOPs), effective April 29.

“These changes require that all TOPs [including NYISO] have access to the GFER fuel survey results in order to adequately evaluate energy constraints and develop seasonal operating plans,” said John Stevenson, gas and electric technical specialist.

The revisions are a result of NERC Project 2019-06, which, among other changes, updated standards to require TOPs to include in their data specifications provisions for reporting the cold weather information identified by generator operators in their cold weather plans. (See NERC Board OKs Cold Weather Standards.)

March LBMPs Drop with Milder Weather

NYISO locational-based marginal prices averaged $56.78/MWh in March, down from $94.06/MWh the previous month and nearly double the $28.59/MWh average in March 2021, Rana Mukerji, senior vice president for market structures, said in delivering the monthly operations report, attributing the monthly decrease to lower fuel prices and milder weather.

Day-ahead and real-time load-weighted LBMPs came in lower compared to February. Year-to-date monthly energy prices averaged $100.65/MWh, a 116% increase from $46.57/MWh a year ago.

March’s average sendout was 390 GWh/day, down from 429 GWh/day in February and higher than 381 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $4.47/MMBtu for the month, down from $6.17/MMBtu in February and up 99.6% year-over-year.

Distillate prices were up 105.2% year-over-year. Jet Kerosene Gulf Coast averaged $25.68/MMBtu, up from $19.79/MMBtu in February. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $27.02/MMBtu, up from $20.46/MMBtu in February.

March uplift increased to -9 cents/MWh from -$1.77/MWh the previous month, and total uplift costs, including the ISO’s cost of operations, came in higher than those in February.

The ISO’s local reliability share climbed to 27 cents/MWh in March from 4 cents/MWh the previous month, while the statewide share increased to -36 cents/MWh from -$1.77/MWh in February.

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ISO-NE Preparing to Move Forward on Day-ahead Ancillary Services

ISO-NE is ramping up its work on incorporating ancillary services in the day-ahead energy market.

In a recent memo and at the NEPOOL Markets Committee meeting Tuesday, officials from the RTO laid out the scope and timing of the project, which is a much anticipated addition to the market.

“Broadly, the day‐ahead ancillary services project seeks to procure and transparently price the ancillary service capabilities needed for a reliable, next‐day operating plan with an evolving generation fleet,” the memo says.

The proposal includes two components. One is an Energy Imbalance Reserve (EIR) feature that would incorporate load forecasting into the day-ahead market and procure energy to cover the gap when physical energy supply awards are below the forecast real‐time load.

The other is Flexible Response Services (FRS), which would procure 10- and 30-minute fast‐start and fast‐ramping capabilities in the day‐ahead market.

Longer-duration ancillary services, like the previously proposed Replacement Energy Reserves, will be deferred while ISO-NE focuses on the former two.

Much of the grid operator’s work to develop the new market features was completed as part of the Energy Security Improvements proposal that was ultimately rejected by FERC. (See FERC Rejects ESI Proposal from ISO-NE.) But ISO-NE is finishing up some calculations and technical work, as well as preparing to redo its impact analysis and market power evaluation for the new proposal.

The RTO is planning to work on the proposed new day-ahead services throughout this year and next, filing it with FERC by the end of 2023 with an implementation date either at the end of 2024 or beginning of 2025.

Still no Go for Proposed FA Changes

The MC again declined to recommend changes to the ISO-NE financial assurance policy that are being proposed by Competitive Power Ventures.

CPV’s Joel Gordon had brought forward more changes to his proposal to, among other things, address concerns with the amount of financial assurance that would be required for solar projects.

The proposal is designed to penalize companies that don’t meet development milestones, a timely topic after the fiasco surrounding Killingly Energy Center earlier this year. But like at the February MC meeting, it failed to get enough support from the committee to recommend advancing it to the Participants Committee.

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Washington Carbon Offset Program Aims to Preserve Forests

Washington is launching a first-of-its-kind program to auction off carbon offset credits to preserve the state’s forest land.

“We are creating a blueprint that can be used for public lands across the nation,” Washington Lands Commissioner Hilary Franz said Wednesday at press conference.

Franz oversees the state’s Department of Natural Resources (DNR), whose duties include managing the state’s trust lands with the mission of producing revenue from property for various programs such as education. The agency routinely auctions off trees on its lands to be harvested for timber.

The new DNR program will set aside 10,000 acres of forests — with trees that began growing prior to 1900 — that have the potential to be harvested. Offset buyers will bid on carbon credits to keep those carbon-absorbing forests intact. This enables the DNR to achieve its mission of producing revenue from its older forests without having to harvest them for timber, Csenka Favorini-Csorba, a senior policy adviser at DNR, said.

This effort comes after state lawmakers last year approved the nation’s second cap-and-trade program, after California. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)  Washington officials are still working on the details of that program, which is scheduled to go into effect on Jan. 1, 2023, and raise $500 million annually, with most of the money going to transportation projects.

The DNR project will start out as part of the nation’s voluntary offsets market. Once Washington’s cap-and-trade system is up and running, the offset credits could potentially be applied to offset emissions under the program. Participants in the Western Climate Initiative, which includes California’s cap-and-trade, will be able to buy the initial DNR carbon offset credits from the voluntary market. The agency expects the program to generate more than 900,000 carbon offset credits in its first 10 years.

“This is truly the next generation of carbon offsets,” said Caitlin Guthrie, director of forest carbon origination for Finite Carbon, a developer and supplier of forest carbon offsets. Finite Carbon is participating in the project to ensure it represents durable and verifiable carbon sequestration, she said.

“We hope this becomes a model for other states,” Favorini-Csorba told NetZero Insider.

The new program has identified 2,500 acres on DNR trust lands to be set aside this year in Whatcom, King, Thurston and Grays Harbor counties, stretching from northern to southern Puget Sound. Another 7,500 acres are scheduled to be identified next year.

Many details must still be worked out, including when the credits will be auctioned, what the minimum acceptable bids would be and the overall fundraising targets, Favorini-Csorba said. The state plans to auction off 917,000 carbon credits in the first 10 years of the program.

The DNR created a Carbon Sequestration Advisory Group in 2019 as a climate change measure. The agency has also leased some of its lands to wind farms, now capable of generating more than 200 MW of power.

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NERC, WECC Repeat Solar Performance Warnings

A series of disturbances involving solar resources last summer in California highlights the ongoing challenges of integrating new generation into the grid, according to a joint report by NERC and WECC released last week.

The report, “Multiple Solar PV Disturbances in CAISO,” concerns four bulk power system disturbances between June and August 2021 in Southern California that led to “widespread reductions of active power output” from solar resources. All of the events triggered the loss of at least 500 MW of generation, qualifying as a Category 1i event under NERC’s event analysis process; two also led to tripping at natural gas plants, and three caused tripping or reduction of distributed energy resources.

WECC employees have spoken about the events before: In a webinar earlier this year, WECC Reliability Initiatives Director Steve Ashbaker observed that the number of disturbances last year was the same as all those in the previous five years, indicating a significant increase in such issues. (See Texas RE, WECC Call For Coordination on DER Issues.) Other representatives from WECC warned that the accelerating pace of interconnection requests for solar projects points to a growing “reliance” on solar power in the West, making the incidents of last summer more likely.

Four Events in Three Months

NERC and WECC based the report on data from solar facilities that reduced active output by more than 10 MW during the events; the authors held follow-up discussions with plant owners and operators as needed.

In the first event, which began at 3:19 p.m. PT on June 24, a phase-to-phase fault occurred on a 500-kV line near Victorville, leading to a reduction of 765 MW across 27 solar facilities. The second, on July 4, also involved phase-to-phase faults on a 500-kV line, although this time the issue was caused by the Tumbleweed Fire and resulted in a 605-MW reduction of solar across 33 facilities. A combustion turbine at a combined cycle plant also tripped offline while loaded at 125 MW.

In the Windhub disturbance of July 28, a 500-kV line and a 500/230-kV transformer bank both tripped because of a single-line-to-ground fault that occurred while a circuit breaker that faulted was being returned to service after scheduled maintenance; as a result, CAISO recorded 511 MW of reduction across 27 solar facilities. Finally, a fire near the San Bernardino National Forest caused the Lytle Creek disturbance of Aug. 25, with 583 MW of reduction across 30 solar plants. Gas turbines at two nearby plants also tripped, carrying 303 MW of load in all.

Causes of solar PV reduction (NERC) Alt FI.jpgCauses of solar PV reduction in each disturbance. Clockwise from left: June 24, July 4, July 28 and Aug. 25. | NERC

According to the report, a “significant number of solar PV resources responded to the BPS disturbances in a manner that does not support BPS reliability.” In some cases solar facilities as far as 100 miles away from the fault locations were found to have responded abnormally.

Momentary cessation and slow active power recovery were the top two contributors to reduction and provided more than half of the drop in every case, though their shares varied widely: In the Aug. 25 event, momentary cessation accounted for almost three-fourths of the total reduction, while in the July 4 disturbance, it was only 21%. This made the July 4 event the only one in which slow active power recovery was the top cause of reductions, with 33%.

The report noted that the high degree of momentary cessation is “primarily driven from solar PV facilities with legacy inverters that cannot eliminate momentary cessation or modify settings.” Plant controllers may also have contributed to the problem, with the report suggesting their “interactions with the inverters appear to [have elongated] the expected dynamic response from these resources.”

Analysis was made more difficult by a lack of monitoring data from many plants, particularly the legacy facilities installed prior to the publication of NERC reliability guidelines related to the collection of data in BPS-connected inverter-based resources in 2019. This results in “a systemic gap in the capabilities of plant owners to analyze their facilities’ dynamic response to grid disturbances.”

Odessa Recommendations Repeated

In their recommendations, NERC and WECC emphasized that many of the issues highlighted in the report are not new: The Odessa Disturbance Report, published by NERC and Texas Reliability Entity last year, covered a widespread BPS disturbance in Texas involving a total reduction of output of more than 1,300 MW that involved solar, wind and natural gas facilities, and exposed some of the same problems. (See NERC-ERCOT Report Reviews Texas Solar Issues.)

The WECC report identified the root cause of all the issues identified in both reports as “a lack of performance requirements” in the FERC generator interconnection agreements. The report urged that FERC update the agreements to “help ensure there are no gaps in performance for newly interconnecting resources [with] clear requirements for accurate modeling and sufficiently detailed studies during time of interconnection.”

However, the report also called out NERC for shortcomings in its reliability standards that have led to “systemic issues with inverter-based resources.” To address these gaps, it said NERC’s Reliability and Security Technical Committee should help to set standards projects in motion that would result in:

  • a performance validation standard to ensure that reliability coordinators and balancing authorities can seek corrective actions for plants that do not perform up to the requirements of the interconnection agreement;
  • a ride-through standard to ensure solar and wind resources can endure disturbances without causing larger BPS issues;
  • analysis and reporting for abnormal inverter operations; and
  • inverter-specific performance requirements.