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November 20, 2024

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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

” data-credit=”© RTO Insider LLC” data-id=”3065″ style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Aaron Berner, PJM | © RTO Insider” data-uuid=”YTAtNTQzNTM=” align=”right”>Aaron Berner, PJM | © RTO Insider LLC

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.

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NARUC Panel: Plan for Climate Change

On the first anniversary of Winter Storm Uri’s gut punch to the Midwest and Texas grid, industry experts discussed how to prevent climate change from setting off future mass blackouts.

Monday’s panel was part of the National Association of Regulatory Utility Commissioners’ Winter Policy Summit.

Texas-based energy consultant Alison Silverstein said Texans will be paying for the storm’s destruction in their bills for the next 20 years “without that ever making a difference” in grid reliability “or preventing the next disaster.”

Silverstein said it’s time for grid planners to start thinking about not “if it could happen, but when it will happen here.” She said the grid needs to be reinforced to handle more regular extreme weather and that using historical weather events is “no guide” in planning for future events.

“This requires us being very, very paranoid,” Silverstein said. “The threats are radically different than today.” She called for a different “scope of reference” and analyzing the costs of not making investments.

“Nobody was spared. It seemed that if you were in the area, you were going to suffer,” David Ortiz, acting director of FERC’s Office of Electric Reliability, said of power outages caused by last February’s storm.

Ortiz said the “simple” winterization of plants could have cut generation outages by about 50% and 60% in SPP and ERCOT, respectively.

“We have to remember that efficiency and resilience are enemies of each other,” said MISO President Clair Moeller, appearing on behalf of the ISO/RTO Council. He noted that resiliency requires advance fuel contracts and extra megawatts in capacity.

Moeller said RTOs and ISOs are considering a variety of strategies to make their generation fleets more available.

“Some of it’s a carrot; some of it’s a stick. Some of it’s an orange stick,” he joked.

Moeller said it’s clear that grid operators need higher reserve margins in the winter. “Big risk hours aren’t all on the peak period, and haven’t been for a while,” he said.

“It’s tremendously important to move away from this peak planning,” Ortiz agreed.

Moeller said coal and gas fuel supplies continue to be a concern, with the coal supply chain weakening to where only firm contracts are fulfilled with any degree of certainty. He pointed out that MISO’s Midwest region still relies on a 50% coal mix during the winter.

Natural gas generation operators aren’t ready for the flexibility that RTOs are going to start asking of them, Moeller said. He said gas-electric coordination will become even more important going forward.

Silverstein said conversations following the storm focused intensely on generation’s winterization and ignored that properly insulating customers’ homes could have alleviated demand. She said poorly-insulated Texas homes and their use of resistance heating contributed to the event’s severity.

Ortiz also cautioned against “staying on only the supply-side of the equation.”

“There’s a tremendous amount that can be done on the demand side,” he said.

Silverstein said more state regulatory bodies must devise meaningful demand-management programs.

Moeller said the ensuing “blame game” and court battles following last year’s winter storm are unhelpful. He also said data requests to MISO following the event were daunting and said a better organized data-sharing method would be useful.

“People are betting their lives and their livelihoods on us getting this right,” he said.

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Killingly Uncertainty Could Delay Capacity Auction Results Another Month

It could be another month before stakeholders and the public in New England find out the results of ISO-NE’s capacity auction from last week as the grid operator wrestles with the ongoing fallout of an 11th-hour court ruling over a Connecticut power plant.

In a filing to FERC on Tuesday, ISO-NE said that the Feb. 4 D.C. Circuit Court of Appeals ruling allowing the Killingly Energy Center to temporarily maintain its place in Forward Capacity Auction 16, which took place on Monday, could mean it is unable to announce the results of the auction until mid-March or later.

As of right now, there are two sets of auction results hanging in limbo, as ISO-NE calculated clearing prices and quantities both with and without Killingly participating.

That means the grid operator will also have to delay its preparations for next year’s capacity auction, FCA 17, which were supposed to begin this week. For example, ISO-NE is required to provide market participants that have existing capacity resources with their qualified capacity values for those resources on Thursday.

“The definitive calculation of those qualified capacity values cannot be made for all resources without final FCA 16 results,” ISO-NE said in the filing.

The grid operator considered moving forward with planning for next year’s auction using both sets of results but decided that approach would not be compatible with its systems and processes and would pose “extraordinary risk to all the downstream activities.”

ISO-NE is asking FERC for permission to delay establishing that and other dates as part of the FCA 17 timeline until the Killingly situation is clarified.

FERC still has an important role to play in ending the uncertainty. The agency has a rehearing request in front of it, filed by Killingly developer NTE Energy, which is appealing the agency’s decision to affirm an ISO-NE decision to terminate the capacity supply obligation for the project. (See Killingly Stays Alive After DC Circuit Halts FERC’s Termination Order.)

While FERC issued a notice denying rehearing “by operation of law” on Feb. 11, that was not sufficient to “resolve” the request, ISO-NE said.

The uncertainty could also mean that next year’s capacity auction is pushed back to March instead of February.

“Based on the analysis that the ISO has conducted to date, the ISO envisions that the qualification activities for FCA 17 will begin in April 2022, and FCA 17 will occur in March 2023,” the filing said.

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NASEO Panel Charts Role of Fossil Fuels in Energy Transition

The term “clean energy” has become a flashpoint in current debates swirling around decarbonizing the U.S. electric system.

Should it be defined solely in terms of renewable technologies — wind, solar, storage hydropower and, maybe, nuclear?

Or, with climate change intensifying extreme weather events across the U.S. and worldwide, is a broader view — encompassing hydrogen, natural gas and carbon capture — required to drive rapid and deep reductions in greenhouse gas emissions?

Speakers at the recent Energy Policy Outlook Conference of the National Association of State Energy Officials (NASEO) leaned strongly toward the latter approach, reflecting the broad range of political, economic and technical issues surrounding state-level plans for cutting emissions to net-zero by midcentury.

Karl Hausker, WRI 2022-02-12 (RTO Insider LLC) FI.jpgKarl Hausker, WRI | © RTO Insider LLC

“Nearly all states that have set a goal of zero-carbon for their utilities define it in terms of 100% clean energy, not 100% renewables,” Karl Hausker, senior fellow for climate policy at the World Resources Institute, told conference attendees at a Feb. 9 panel on decarbonization pathways.

The reason, he said, is that “as a power system approaches 100% renewable, system costs increase sharply … and maintaining reliability becomes more difficult.”

Hausker argued for a five-point strategy for getting the U.S. economy to net zero, including deep efficiency, broad electrification and increasing electricity supply, while also commercializing carbon capture and sequestration (CCS) technologies and aggressively pursuing a range of research and development efforts.

“We are betting on solutions, and there is a big case for spreading our chips, like we do in Las Vegas,” he said. “The good news is that if we can do this smartly and efficiently and wisely, we can keep the cost of this transition to 1 or 2% of global GDP or 2% of U.S. GDP. That’s a pretty good price to pay for the damages [of climate change] that are already being felt in the world.”

Richard Meyer 2022-02-12 (RTO Insider LLC) FI.jpgRichard Meyer, AGA | © RTO Insider LLC

Speaking on the same panel, Richard Meyer, vice president for energy markets at the American Gas Association (AGA), also called for a multipronged approach to net zero, but with a central role for natural gas to ensure reliability, affordability and minimum disruption for Americans who rely on gas for space and water heat.

Drawing on figures from the EPA and the Energy Information Administration, Meyer said that natural gas accounts for 13% of U.S. greenhouse gas emissions, most of which are produced by residential, commercial and industrial customers. A new report from the AGA outlines four key strategies for cutting those emissions: reducing the industry’s methane emissions, improving efficiency, decarbonizing the gas supply via renewable natural gas and hydrogen, and offsetting emissions with carbon capture and sequestration and direct air capture.

“There is no one single pathway to zero,” Meyer said. “Gas utilities, gas infrastructure can play crucial and enduring roles … Decarbonization planning, including the evaluation of gas and carbon mitigation strategies, have to be examined with regional-level assessments and evaluated by their ability to support tenets aligned with safety, reliability, affordability, resilience and feasibility.”

Net-negative emissions

The reality of climate change, and the realization that avoiding its worst impacts will require economy-wide, transformative decarbonization, is no longer a point of contention in the energy sector. Nor is the prominent role renewable technologies and electrification must play in the transition.

Rather, the debate now centers on what role, if any, fossil fuels — the main source of the greenhouse gas emissions driving climate change — can or should play, while also considering how deeply integrated they are in global power systems and economies.

Speaking on a later panel at the NASEO conference, Jennifer Wilcox, principal deputy assistant secretary for the Office of Fossil Fuels and Carbon Management at the Department of Energy, framed carbon capture technologies as a solution for hard-to-decarbonize industries, such as steel and cement. 

The need for net-negative emissions (IPCC) Content.jpgThe need for net-negative emissions | IPCC

“A big focus of what we’re looking at is not just the sectors that we’re dependent upon today that are sourced from fossil fuels, but those that are expected to be committed through midcentury,” Wilcox said. “And so, when we look at the power sector, it’s not that CCS is a blanket solution across all fossil fuel-fired power plants, but we look at what is the infrastructure that’s expected to persist through midcentury, and those are really good targets potentially for CCS.”

Hausker believes that despite ongoing efforts to curb GHG emissions, the U.S. will probably not meet the emission reduction targets needed to keep climate change to the 1.5-degree or even 2-degree target set in the UN Paris agreement and confirmed at the recent Climate Change Conference in Glasgow.

“So, beginning midcentury and continuing on for the rest of the century, we will have to get into a net-negative emissions posture,” he said. “We will have to take more CO2 out of the air than we may still be putting in midcentury and beyond.”

CCS and direct air capture could be critical in such a scenario, he said. Further, Hausker argued that while the costs of renewable wind and solar have dropped, the industry standard for comparing the cost of different fuels — the levelized cost of energy (LCOE) — “is a flawed metric.”

“It’s really important for policy makers and policy influencers to focus on system costs, not the LCOE,” which is based on the average cost of a megawatt-hour of power from a standalone plant, he said. The system cost is “the cost that consumers ultimately pay … including all the technologies needed to maintain a reliable grid.”

Thus, even if wind and solar are themselves cheaper than fossil fuels, system costs for a 100% renewable grid might be high.

Further, while existing storage technologies have solved the problem of the minute-to-minute variability of renewables, further research will be needed to ensure reliability across daily and seasonal weather patterns, he said. When wind or solar generation drops for days at time, “you better have something to turn on,” he said.

A Moral Hazard Question

The natural gas industry has long maintained that its resources are needed to back up the intermittency of renewables.

“Part of the value of what the gas system does for us today is its ability to store and transport large amounts of energy to meet seasonal and daily energy use,” Meyer said. “An integrated approach to decarbonization that leverages the advantages of the gas distribution system is likely to support a more effective, reliable and resilient transition to a net-zero energy system and minimizes negative impacts for customers.”

In the U.S., planning for decarbonization will also need to take “highly localized” regional differences into account. Such factors might include “climate and temperatures … energy prices,” he said. “What does the housing stock look like? What kind of businesses are using gas?” 

The AGA report lays out four pathways to net zero by 2050, based on different combinations of efficiency, hybrid gas-electric heating, a mix of other technologies, and renewable natural gas and carbon capture technologies. A key finding, all four of the pathways would increase the number of customers served by natural gas utilities, Meyer said. “In other words, we don’t have to make a choice between adding new customers and helping them achieve ambitious environmental goals.” 

Moderating the decarbonization panel, Joe Pater, director of the Office of Energy Innovation at Wisconsin’s Public Service Commission, provided a real-life example of the challenges his state faces as it increases renewable energy and storage, and explores electrifying home heating.

The state has heavily promoted “high-efficiency natural gas furnaces over the last few decades,” he said. “But now we are talking about heat pumps, and we’re talking about cold-climate heat pumps that are coming to market. From the contractor perspective, we’re kind of getting a little bit of pushback, so I think the reality here is that renewable natural gas is going to need to be a bigger factor in Wisconsin.”

Solving such problems will require a short list of regulatory actions, Meyer said, including expanding equity, energy efficiency and demand-side management programs and updating rate structures and cost recovery “so all parties are incented and support greenhouse gas emissions reductions.”

“Methods to compensate our customers for the services they provide to other parts of the energy system” should also be considered, he said.

In his closing remarks, Hausker acknowledged the environmental arguments against carbon capture — that it is too expensive, does not work and prolongs our dependence on fossil fuels. While he disagrees with the first two points, he said, the idea of prolonged dependence raises a “moral hazard question.”

“Just perfecting the technology, commercializing it, do we create a moral hazard where we’re just likely to keep burning fossil fuels? You can’t dismiss that,” he said. “We have to balance that moral hazard problem against the very physical hazard of what if we come to 2040 or 2050 and we have no means to take out of the climate the CO2 that we need to at that point?”