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.
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.
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 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.
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.
PJM 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.
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.
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.’”
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.
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.
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.
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.
“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.”
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
“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?”
PJM delayed a vote at last week’s Market Implementation Committee meeting on a proposal addressing pseudo-modeled combined cycle minimum run time guidance after stakeholders asked for more time to review the changes.
Market sellers can model a combined cycle unit as multiple pseudo units composed of a single combustion turbine and a portion of a steam turbine. Hauske said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit for an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times on parameter-limited schedules (PLS).
The proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of any second and subsequent pseudo-modeled block to remove the associated steam turbine start-up time that is included in the parameter limit when it’s dispatched.
Hauske said PJM removed language calling for “hourly” updates of the minimum run time parameter in order to avoid creating a “compliance trap” for market sellers who have several pseudo-modeled combined cycle units.
Adrien Ford of Old Dominion Electric Cooperative said she would appreciate the opportunity to circulate the updated manual language with ODEC staff before a vote to see what potential impact removing the “hourly” language could have on operations.
“ODEC’s wholly supportive of not creating compliance traps,” Ford said.
Calpine’s David “Scarp” Scarpignato said he agreed with taking more time to circulate the manual language internally.
“It’s very different than last month’s language, so I would recommend a delay,” Scarp said.
Hauske said PJM wants to have final endorsements by the March 23 Markets and Reliability Committee meeting because the RTO’s unit-specific parameter adjustment process starts Feb. 28. PJM must provide a determination on the requests by April 15.
PJM staff agreed to delay the vote on the proposal but will proceed with conducting a first read of the language at the Feb. 24 MRC meeting.
Manual 27 Revisions Endorsed
Stakeholders unanimously endorsed manual revisions related to a recent FERC order in response to industrial customers’ protest of PJM’s proposed revisions to its administrative rates.
While FERC accepted it for filing, the commission in December ordered hearing and settlement judge procedures for PJM’s proposed tariff revisions changing its administrative cost recovery to monthly rates based on that month’s costs and that month’s billing determinations. (See FERC Sets Hearing on Industrials’ Challenge to PJM Administrative Rates.) The PJM Industrial Customer Coalition had protested the proposal.
Rebecca Stadelmeyer of PJM’s market settlement development department reviewed the revisions to Manual 27: Open Access Transmission Tariff Accounting, which include reorganized wording to distinguish between administrative rates and pass-through rates, and a new section to only be reconciliation for transmission owner scheduling system control and dispatch service.
The manual changes will now go to the Feb. 24 MRC meeting for final endorsement.
Manual 18 Revisions
Jeff Bastian, senior consultant in PJM’s market operations department, provided a first read of revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders regarding:
PJM’s revisions to the application of the minimum offer price rule (MOPR), which became effective by operation of law in September when the commission deadlocked (ER21-2582);
PJM’s October compliance filing to amend several sections of Attachment DD of the tariff establishing a replacement market seller offer cap (EL19-47);
restored tariff provisions related to the prior backward-looking energy and ancillary services (E&AS) offset for the 2023/24 Base Residual Auction and beyond (EL19-58); and
the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve (ER19-105).
Bastian said language in section 3.3.2 was updated to reflect that the net E&AS of the reference resource combustion turbine will be calculated using the forward-looking methodology with application of the 10% adder for only the 2022/23 delivery year. The net E&AS will be determined using the historical approach and without application of the 10% adder for all other delivery years.
The revisions also delete language in section 5.4.5.2 describing the consequences of accepting a state subsidy after electing the competitive exemption or certifying that a resource is not state-subsidized.
Stakeholders will vote on the changes at the March MIC meeting, with a final vote planned for the March 23 MRC meeting.
Critical Gas Infrastructure
Jack O’Neill of PJM’s demand response department provided a first read of a problem statement and issue charge addressing the recommendation for demand response participation in a FERC and NERCreport on last February’s winter storm in Texas and other parts of the South.
The report included a key recommendation “to require balancing authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) to prohibit use of critical natural gas infrastructure loads for demand response.”
PJM began discussions with curtailment service providers (CSPs) through the Demand Response Subcommittee to identify impacted loads for the 2021/22 winter season, O’Neill said, and it developed a preliminary definition of critical gas infrastructure loads.
O’Neill said CSPs have cooperated with PJM to identify impacted loads in the RTO’s DR Hub application so dispatchers have “operational awareness.” PJM estimates there are about 20 facilities of critical gas infrastructure load that participate as DR in the RTO’s wholesale markets, amounting to around 95 MW of winter capability and 190 MW of summer capability.
The key work activities of the issue charge include defining critical gas infrastructure loads and PJM market participation rules in compliance with FERC/NERC recommendations and developing a transition mechanism if new participation rules impact member’s capacity commitment.
PJM wants to assign the work to the Demand Response Subcommittee. Work on the issue is expected to last 12 months, and the goal is to file any necessary tariff changes with FERC in the first quarter of 2023.
“It’s not a huge issue for PJM considering our demand response fleet is roughly 6,500 MW,” O’Neill said. “But it’s still something that needs to be addressed.”
Stakeholders will vote on the issue charge at the March MIC meeting.
Operating Reserve Clarification
Phil D’Antonio of PJM’s energy market operations department provided a first read of a problem statement and issue charge addressing clarifications and potential enhancements to the rules for paying operating reserve credits to resources operating when requested by the RTO.
D’Antonio said PJM pays energy uplift to market participants under specified conditions to ensure that competitive market outcomes “do not require efficient resources to operate for the PJM system at a loss.” He said the uplift payments are intended to act as one of the incentives for generation owners to offer energy for dispatch based on short-run marginal costs and to operate units as directed by the RTO’s operators.
PJM wants to clarify the definition of “operating as requested by PJM” in both the tariff and manuals because it “lacks the type of systematic approach” found in the definition of “following dispatch,” D’Antonio said, which is used in assessing balancing operating reserve deviation charges. He said PJM and the Independent Market Monitor have had debates over the meaning of the definition.
“We feel the current definition isn’t as specific as we would want it to be and leads to different interpretations as we apply operating reserve credits and uplift payments,” D’Antonio said.
The key work activities in the issue charge include determining a definition of “operating as requested by PJM” as it relates to payment of operating reserve credits. It also seeks to establish alternative rules addressing the megawatt level to which balancing operating reserve credits should be paid to resources found not to be closely following PJM’s commitment and dispatch instructions.
The issue will be worked on at the MIC, D’Antonio said, with the potential for special MIC meetings to be scheduled as needed. Work is expected to last around nine months.
Calpine’s Scarp said he would like to see discussions include how renewable resources will get credits and an “explicit piece of the issue charge” on what renewable resource output is compared to determining credits or deviations.
Monitor Joe Bowring said he has been bringing up this issue for at least four years and was glad to see PJM and stakeholders deciding to tackle it. He also appreciated the opportunity to work with PJM in developing the issue charge and problem statement.
Bowring added, however, that they did not agree about the current rules or the appropriate solution. Bowring said the Monitor will continue to pursue parallel paths to address the issues associated with paying uplift to units not following dispatch, including making referrals to FERC’s Office of Enforcement.
“It’s essential to get these issues clarified,” Bowring said.
Panelists at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit on Monday encouraged attendees to take an active role in pushing utilities to invest in cybersecurity.
“It’s really worrying about the weakest link here when it [comes] to cyber. … If our weakest link goes down, then we’re all in real trouble,” Deputy Secretary of Energy David Turk told the “Protecting the Homeland” panel at the summit’s general session. “And it strikes me [that] you all as commissioners … play an incredibly important role to make sure that you’re taking care of the weakest links … so people appreciate why we need to make the investments … from the get-go and build resilience [and cyber] in by design.”
Cyber the Responsibility of All
Turk and his fellow panelists said that recent high-profile cyberattacks such as the Colonial Pipeline ransomware attack and the hack of the SolarWinds Orion software have helped to shed light on the importance of cybersecurity. However, even as utilities that now say they are taking cybersecurity seriously, the leadership often still believes that addressing the threat means assigning it to specialists.
National Cyber Director Chris Inglis | NARUC
This is an outdated way of thinking that ignores the way hackers infiltrate organizations, National Cyber Director Chris Inglis said. He pointed out that the Colonial attack was possible because “a human being made a mistake [and] clicked on a link … not realizing that it’s somebody else’s code.” The lesson: No matter what kind of firewalls and other precautions a company’s security professionals put in place, the organization is still vulnerable unless every employee is committed to maintaining security.
“We still don’t have all the heads in the room … saying, ‘I have a role to play.’ Too often, we see this as the work of champions who have the word ‘cyber’ or ‘IT’ [information technology] in their job titles,” Inglis said. “Individuals making use of cyberspace make choices all day, every day, that then have … a heavy influence on how things proceed.”
Inglis acknowledged the difficulty and expense of adding new cybersecurity requirements to the existing grid but said that this is where regulators could play a role by ensuring that refusing the necessary investment is not an option for utilities.
“This is simply an investment we must make. No one doubts that there should be a third prong on the plug that you plug into the wall in a 110-volt system — we should have no less of a doubt that cyber should be built into everything that we do,” he said.
Private, Public Sectors Must Support Each Other
Berkshire Hathaway Energy CEO Bill Fehrman | NARUC
Bill Fehrman, CEO of Berkshire Hathaway Energy, agreed with the government representatives that “if a company cannot afford to properly protect their systems, then they should not be in business.” But he also observed that with the proliferation of cybersecurity threats, utilities — especially smaller municipal and rural electric providers — are facing heavier burdens than they have ever encountered before.
“We, across our networks, take about three and a half billion hits a day. About 10% of those are actual, legitimate business issues; the rest are the people … who are trying to get in and do things to us,” Fehrman said. “And today it’s much broader than just the hits on the network. It’s on our supply chain: we now worry about every single component that is in the … equipment that we buy. … Because of concerns of equipment coming, in particular, from China … we may have to spend more money to get equipment from more U.S.-friendly countries.”
The diversity of threats makes it paramount that utilities be able to share data quickly on security developments — a role that NERC’s Electricity Information Sharing and Analysis Center seeks to fill.
“We don’t need all 3,000 utilities in a room,” Fehrman said. “What we do need is a way to quickly come in, assess that information, and then through the information sharing mechanisms that we have get it pushed back out, so that even the smallest of the utilities have that information that they need, so that they can properly operate their systems.”
Inglis agreed with Fehrman that the electric sector occupies a unique position in national security, with private companies responsible for vital national infrastructure assets. He said that the government must recognize this and position itself accordingly to support the stakeholders in this space, rather than dictate how they ought to respond to the latest threats.
“In the realm of cyberspace, unlike just about every other national security issue of some consequence … the private sector is the supported entity,” Inglis said. “Most of the resources exist in the private sector: just about all the innovation … capacity building [and] operation is in the private sector. The government, therefore, if it’s going to be coherent, needs to be prepared for a particular purpose, which is to better support the private sector.”
A group of New York legislative committees are working together to establish whether the state has a clear electric vehicle charging deployment plan so residents will be comfortable buying clean cars.
To meet state climate goals, New York needs to incentivize EV adoption, but the lack of consumer confidence in being able to charge EVs “is still very problematic,” Rep. William Magnarelli, chair of the House Transportation Committee, said during a hearing on Thursday.
Four House committees convened the hearing to identify existing plans and programs for building EV charging facilities and what the state can do to expedite infrastructure development.
Currently, New York has 90,000 registered EVs and 9,000 charging stations to support them, said Adam Ruder, assistant director of clean transportation at the New York State Energy Research and Development Authority (NYSERDA).
“New York needs tens of thousands more charging stations in the coming years and hundreds of thousands more in the coming decades to serve the number of EVs that will be on our roads,” he said.
Gov. Kathy Hochul signed a clean cars law in September that sets a goal for all new passenger car and truck sales in the state to be zero-emission by 2035. The bill directs the Department of Environmental Conservation (DEC) to prepare an EV market development strategy this year.
“This effort will include a thorough evaluation of EV infrastructure needs and will be grounded in analytical work being done by NYSERDA to build upon the substantial investments and programs already in place,” said Jared Snyder, DEC’s deputy commissioner of air resources, climate change and energy.
Programs and Progress
State supported EV infrastructure development is spread out across different programs and agencies.
At the DEC, for example, the Climate Smart Communities program helps local governments with climate- and energy-related activities with grants and rebates. To date, the program has funded the installation of 650 public charging ports, Snyder said.
“In most cases, these are Level 2 chargers, but a few communities have invested in [fast] charging,” he said.
NYSERDA wrapped up its three-year Charge Ready NY program last year for Level 2 public charging stations, completing 3,000 charger installations and approving another 1,000 that are currently under development. The agency is also funding fast-charging station deployment in Upstate New York with a target of installing 92 stations over the next two years, Ruder said.
In addition, he said, state agencies are reviewing new federal guidance on how they can use an estimated $175 million for EV charging coming from the Infrastructure Investment and Jobs Act over the next five years. (See States to Get $615 Million for EV Charging from IIJA Funds.)
In November, Hochul announced that state utilities would begin implementing an EV charging make-ready program to deploy 50,000 Level 2 chargers and 1,500 fast chargers over the next four years. The utilities are on track to meet those goals, with active applications for more than 800 fast-charging ports and 20,000 Level 2 ports, said Zeryai Hagos, deputy director of the Office of Markets and Innovation at the New York Department of Public Service.
EV charging deployment efforts at the New York Power Authority (NYPA) have underperformed based on stated programmatic goals, a Feb. 4 State Comptroller report said.
“The authority’s very slow startup is of great concern,” Rep. Steve Englebright, chair of the House Environmental Conservation Committee, said during the hearing.
New York officials launched Charge NY in 2013 to be administered by NYPA, NYSERDA and DEC. An initial program goal of deploying 3,000 charging stations increased in 2018 to 10,000 stations by 2025. Under the Charge NY umbrella, NYPA launched a $250 million program in 2018 called EVolve NY to install fast chargers on major highways through 2025.
By the end of 2019, NYPA had not met its goal of installing 200 fast-charger ports, the report said. In total, NYPA had installed 140 charging stations with 499 ports under Charge NY and EVolve as of September 2020. Of those installations, only one was a fast charger for the EVolve program, the report said.
To date, NYPA has 60 fast chargers installed at 16 sites, Sarah Salati, executive vice president and chief commercial officer, said.
“Based on the audit, the numbers are abysmal, and I’m particularly upset about the fact that there’s really missed opportunities,” Rep. Keith Brown said during the hearing.
As part of its original EVolve program goal, NYPA expected to build 100 fast chargers in collaboration with the New York Thruway Authority. That work, however, was delayed by the thruway authority’s plan to update a group of rest areas, and Salati said the chargers project “was undertaken by a private sector entity.”
In addition, Salati said NYPA did not receive regulatory authority to install chargers at non-governmental sites until April 2019, which delayed buildouts at non-public sites. Pandemic supply chain issues have stymied more recent efforts to advance the fast-charging program, she said.
