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November 17, 2024

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Massachusetts Legislators Call for Fossil Fuel Ban in Net-zero Building Code

Massachusetts legislators expressed disappointment Tuesday that fossil fuel use would be allowed under a net-zero building code straw proposal introduced by regulators.

The proposal “didn’t go far enough,” said Sen. Cynthia Creem (D), chair of the Massachusetts Senate Committee on Global Warming and Climate Change.

“The draft net-zero code would not represent a path for cities and towns to restrict the use of fossil fuels in new development,” she said during a committee hearing on the implementation of the state’s climate roadmap enacted last March.

A specialized net-zero code will be part of a three-tier system of building codes authorized by the law. Existing tiers include a base building code and a municipal opt-in stretch energy code. The state is updating the stretch code in consultation with the Board of Building Regulations and Standards, which is responsible for regular updates to the base code. In addition, the law calls for development of a municipal opt-in net-zero code as a third tier.

Tiers 2 and 3 — which apply to new building construction, additions and major retrofits — offer progressively more stringent compliance pathways for energy efficiency beyond the base code. The Department of Energy Resources (DOER) released a proposed update to the stretch code and the proposed specialized code last week for comment.

Compliance with the tiers will be based on the Home Energy Rating System (HERS) index, which scores efficiency between zero and 150, with 150 being the least efficient. Buildings complying with the base code must achieve a HERS rating of at least 55, while Tier 2 compliance ratings would be 42 for buildings that use fossil fuel heating and 45 for buildings with electric heating.

Net-zero code compliance would have the same Tier 2 ratings for buildings with fossil fuel and electric heating, but buildings that include fossil fuel heating must also have rooftop solar where feasible and be pre-wired for electrification.

About 85% of Massachusetts’ municipalities already opt in to the stretch code, and many are interested in upgrading to the net-zero code. A group of 30 town and city representatives sent a letter to the Executive Office of Energy and Environmental Affairs (EEA) last fall in support of a net-zero code that gives municipalities “clear authority to prohibit on-site combustion in new buildings and major rehabilitation.”

Without the option for communities to “actually experiment with going net zero,” the proposed code is a “reversal of legislative intent,” Sen. Michael Barrett, committee vice chair, said during the hearing.

“We wrote language that permitted communities to have a vigorous local debate … before opting in, but we imagined that once they made that decision, they would do so knowing that new construction without a backup fossil-fuel hookup was an option that they could pursue,” he said.

The purpose of the new code, as written, is to “encourage construction of all-electric buildings,” Kathleen Theoharides, secretary of the EEA, said in hearing testimony.

“Dictating certain fuels be used or certain things be banned is not innovation; it’s a requirement,” she said. “What we’re doing is creating a code that requires the most energy-efficient building envelopes possible, as well as additional things that … allow for experimentation.”

Creem would like to see the administration update the proposed code so that it is a “fossil-free option” for municipalities. But the proposal, Theoharides said, balances energy efficiency, cost and emission reductions, while seeking to ensure an orderly transition.

“The challenge with letting some people come off of gas … is that you leave customers on the gas system who are the least able to make the change and end up bearing the brunt of the cost for the remaining gas system as we transition away from it,” she said.

The DOER will accept comments on the straw proposal for the updated stretch code and new net-zero code through March 9, followed by public hearings over the summer. The final language for both codes is due in the fall.

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Biden Admin Launches Drive to Decarbonize US Industrial Sector

The White House on Tuesday continued its execution of the Infrastructure Investment and Jobs Act (IIJA) with a new group of requests for information (RFIs) and guidance documents, this time aimed at hard-to-decarbonize industrial products, including steel, aluminum and concrete.

The Department of Energy issued two RFIs, one on the IIJA’s $8 billion allocation to develop four clean hydrogen hubs across the country, and a second on the $1.5 billion in funding for research and development for clean hydrogen manufacturing and recycling.

The White House Council on Environmental Quality (CEQ) also issued draft guidelines for federal agencies on “responsible deployment” of carbon capture, utilization and sequestration (CCUS) projects. The IIJA provides $3.5 billion for CCUS demonstration and pilot projects and another $2.5 billion for low-interest loans for CO2 pipelines.

Other initiatives outlined in a White House fact sheet include:

  • the creation of a Buy Clean Task Force to “harness the federal government’s massive purchasing power to support low-carbon materials made in American factories”;
  • a new Technology Innovation Advisory Committee charged with “creating a comprehensive strategy to lower the carbon footprint of America’s industrial base”; and
  • trade policy being developed with the EU to keep “dirty steel” out of U.S. and European markets and limit steel dumping.

“The industrial sector is … central to tackling the climate crisis, as it is currently responsible for nearly a third of domestic greenhouse gas emissions,” the administration said. “By helping manufacturers use clean energy, efficiency upgrades and other innovative technologies to reduce emissions, the administration is supporting cleaner industry that can produce the next generation of products and materials for a net-zero economy.”

“With industries moving quickly to adopt and deploy carbon capture technologies, federal agencies can play a key role in ensuring that projects are done right and in a way that reflects the needs and inputs of local communities,” CEQ Chair Brenda Mallory said. The new guidelines are a first step toward CCUS “deployment in a manner that is environmentally sound and that cuts cumulative pollution in nearby communities.”

The hydrogen RFIs are part of DOE’s Hydrogen Shot, another initiative aimed at reducing the cost of clean hydrogen by 80% over the next decade, from the current price of about $5/kg to $1. According to the RFI on hydrogen hubs, “co-locating large-scale clean hydrogen production with multiple end uses can foster the development of low-cost hydrogen and the necessary supporting infrastructure to jumpstart the hydrogen economy in various market segments, create both near-term and long-term jobs and tax revenues for regional economies, and realize emissions-reduction benefits.”

The IIJA requires that the four hubs must each be located in different areas of the country; use different fuels, including natural gas, renewable energy and nuclear; and demonstrate applications in different industries: electricity, transportation, industry, and residential and commercial heating.

“Clean hydrogen is key to cleaning up American manufacturing and slashing emissions from carbon-intensive materials like steel and cement.” Energy Secretary Jennifer Granholm said in a statement. The goal is to help make “scaling up this clean, affordable energy source a reality for the United States.”

CEQ Guidelines

The guidelines for carbon capture and storage recognize the complex challenges that will be involved in permitting these projects. A demonstration project on federal land could trigger environmental assessments under the National Environmental Policy Act, Endangered Species Act and the Clean Air Act.

For example, to streamline permitting, the guidelines suggest that agencies develop “programmatic environmental reviews … where such analyses can facilitate more efficient and effective environmental reviews of multiple projects while maintaining community engagement.”

For building out a network of pipelines for CO2 transport and sequestration, the guidelines call for “close monitoring and enforcement of existing regulations and development of new tools to monitor and improve safety while also reducing the number of incidents that result in leakage of carbon dioxide.”

Jessie Stolark, policy and member relations manager for the Carbon Capture Coalition, said the clean industry initiatives reflect “broad, bipartisan support for the economywide deployment of carbon management technologies and further [underscore] President Biden’s commitment to utilizing carbon management as a critical tool to decarbonize heavy industry and manufacturing.”

“Federal investment in industrial decarbonization is key to American prosperity and to putting domestic industry firmly on the path toward deep emissions reductions, retaining and creating high-wage jobs, and continued technology leadership and economic competitiveness,” Stolark said.

On Thursday, DOE and the Department of Transportation announced the first round of state allocations for the $5 billion in the law to help states deploy electric vehicle chargers along main transportation corridors. (See States to Get $615 Million for EV Charging from IIJA Funds.)

DOE also released state guidelines for applying for the money, and the White House has issued a 465-page guidebook to help the states navigate all the IIJA funding opportunities.

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Survey Captures Driver Discontent with EV Charging Stations

Electric vehicle drivers in California say they’re having trouble using public charging stations, either because the station is not working, the driver isn’t a member of the charging network or there are other issues with payment.

Those are some of the findings of a new report from the California Air Resources Board (CARB). The report is a technical review of the agency’s Electric Vehicle Supply Equipment (EVSE) Standards, a regulation adopted in 2019.

CARB held a workshop on Tuesday to discuss the report’s findings.

The technical review included a survey of 1,290 California drivers to find out what barriers they face at public EV charging stations and what payment methods they have access to.

Among survey respondents, 575 drivers identified membership requirements as a barrier, including not having a charging network membership or not wanting to create one.

Charging station operability issues were a barrier for 439 respondents, while 209 drivers said payment was a problem.

Respondents listed several other barriers: 224 drivers said the stations were too expensive; 164 said they’re too complicated; 121 said they’re too hard to find.

And one workshop participant pointed to additional charging station issues. Charging hoses don’t reach the car or won’t release when the charge is completed, the participant said. The screens are impossible to read when the sun hits them.

“The list goes on,” the participant said in comments read by the workshop moderator. “If the station does not deliver the charge, it is useless to the driver, no matter the reason.”

Stephanie Palmer, an air resources engineer at CARB, said the agency is aware of the problems. Some of the issues are outside the scope of the technical review, she said, but will be researched by CARB and the California Energy Commission as part of other programs.

EVSPs Surveyed

Electric vehicle service providers (EVSPs) and credit card companies were also surveyed as part of CARB’s technical review.

The network providers rely mainly on contactless “tap” technology for charging station payment, according to the report. The use of tap-enabled cards is growing in the U.S., but the cards currently account for only a small percentage of cards in use, the report said. In contrast, EMV chip payment cards are widely used.

None of the EVSPs surveyed accept cash at their charging stations.

Several of the EVSPs that participated in the survey said their national uptime ranges from 95% to 98%. The report noted a possible contradiction between the responses of EVSPs and drivers who encountered charging station operability issues.

“The data from the two surveys suggest there may be a disconnect between what drivers are experiencing and what the EVSPs are reporting, and more work is needed to understand this issue,” CARB said in its report.

One workshop participant said that CARB needs to define “uptime,” which station operators may define as times when there is power to the station.

“This does not mean the station works and is able to provide the asked-for energy,” the participant said in a comment read by the moderator. “There are so many ways it can fail.”

Palmer said CARB plans to explore the issue further.

Payment Requirements

CARB adopted the EVSE Standards regulation in 2019 to fulfill a mandate of Senate Bill 454 of 2013.

The standards are intended to reduce barriers to accessing public charging stations.

“Everyone should be able to use electric vehicle charging stations in a secure and reliable way,” CARB said in explaining the background of the regulation.

The regulation applies to all EVSPs operating publicly accessible Level 2 or DC fast chargers in the state. It doesn’t cover private EV charging, including charging networks run by Tesla (NASDAQ:TSLA) or Rivian.

Requirements regarding payment methods took effect recently or have not yet taken effect.

Under the regulation, DC fast chargers installed on or after Jan. 1 of this year must accept EMV chip-enabled cards and mobile payments. Those requirements will also apply to Level 2 chargers installed on or after July 1, 2023.

All EV charging stations, whether existing or newly installed, must meet the payment requirements by July 1, 2033.

The regulation also includes a requirement for EV charging stations to allow payment by members of an EVSP network as well as by non-members.

Under the regulation, EVSPs must post all fees associated with a charging session. And a sticker at each charging station must state the voltage and amperage capabilities of the unit.

Next Steps

CARB will accept public comments on the technical review through 5 p.m. on Feb. 28.

CARB staff plans to present the report to the agency’s board in April. Staff’s recommendation is to monitor compliance with the EVSE standards regulation without any changes to the regulation at this time.

But the CARB board could decide the regulation needs updating and launch a rulemaking process.

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Former Commissioners Preview Year Ahead for FERC

FERC has undertaken an ambitious agenda for this year that will face numerous headwinds from administrative challenges, not least of which remains the ongoing COVID-19 pandemic.

A panel of former FERC commissioners provided their insight into those challenges during a webinar hosted by the Energy Bar Association’s Northeast Chapter and moderated by RTO Insider co-publisher Rich Heidorn Jr.

At the top of FERC’s agenda is its Advanced Notice of Proposed Rulemaking on transmission planning and cost allocation. Chair Richard Glick said last week that he hopes to have a final rule out of the proceeding by the end of the year, but former Chair Joseph T. Kelliher, now an arbitrator with dispute resolution firm FedArb, was doubtful that could be achieved because of the scope of the docket. (See related story, Glick Aiming for Final Transmission Rule by End of Year.)

But former Commissioner Nora Mead Brownell, co-founder of consulting firm ESPY Energy Solutions, said that “given the current set of circumstances that we face … it’s time to be bold. … We are not really getting the environmental, economic or equity outcomes that meet the threshold that we’ve learned to expect. We have a transmission grid that is old; that is vulnerable; that is not achieving what we need to do to deliver a grid for the future.”

Among the practical challenges to reaching any final rule is a staffing shortage, she said. “There’s been an enormous amount of staff turnover; there’s lots of open positions. I think we all need to be arguing for increasing hiring. We need to be supporting the efforts to recruit people. And we need to give them the tools that they need in order to do the job.”

Another challenge remains the COVID-19 pandemic, which has kept commissioners and their staffs working remotely. Former Chair Neil Chatterjee, now senior adviser at Hogan Lovells, noted that Commissioner James Danly was confirmed by the Senate in early March 2020, just before Chatterjee transitioned the commission to telework as the pandemic began. Thus, Chatterjee had never held an open meeting in-person with Danly as a commissioner, nor did he with current commissioners Allison Clements and Mark Christie.

This week’s open meeting will mark two years since the commission last held an in-person open meeting. Chatterjee said that makes it difficult for commissioners and their staffs to get to know each other personally and, therefore, work toward consensus on controversial dockets. Glick had intended to resume limited in-person meetings, with only staff and members of the press in attendance, last year, but the surge in COVID cases from the Omicron variant of the virus delayed that plan.

On Wednesday, after his keynote speech at the National Association of State Energy Officials’ annual Energy Policy Outlook Conference, Glick told RTO Insider that, though he would like to resume in-person meetings “as soon as possible,” the case rate in D.C. is still too high.

According to the Centers for Disease Control and Prevention, D.C.’s case rate per 100,000 residents as of Monday was 180.94; any rate above 100 is considered “high.” The district has reported an average of 182.4 cases a day over the past week.

“We’re all sort of adept at virtual communication these days, but so much is lost in that process,” Chatterjee said. “And when you’re trying to negotiate something as complex as reforming transmission policy, it’s hard to do it virtually.”

Finally, since the beginning of the Trump era of U.S. politics, the commission has seen a partisan divide in its decisions and debates that has alarmed many observers.

Chatterjee said that working virtually does not help heal that divide. Kelliher agreed, saying that filings constitute 85% of the commission’s workload, leaving the remainder of time for discretionary work, such as initiatives. But the commission has become less efficient processing filings, leaving less time to work on big issues, he said.

“When I was chairman, we’d meet every week, one on one, no staff, and we would talk about big things that are what I thought the commission had to act on in the next three months,” Kelliher said. “We wouldn’t do something big unless we knew, ‘What’s the center of gravity? And is this a productive exercise?’ And then once we knew, then the order would be written up, versus writing up an order, flinging it down the hallway virtually, and then seeing what the reaction is. It’s just much more efficient.”

Brownell said that partisanship may be the new normal, as “it’s a reflection of what’s happening in the larger world.”

Regarding the transmission ANOPR, she said, “I think it would be great if they could get to unanimity, but when you have people who may believe it’s their job just to disagree, maybe that’s just not possible in today’s world.”

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States Outline Energy Challenges, Infrastructure Opportunities

WASHINGTON — Louisiana’s Jason Lanclos is both excited and anxious over the funding opportunities in the long-awaited Infrastructure Investment and Jobs Act (IIJA).

“When you start looking at the sheer amount of data and programs and funding that’s in [the bill], it’s extremely intimidating,” said Lanclos, director of the Technology Assessment Division in the state’s Department of Natural Resources. “But I think that there are also a tremendous amount of opportunities.”

For that reason, Lanclos said, he is grateful for his ability to compare experiences with other state energy officials, as he did during a panel discussion at the National Association of State Energy Officials’ (NASEO) Energy Policy Outlook conference Friday.   “I think that that’s where you kind of have validated that, ‘Hey look, I’m not in this alone. There are other states who are facing the same things and having similar challenges.’”

Lynn Retz, director of the Energy Division at the Kansas Corporation Commission, echoed Lanclos. “Don’t ever hesitate to tap into your neighbors, your co-workers or colleagues here, because I’m not [ashamed] to call someone, send an email, beg, borrow steal their stuff,” she said. “Adapt it to what works — it’s called being resourceful.”

The discussion, which Lanclos moderated, identified states’ commonalities while also highlighting unique challenges faced by some, such as remote Alaskan communities and the islands of Hawaii.

Hawaii: Six Independent Grids

Scott Glenn, chief energy officer for the Hawaii State Energy Office, noted that his state has six standalone grids. “Each island has only the electricity produced on that island for its use and reliance. We don’t have any cables connecting the islands or cables or anything,” he said.

“We’re kind of looking at this money as an opportunity to really change things,” he said. With about 60% of the state’s homes equipped with rooftop solar, the state was well on its way to building out its distributed generation before the infrastructure funding.

Glenn would like to use some of the state’s funding to decarbonize the six- and nine-seat planes that residents use to get from one island to another.

“The main part of their costs for flying between the islands is the takeoff and landing — it’s the jet fuel for that 20-minute flight,” he said. “And so, if we can electrify that, we can lower that cost dramatically.”

One challenge: Hawaii’s smallest islands total only 7 MW of capacity. “They’re not going to be able to charge a plane,” he said.

Glenn cited the importance of stakeholder collaboration. “We’re islands. We try to say, ‘You can’t throw people out of the canoe.’”

He said his office will seek to dissuade multiple parties from proposing competing ideas for the same funding source, “so that we can leverage our limited opportunities to apply for things, and then also better coordinate local match availabilities.”

On the positive side, the state has only have four counties, making coordination more manageable. “We can get all four mayors together in the room [and ask] ‘What are you guys doing?’ So it’s digestible.”

Alaska: Feeling Excluded

Alaska found itself at the bottom half of the electric vehicle funding allocations announced by the U.S. Department of Transportation and Department of Energy Thursday. Its $7.8 million ranked 30th among the states, Puerto Rico and D.C. (See States to Get $615 Million for EV Charging from IIJA Funds.)

“It’s nice to have electric charging for vehicles every 50 miles [as envisioned in the Federal Highway Administration’s  guidelines for the EV infrastructure program],” said Curtis Thayer, executive director of the Alaska Energy Authority. “But if you don’t have any power for 100 miles, you’ve got a problem. And there’s no way of getting three-phase power in there when the transmission line is at least 20, 30 miles away.”

Some 200 rural villages were excluded from funding “because there was complete exclusion for any of the rural villages … that are not part of the National Highway System,” he said.

The state also is finding it difficult to obtain federal funding to shift from fossil fuels. “For us to introduce more renewables, we’re going to have to upgrade the transmission lines that we have. We have currently 138 [kV] serving a lot of Alaska; we want to upgrade to 230 [kV]. … But we’re a little too small for the 500 kV.

“We are too small for some of the funding available or too big for other money,” he said.

Kansas: Messaging is Key

Kansas’ Retz was thrilled to announce to her colleagues that her energy office within the state Corporation Commission recently doubled in size.

“Most of you know I have been an office of one. Well, they just allowed me to hire one more person. So now I’m an office of two,” she said, prompting applause and laughter from the crowd at the Fairmont hotel in Georgetown.

Retz said she will be focusing on reaching rural communities with programs such as small business energy audits and a program to benchmark the energy efficiency of K-12 school buildings.

She’s also working to help add EV charging to Department of Wildlife and Parks’ facilities whose infrastructure has been neglected.

Because her office is within the KCC, Retz said she is not permitted to “establish policy” but can “help facilitate” policy discussions. “So it is bringing all of these state stakeholders to the table and knowing who to recognize and make those introductions. Because what I’ve also found is I have people at Wildlife and Parks who wanted to talk about the infrastructure at the facilities that hadn’t reached out to our Department of Transportation. So part of my role is literally with those stakeholders figuring out who should be at the table to have those conversations and facilitating those conversations. And then making those introductions that cross other state lines as well.

“You didn’t really want to talk about [EV charging] prior to this, just simply because of the political climate,” she said. “I have to be careful about the terminology that I use and how I message the programs that I’m going to move forward.”

Using the federal funds and being able to do so quickly, is “going to be critical,” she added. “If I get some of it launched off early, others will have no clue what I’m doing, and I’m going to be too far down the road to do anything about it,” she said.

Michigan: Flexibility Essential

Robert Jackson, director of the energy office in the Michigan Department of Environment, Great Lakes, and Energy, said state officials are focused on meeting Gov. Gretchen Whitmer’s 2050 carbon neutrality goals while also making their programs as flexible as possible in case of a change in administration or program priorities.

The state is creating workgroups to help guide efforts to win Energy Efficiency and Conservation Block Grants. Michigan still has energy efficiency programs from the American Recovery and Reinvestment Act (ARRA), but that funding, he said, was “prescriptive.”

The state initially targeted its EE and renewable energy program toward small businesses, in response to the decline of the auto industry in the state. “We needed to provide these businesses with funding in order to change their focus … and to retool them to become more efficient,” he said. “But that money can only be used for that purpose now.”

Lanclos agreed with Jackson’s recommendation for flexibility. He recalled an economic development roundtable he did in Louisiana with the Committee of 100 for Economic Development. “A lot of the conversation was on depoliticizing climate — in other words, trying to bring in plans that can survive [changes in] administrations.”

The state is considering whether hydrogen or carbon capture, utilization and storage (CCUS) can help decarbonize its industrial sector.

“With us, our biggest challenge is with industry,” he added. “We have these high-intensity, high end-use industries that use a lot of power. And so working with them and trying to make sure that folks like that are at the table when you’re crafting these plans, is really, really important.”

South Carolina: Office of Resilience Looks beyond Flooding

Lanclos said the IIJA has forced state energy officials to work with agencies and organizations that “are a little bit out of our comfort zone, or that we don’t work with every day.” He cited opportunities to increase his office’s engagement with the Louisiana Public Service Commission on efforts considering offshore wind and hydrogen.

South Carolina also is seeing greater interagency collaboration, said Sara Bazemore, director of the state energy office within the South Carolina Public Service Commission’s Office of Regulatory Staff.

The state recently created an Office of Resilience in response to legislation that focused on threats from flooding.

“It was a great effort with different agencies coming together and going, ‘Oh, we’ve already done a report on that. How about I summarize that?” she said. Although flooding was the initial legislative mandate the office is now taking a broader view to consider the resilience of critical energy facilities, said Bazemore.

Pennsylvania: Looking to ‘Scale Out’

David Althoff Jr., director of the energy programs office in the Pennsylvania Department of Environmental Protection, said ARRA allowed the state to begin to “scale up” its renewables with funding for projects such as a 3-kW solar array at the Philadelphia Zoo. “Now we have like 15 GW of solar in the PJM queue. That’s scaling up. But scaling out, you know, is probably harder: How are we going to get this out to communities? Because that’s really where it needs to go, in my view.”

In Pennsylvania, that means 67 counties and 2,700 municipalities — and the need for an “army” of clean energy workers, Althoff said.

“This is a lot of money. You’re not going to be able to do it yourself,” he said. “… That $62.5 billion, that’s not all coming to state energy offices. Some of that’s going to our [departments of transportation]. Some of that’s going to community and economic development. Ultimately, I think we’re gap fillers … sort of like, you know, like batteries and bacon — it makes it all better.”

“To some degree we’re on a ‘hearts and minds’ tour,” he continued. “The point is, is that where the battle will be won on clean energy? That is how people connect with it, you know — at their home, in their communities at their school.”

Connecticut: ‘Well Positioned’

Vicki Hackett, deputy commissioner of energy in the Connecticut Department of Energy and Environmental Protection, said her state is “really well-positioned” to take advantage of the IIJA.

“We’ve done a fair amount of planning and policy development,” she said. “And the needs that we’ve identified and begun to address are very much aligned with the act, so we have existing programs and some that are in late stages of development that we can leverage.”

She noted that the state Public Utilities Regulatory Authority has opened several grid modernization dockets and said the state’s modeling indicates that energy storage “will play an increasingly significant role in ensuring the reliability of the grid and minimizing wasted generation as we continue to employ offshore wind in New England.

“The existing transmission system needs to be upgraded and expanded to meet the regional energy capacity additions that are needed to achieve our goals and other states’ goals,” she said. “We’ve also identified retention of our nuclear facilities as a critical factor in reaching our decarbonization goals while maintaining reliability as load balancing technologies evolve.”

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PJM Operating Committee Briefs: Feb. 10, 2022

Illinois CEJA Reliability Guidance Update

PJM last week provided the Operating Committee an update on the Illinois Climate and Equitable Jobs Act (CEJA) and its impact on the RTO.

Chris Pilong, director of PJM’s operations planning department, presented a draft reliability guidance document that the RTO will send to Illinois regarding the new clean energy legislation. Signed into law on Sept. 15 by Gov. J.B. Pritzker, the legislation requires all investor-owned baseload coal-fired power plants and remaining oil peaker turbines to shut down by 2030. (See Illinois Senate Passes Landmark Energy Transition Act.)

Gas turbine plants, including ones currently under construction, must also close by 2045 under the terms of the bill, although the state has the option to retain plants that are critically needed.

Pilong said PJM has been working with the Illinois Environmental Protection Agency and the governor’s office to develop a guidance document to clarify the legislation for generation owners and other impacted stakeholders. The law’s broad scope and impact creates a need for generation owners and state entities to discuss and resolve issues, he said.

“This guidance document is very much written from the PJM and member stakeholder perspective,” Pilong said.

PJM received feedback from stakeholders on the RTO’s procedures for excepted generators in Illinois. In a section of the document on scheduling large greenhouse gas-emitting units for reliability, PJM is proposing language that says a unit will need to bid into the day-ahead and real-time markets as “unavailable” if it does not have any remaining run hours left as a result of the CEJA legislation.

Pilong said a unit will also need to enter an “unplanned” outage ticket with a cause code of “emissions – CEJA” in the PJM eDART system. He said a unit entered with this outage type and cause code will not be expected to enter Generating Availability Data System outages and will not have an equivalent forced outage rate demand impact calculated.

“What we found is the legislation creates a new scenario for us,” Pilong said. “We’ve never had a unit that’s available for a reliability need but not available for potential economic scheduling.”

Marji Philips, LS Power vice president of wholesale market policy, praised the work being done by PJM staff to draft the guidance document. Philips said one of her company’s biggest concerns is to have the Illinois government put in writing that generators will not be penalized for running as reliability resources and be protected from private lawsuits for exceeding emissions limits.

“We don’t want to get into litigation,” Philips said.

Philips also encouraged PJM to complete impact studies from the legislation as soon as possible. She said other states are currently looking at similar legislation, and there are “significant reliability concerns” with the deactivation of generators.

“It would be helpful to give some guidance to other states that are looking at similar legislation and some of the issues they can expect to possibly occur,” Philips said.

TO/TOP Matrix Review Approved

Stakeholders unanimously voted to recommend that the Transmission Owners Agreement – Administrative Committee (TOA-AC) approve the latest version of the Transmission Owner/Transmission Operator (TO/TOP) Matrix.

Gizella Mali, chair of the PJM TO/TOP Matrix Subcommittee (TTMS), reviewed version 16 of the TO/TOP Matrix. Mali said the subcommittee has been working on changes since June and finalized the matrix in November.

TO TOP Matrix Update Process (PJM) Content.jpgPJM’s process for updating the TO/TOP matrix. | PJM

The TO/TOP Matrix is an index between the PJM manuals and governing documents and NERC reliability standards applicable to the RTO as the TOP. The matrix delineates the assigned and shared tasks for member TOs where PJM relies on its TOs to perform certain tasks.

Changes in version 16 of the matrix included several revised tasks with updated language and administrative changes to update reference documents, spelling and grammar and align abbreviations. Mali said there were no changes with new NERC reliability standards or other standards in the existing matrix.

Members also unanimously recommended approval of the matrix in a vote at last week’s Planning Committee meeting. The matrix will now go to the TOA-AC for final approval at the March meeting.

Manual 40 Endorsed

Members unanimously endorsed a minor change to Manual 40 as part of the periodic review.

Benjamin Miller, PJM’s senior training technology coordinator, reviewed the change to Manual 40: Training and Certification Requirements. Miller said Maureen Curley was added as manager of PJM’s state and member training department. Curley replaced Michael Sitarchyk who retired as manager earlier this year.

The manual change will now go to the Feb. 24 Markets and Reliability Committee meeting for final endorsement.

Manual First Reads

Several manual changes resulting from the periodic review were presented for first reads by Donnie Bielak, manager of reliability engineering for PJM. The manuals were:

Stakeholders will vote on the changes at the March OC meeting.

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PJM Planning Committee Endorses ‘Fast Lane’ Criteria for Gen Projects

Stakeholders strongly endorsed PJM’s plan for transitioning into a new interconnection process at last week’s Planning Committee meeting.

The proposal, developed in the Interconnection Process Reform Task Force, received 218 votes in support (91%), with 22 members voting against it. It now goes to the Markets and Reliability Committee meeting for endorsement.

Jack Thomas of PJM’s Knowledge Management Center said the proposal would establish an expedited interconnection process with “fast lane criteria” for projects with any cost allocations for transmission upgrades of $5 million or less, amounting to about 450 impacted projects with a completion date of 18 months. The $5 million cutoff covers the bulk of substation and terminal equipment upgrades and, as a result, shorten durations for facilities to study the work needed to be done.

While PJM processes these projects, along with the remaining projects that have been “re-queued,” no new project applications would be accepted for two years.

Ken Seiler, PJM’s vice president of system planning, thanked stakeholders and PJM staff for the work done in the effort, calling it a “long journey.” Seiler said members were able to come together and find “collective solutions” to improve the interconnection process.

“We’ve worked very hard to hear everybody’s concerns and examine any number of ways to improve the process,” Seiler said. “And I think this is really going to help us long-term to prepare us for the grid of the future.”

He also said PJM recognizes that the proposal doesn’t satisfy all stakeholders, but it will help the RTO better interconnect generation resources in the queue. He called it PJM’s “best faith proposal” to deal with the growing backlog in the queue.

There is currently more than 220 GW of capacity in the queue, Seiler said, 95% of which are made up of renewable resources.

At the same time that the interconnection queue continues to grow, Seiler said PJM is facing staffing concerns to be able to handle the interconnection requests. The RTO has continued to hire staff over the last two years and plans to add more through 2023.

PJM staff have also taken a “hard look” at its capital budget for tools and automation efforts to increase efficiencies, Seiler said, increasing money set aside.

“I think we are going to find a better, faster, more efficient way to get these new projects integrated into the system and enable our states to meet their renewable portfolio goals,” Seiler said.

Seiler said he wanted to emphasize that PJM is “not closing the door” on new projects entering the interconnection queue and that the RTO has heard stakeholder concerns that the queue will be closed with the transition proposal.

“We’re prioritizing more than 1,200 projects that we have in our backlog; most of them are renewables, and they represent well over 100,000 MW of nameplate capacity,” Seiler said. “That’s half the capacity we have in our system today, and we’re focused on moving these through the system and streamlining the process as much as possible, and getting real projects interconnected to the queue.”

Stakeholders originally endorsed an issue charge for work to be completed on the interconnection issue at the April PC meeting, with task force meetings starting later that month. (See “Interconnection Process Reform Endorsed,” PJM PC/TEAC Briefs: April 6, 2021.) Thomas said that while PJM and stakeholders were working through the issues in the task force, they realized a transition process also needed to be discussed.

The proposal would also preserve the ability for backlogged projects that would have received an interconnection service agreement under the existing process if not for delays to remain in the queue, Thomas said, and it would also reduce the time that the queue is closed for the transition.

If the proposal is endorsed by the MRC and MC in April, PJM expects to file the necessary changes with FERC by May. Based on the current work plan, the effective date of the transition would be the last quarter of 2022 or the first quarter of 2023.

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PJM PC/TEAC Briefs: Feb. 8, 2022

Planning Committee

Generator Deliverability Update

PJM is preparing to present stakeholders with study results that seek to explain any potential upgrade requirements stemming from the RTO’s generator deliverability proposal.

Kern-Jonathan-2018-03-08-RTO-Insider-FI-1.jpgJonathan Kern, PJM | © RTO Insider LLC

Jonathan Kern of PJM’s transmission planning department provided an update on the timeline for the development of a proposal to change the generator deliverability test at last week’s Planning Committee meeting.

Kern said PJM agreed to conduct two sets of studies on potential upgrade requirements. The first is on the baseline in the 2026 Regional Transmission Expansion Plan summer, winter and light-load assumptions; the second is on a hypothetical interconnection queue scenario using commercial probabilities to get an idea of the long-term implications of new rules.

PJM is performing some sensitivity analyses on the studies to distinguish between upgrades driven by higher wind and solar deliverability levels versus the other changes being proposed for the test. Besides the generator deliverability changes, Kern said, PJM has also discussed conducting several new tests that include a high wind and solar zonal test, an individual plant deliverability test and an extreme interchange variation test.

PJM’s work to provide transmission results and complete the studies is “customized,” Kern said, with staff developing power flow models and completing an “extensive” revision to the in-house generator deliverability code.

The RTO originally planned to provide a first read of the proposed generator deliverability changes at the February PC meeting, Kern said, but the work being done internally resulted in delays in the completion of the generator deliverability testing.

Kern said it will present additional information at a special PC session on capacity interconnection rights (CIR) for effective load-carrying capability (ELCC) resources on Feb. 15, including an educational workshop on the proposed generator deliverability changes.

PJM will hold a final special PC session on CIRs for ELCC resources on Feb. 23, Kern said, with the RTO targeting the meeting to provide stakeholders with a summary of the generator deliverability results and a discussion of the final proposals. Kern said PJM is expecting to complete the generator deliverability tests by the middle of the month.

Kern said PJM will conduct a first read of the generator deliverability proposal at the March 8 PC meeting.

Deactivation Process Timing

David Egan, manager of PJM’s system planning modeling and support department, reviewed the proposed generator deactivation process timing update, presenting a problem statement, issue charge and revisions to Manual 14D and the tariff.

Egan said the current tariff language providing 30 days to complete deactivation studies is acceptable when only a single deactivation notice is made in a period. But when multiple deactivation requests are received, the 30-day window is “insufficient” to determine any adverse impacts on reliability and can be “very challenging” to complete.

“We’re narrowly focused on targeting the current tariff timing for deactivations,” Egan said.

The current industry trends and state energy policies will increase the volume of deactivation notices in the future, Egan said, putting more pressure on PJM staff to complete deactivation studies. He said the short window puts “undue burden” on PJM’s planning and operations staff, along with the staff of transmission owners making deactivation requests, to make reliability evaluations and mitigation determinations.

Generation deactivations 2018-2021 (PJM) Content.jpgGeneration deactivations in PJM from 2018-2021 | PJM

 

PJM is an “outlier” in its deactivation process when compared to other RTOs and ISOs, Kern said, with a current advance notice of 90 days and 30 days to conduct a study.

MISO requires advanced notice of 26 weeks for a deactivation, and the studies include 75 days to identify issues and 26 weeks to complete the deactivation study. NYISO has an advanced notice of 365 days for deactivation, and studies are conducted in the subsequent quarter.

PJM’s proposed issue charge calls for tariff and manual changes that “provide more time to complete analyses, allow additional and improved studies and provide the ability for more efficient work control and consistency regarding timing of deactivation studies,” Egan said.

The proposed deactivation process includes quarterly study times for requests, with study periods beginning Jan. 1, April 1, July 1 and Oct. 1. PJM staff will study deactivations as a batch; the Jan. 1 study period would result in a reliability notifications at the end of February, for example.

To request a deactivation, a generation owner must submit a notice:

  • between Jan. 1 and March 31 to deactivate July 1 or later;
  • between April 1 and June 30 to deactivate Oct. 1 or later;
  • between July 1 and Sept. 30 to deactivate Jan. 1 of the subsequent year or later; or
  • between Oct. 1 and Dec. 31 to deactivate April 1 of the subsequent year or later.

Egan said the quarterly schedule will allow sufficient time for additional required seasonal, interim year and short-circuit analyses, scheduling upgrades and cost estimates. He said the new schedule would also allow PJM operations to identify additional needed operational measures.

PJM will seek endorsement of the issue charge at the March PC meeting.

Transmission Expansion Advisory Committee

NJ Offshore Wind

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Aaron Berner, PJM

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Aaron Berner, PJM manager of transmission planning, provided an update on the New Jersey offshore wind “state agreement approach” (SAA) proposal window at last week’s Transmission Expansion Advisory Committee meeting.

PJM and the New Jersey Board of Public Utilities asked FERC last month to approve the SAA plan to build the transmission necessary to deliver the state’s planned 7,500 MW of offshore wind. (See PJM, NJ Seek FERC OK for OSW Tx Process.)

Berner said PJM staff is currently conducting system reliability tests to determine how the different proposals may impact grid performance. The RTO has also performed internal reviews on the necessary construction of transmission, Berner said, while engaging with external consultants to look at the “viability” of the construction and potential cost and permitting issues.

“This is a much more complex set of projects than we have looked at in the past,” Berner said.

PJM is working with the New Jersey Department of Environmental Protection to “better understand” some of the environmental issues that need to be considered when building the new transmission, he said.

The RTO has completed a “good amount” of summer, light-load and winter deliverability testing associated with several proposals, Berner said, and has seen “small magnitude” violations with some of the proposals.

Berner said PJM has reviewed proposals for the options of upgrades on existing onshore transmission connection facilities and new facilities. In consultation with NJBPU, PJM identified an initial set of 6,400 MW of combinations to evaluate for offshore wind generation solicitations 2 through 5.

The NJBPU conducted its second offshore wind solicitation last June with a combined capacity of 2,658 MW. (See NJ Awards Two Offshore Wind Projects.) The fifth and final solicitation window is scheduled for the first quarter of 2027.

Berner said PJM is working with a consultant to analyze the cost of the proposals over the entire service life of the projects under different scenarios, including project cost increases and schedule delays. He said the RTO will also evaluate the cost containment provisions for the proposals.

Sharon Segner, vice president of LS Power, asked when the analytical and evaluation work being done by PJM staff and the consultant will be presented to stakeholders.

Berner said some of the work should be completed and presented at the TEAC by March, and more is expected within three months. He said it’s difficult to issue the analysis in a piecemeal fashion because of the complexity of the work to be completed.

“We need to come to a point where we have a more holistic view of some of the projects, which means rounding out more of the analysis,” Berner said.

Generation Deactivation

Phil Yum of PJM provided an update on recent generation deactivation notifications.

Generation deactivations requests (PJM) Content.jpgPJM generation deactivation requests from June-August 2021 | PJM

 

Yum highlighted the deactivation notifications of New Jersey’s last two remaining coal plants: the 219-MW Logan Generating Plant and the 240-MW Chambers Cogeneration, both owned by Starwood Energy and located in the Atlantic City Electric transmission zone. Starwood requested a deactivation date of April 1. PJM completed a reliability analysis of both plants and no reliability violations were identified.

The 9.3-MW Orchard Hills Landfill in the ComEd transmission zone in Illinois requested a deactivation date of March 31. Yum said a reliability analysis was completed and no reliability violations were identified.

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FERC Clarifies Order on PJM Reserve Market Changes

FERC on Friday clarified that its Dec. 22 order on remand partially reversing a May 2020 decision on PJM’s proposed energy price formation revisions did not remove the RTO’s reserve price caps (EL19-58).

On remand from the D.C. Circuit Court of Appeals in December, the commission 3-1 reaffirmed its previous decision directing PJM to consolidate its tier 1 and tier 2 reserve products, but it said it had erred in its approval of changes to the shape of the RTO’s operating reserve demand curve (ORDC), requiring tariff and Operating Agreement revisions within 60 days. (See FERC Reverses Itself on PJM Reserve Market Changes.)

PJM uses an ORDC and transmission constraint penalty factors to establish LMPs. Under its current rules, the maximum price the energy component of an LMP can reach is $3,750/MWh. But the “downward sloping” ORDC, approved by FERC in May 2020, allowed the RTO’s LMPs to reach or exceed $12,050/MWh in cases of extreme reserve shortages.

PJM Request

PJM requested FERC action by Feb. 11 so that it could reflect the commission’s clarification regarding how it should address the reserve price caps in its scheduled Feb. 22 compliance filing. It specifically requested clarification as to whether the remand order retained the May 2020 order’s acceptance of the removal of price caps in the reserve markets, or that it should maintain the price caps.

The RTO said in its filing that it would include tariff provisions removing the reserve price caps if the commission didn’t make a clarification. It said it would include capping provisions in its compliance filing that are “consistent with its existing reserve capping provisions but reflect the addition of a new 30-minute reserve requirement.”

It also said that its footprint will have five reserve requirements with the proposed reserve market changes. Without the price capping provisions, PJM said, the maximum energy component of the LMP could reach approximately $6,250/MWh, a price equal to the sum of the $2,000/MWh energy offer cap and five $850/MWh reserve penalty factors.

“PJM states that the removal or continuation of the price capping provisions has implications on the reserve market clearing prices and energy prices,” the commission said in its order last week. “PJM explains that when a reserve zone or sub-zone is short on reserves, the reserve and energy market clearing prices will reflect the need for additional reserves, where the maximum willingness to pay to meet any reserve requirement in any location, independent of the other reserve requirements, is the reserve penalty factor.”

The commission said that while its December remand order didn’t “explicitly address” the current reserve price caps, it directed the RTO to maintain its currently effective reserve penalty factors. FERC said PJM didn’t specifically allege that the reserve price caps are unjust and unreasonable, but rather “proposed only to remove the reserve price caps as part of PJM’s replacement rate.”

“While the May 2020 order accepted PJM’s proposed replacement reserve penalty factors and PJM’s proposal to remove the price caps by extension, it did not find the reserve price caps unjust and unreasonable under the currently effective ORDCs and reserve penalty factors,” FERC said. “Because the remand order reversed the determinations regarding the ORDCs and reserve penalty factors, the underlying predicate for removing the price caps no longer exists. Moreover, PJM did not present any evidence that the reserve price caps are unjust and unreasonable under its currently effective ORDC and reserve penalty factors. Accordingly, we clarify that the remand order did not remove the reserve price caps.”

Stakeholder Input

In response to PJM’s request for clarification, the PJM Load Coalition and the Independent Market Monitor both argued that FERC’s December remand order directed the RTO to maintain the current reserve price caps.

The coalition requested that the commission confirm that PJM must submit a compliance filing maintaining the current approach to the reserve penalty factors and the cap on the energy component of LMP at $3,750/MWh.

FERC said PJM’s governing documents don’t specify the latter, only the caps on prices for synchronized and non-synchronized reserves.

“Because the remand order maintained the May 2020 order’s directive that PJM adopt a new 30-minute reserve requirement and secondary reserve product, PJM may propose revised reserve price caps to reflect the addition of this new product, but we note that the commission will review PJM’s proposal with the benefit of parties’ comments submitted as part of the compliance proceeding,” FERC said.

The Monitor argued that while the overall energy and reserve price cap is not explicitly in the PJM tariff, the commission’s approval of the $850/MWh penalty factors and an overall $2,700/MWh combined energy and reserves price cap make it “clear that the cap is included in PJM’s market design.”

It also argued that the remand order did not direct PJM to increase the synchronized and primary reserve prices or the LMP to reflect the new 30-minute reserve requirement, even though it directed the RTO to implement a reserve penalty factor for the requirement.

“The IMM’s analysis of price formation during instances of reserve price capping underscores the complexity of the issue at hand and the need to develop a further record,” FERC said.

Danly Dissents

James-Danly-2021-11-07-(RTO-Insider-LLC)-FI.jpgFERC Commissioner James Danly | © RTO Insider LLC

Commissioner James Danly rebuked the decision, saying the remand order had “profound and unforeseen consequences” on PJM’s market design. Danly said the “majority rushed to issue” in the remand order, discounting objections from PJM and other litigants.

“Through a tortured reading of the voluntary remand order, the majority ‘clarifies’ that the reserve price caps were not removed and admits that mere reinstatement of the reserve price caps fails to account for PJM’s new reserve product,” Danly said. “This is quite a significant ‘clarification.’”

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DOE Launches $6B Nuke Credit Program

The U.S. Department of Energy on Tuesday invited public comment on a $6 billion program to prevent the early closure of nuclear generators.

The Civil Nuclear Credit Program, funded under the Infrastructure Investment and Jobs Act (IIJA), will allow owners and operators of commercial nuclear reactors at risk of closure to competitively bid on credits to keep them in operation. The IIJA requires applicants to prove their reactor will close for economic reasons and that the closure will result in increased air pollution. Credits will be allocated over a four-year period.

“U.S. nuclear power plants are essential to achieving President Biden’s climate goals, and DOE is committed to keeping 100% clean electricity flowing and preventing premature closures,” Energy Secretary Jennifer Granholm said in a statement.

Nuclear power currently provides 52% of the nation’s 100% carbon-free power, but 12 reactors have closed since 2013 because plant owners said they were unprofitable. Illinois, New Jersey, New York and Connecticut have all approved subsidies to keep nuclear plants within their borders operating.

DOE’s Request for Information in the Federal Register solicits comments on subjects including the certification process, eligibility criteria and allocation of credits. The RFI was accompanied by a Notice of Intent informing generators of the program.

The department’s press release announcing the program quotes an endorsement from Sen. Joe Manchin (D-W.Va.), chairman of the Senate Energy and Natural Resources Committee and an essential vote for the climate programs in the Biden administration’s proposed Build Back Better bill.

“I fought for the inclusion of this critical program to prevent further premature closures of nuclear power plants and to maintain high-paying jobs in communities across America,” Manchin said.

Responses to the NOI and RFI addressing general program design and bid process are due by 5 p.m. MT on March 17. Responses on the certification process should be submitted by March 8.

Battery Supply Chains

DOE last week also outlined a $2.91 billion program in the infrastructure law funding refining and production plants for battery materials, battery cell and pack manufacturing, and recycling.

Responding to Biden’s executive order on supply chains, DOE last year recommended establishing domestic production and processing capabilities for critical materials for a domestic battery supply chain.

One NOI details DOE plans to support the creation of new, retrofitted and expanded domestic facilities for battery recycling and the production of battery materials and cell components.

A second NOI outlines DOE’s initiative for research, development and demonstration of second-life applications for batteries previously used in electric vehicles. It seeks proposals for new processes for recycling, reclaiming and adding materials back into the battery supply chain.