Fuel cell technology could play a “critical role” in New Jersey’s drive to reach 100% clean energy, according to a state report released Aug. 8 that cited the energy source’s potential use in transportation, supplementing the state’s growing wind and solar sectors and acting as an emergency backup energy source.
The report by the New Jersey Fuel Cell Task Force, which Gov. Phil Murphy (D) created, outlines 21 recommendations on how the state should position itself to reap the benefits. It adds that the state is well positioned for such a move because of its high concentration of engineers and scientists, the network of research universities present and the “numerous industrial and chemical plants that could be used to generate hydrogen.”
Fuel cells have “the potential to reduce greenhouse gas emissions and harmful air pollutants and expand the state’s diverse clean energy portfolio,” the report says, echoing Murphy.
Fuel cells use hydrogen or other fuels to generate electricity, producing only water and heat as byproducts and emitting no greenhouse gases. In April, New Jersey and seven other states submitted a proposal seeking $1.25 billion from the U.S. Department of Energy to create a Northeast Regional Hydrogen Hub. (See Maine, RI Join Multistate Hydrogen Agreement.)
Schematic drawings of a how a fuel cell works (left) and a hydrogen fuel cell stack. | EIA/Fuel Cell Store
President Joe Biden authorized the hydrogen hub grants in the $1.2 trillion Infrastructure Investment and Jobs Act signed into law in November 2021. It provides $8 billion for four regional hydrogen hubs, $1 billion for research to bring down the cost of hydrogen electrolysis and $500 million to support equipment manufacturing.
Hub Proposal
Murphy created the task force to promote the use of cells in the state, and the body’s recommendations, according to the report, are designed to “create momentum in advancing fuel cells and hydrogen within the state and strengthen New Jersey’s hub proposal.”
Fuel cell electric vehicles (FCEVs) could be a key use of the technology, especially for medium- and heavy-duty vehicles, for which the battery weight, limited range and relatively long recharge time make battery power less viable, the report says. For similar reasons, technology could be extremely useful for buses, rail, marine vessels and material-handling equipment, the report says. (See Will Hydrogen Fuel Cell Vehicles Beat out Battery Electric?)
The faster fueling time of fuel cells, in particular, is a benefit, the report says. An FCEV can be filled up in about the same time as it takes to refuel a diesel engine, offering a timelier option than an electric battery, which can take hours to refuel depending on the strength of the charger, the report says.
“The state is also home to many large warehouses where fuel cell-powered material-handling equipment offers significant advantages over diesel or battery power in terms of emissions, productivity and lifecycle costs,” the report says.
The report’s other suggestions on how the state should strengthen its ability to take advantage of fuel cell technology include:
Explore ways to incentivize technology to improve local air quality;
Explore fuel cells as a non-combustion option for demand response programs, which provide alternate energy sources when high demand stretches the available electricity supply;
Consider options for state tax credits on investments or production of low-carbon hydrogen;
Encourage revisions in PJM’s tariff to include green hydrogen production;
Consider requiring electric distribution companies to propose state electricity resilience tariffs to help fund system strengthening measures;
Focus the Board of Public Utilities’ grid modernization program on valuing desired environmental attributes for distributed energy resources;
Spur FCEV adoption through incentives, bills, programs and tax credits;
Engage private sector industry partners to develop fuel cell and hydrogen-related pilot projects in New Jersey; and
Engage a broad hydrogen and fuel cell technology education, training and workforce development program.
Dispatchable Electric Supply
The report also sees the ability of fuel cells to turn on and off as a potentially useful source of dispatchable electric supply. That would help, for example, with “peak shaving,” offering a secondary energy supply to help handle peak demand periods and providing a supplement to intermittent sources, such as wind and solar, according to the report.
“The revenue that fuel cells receive for their value to the grid could be used as an incentive to promote their use as a replacement for diesel-powered emergency generators,” the report says. In addition, “less efficient peak load serving units create what is known as locational marginal emissions during peak load events; fuel cells directly offset these marginal emissions.”
Fuel cells also could be a source of backup power to the state, providing reliability and resilience, especially in situations in which natural disasters knock out power from the grid and can complement or provide a substitute to battery-based storage, the report says.
“Examples of fuel cells and hydrogen for backup power include small scale backup power (less than 100 kW), long-duration energy storage, microgrids and utilities,” the report says.
The Department of Energy on Friday made a series of announcements signaling that the Biden administration is doubling down on its commitment to develop and commercialize carbon management technologies as a critical element of its climate agenda.
The selection of two projects as the nation’s first regional direct air capture (DAC) hubs — one each in Louisiana and Texas — grabbed the headlines, but the two notices of intent (NOIs) released on the same day also show DOE digging in for the long haul, both on research and development and “responsible” implementation of its programs. (See DOE to Fund Direct Air Capture Hubs in Texas, Louisiana.)
Published in the Federal Register, the first NOI unveils DOE’s plans for a Responsible Carbon Management Initiative that will “encourage project developers and others in [the] industry to pursue the highest levels of safety, environmental stewardship, accountability, community engagement and societal benefits in carbon management projects.”
The NOI contains the agency’s Principles for Responsible Carbon Management, which cover community engagement and tribal consultation, environmental justice, transparency, long-term environmental stewardship, and regulatory and health and safety standards.
Since the passage of the Infrastructure Investment and Jobs Act, more than 100 carbon removal projects have been announced in the U.S., according to Brad Crabtree, assistant secretary of DOE’s Office of Fossil Energy and Carbon Management (FECM).
“That’s why this Responsible Carbon Management Initiative is so important,” he said in Friday’s announcement. “It will provide a framework for encouraging and recognizing best practices in the development of carbon management projects and for fostering transparency and learning through greater data and information sharing among industry, governments, communities and other stakeholders.”
The second NOI sets out DOE’s road map for new and ongoing research grants and prizes to advance its Carbon Negative Shot (CNS), one of the agency’s Energy Earthshot initiatives, which set high aspirational goals for improving the efficiency and cutting the costs of emerging technologies.
CNS is targeting “gigaton-scale deployment” for carbon dioxide removal technologies within the next decade, at a price of less than $100/metric ton of carbon dioxide captured, including the cost of monitoring, reporting, verification (MRV) and “durable storage.”
A gigaton of CO2 would equal 1 billion tons, or about one-fifth of total U.S. CO2 emissions in 2022, according to DOE.
Current prices for carbon removal technologies vary widely, from “low hundreds a ton and low thousands a ton,” said Noah Deich, FECM deputy assistant secretary, in an interview with NetZero Insider.
The agency defines carbon dioxide removal (CDR) as any form of carbon capture from ambient air or water, as opposed to capturing emissions from a power plant or industrial facility. The funding opportunities ahead will include pilots in small biomass carbon removal and storage, enhanced mineralization projects and marine projects, including direct capture from the ocean.
Biomass carbon renewal refers to technologies that use plants or algae to remove CO2 from the atmosphere, which in some cases may include combustion and carbon capture. Enhanced mineralization uses “alkaline materials such as calcium- or magnesium-rich crushed rocks spread over the ground,” according to a DOE fact sheet,
Other planned funding includes prizes for commercial-scale DAC pilots, smaller than the hubs, and funding for projects “developing and commercializing protocols, technologies and methods to improve MRV” of different carbon removal technologies.
Building the Market
Both the United Nations International Panel on Climate Change and the International Energy Agency (IEA) have framed carbon removal and storage technologies as essential to limiting climate change to 1.5 degrees or 2 degrees Celsius by 2050 or later.
In a 2022 analysis, the IEA said CDR should be part of a comprehensive strategy for reaching global net-zero emissions, but “not an alternative to cutting emissions or an excuse for delaying action.” The agency sees a more modest role for DAC, projecting that it would account for about 85 metric tons (MT) of CO2 removal worldwide in 2030 and 980 MT in 2050.
President Joe Biden and Energy Secretary Jennifer Granholm also have promoted carbon management technologies as central to the U.S. commitment to cut the nation’s greenhouse gas emissions 50-52% by 2030.
But to date, carbon capture and storage technologies have been used in the U.S. primarily for enhanced oil recovery (EOR) — that is, injecting CO2 into low-producing oil wells, first pushing out more oil from crevasses where the CO2 then can be permanently stored.
Both the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) provide major new funding to develop a range of carbon management technologies at commercial scale. The IIJA provides $3.5 billion for the development of four DAC hubs, which will include CO2 capture, processing and sequestration, at commercial scale.
As the first two hubs, Occidental Petroleum’s South Texas DAC hub and Battelle’s Project Cypress hub on the Louisiana Gulf Coast are slated to receive up to $1.2 billion of the IIJA funds. The projects also will be eligible to receive the IRA’s DAC tax credits of $180/ton for up to 10 years.
Occidental uses EOR extensively at its wells in Texas, according to the company website. However, during a Thursday press call, Kelly Cummins, deputy director of DOE’s Office of Clean Energy Demonstrations, said none of the carbon captured at the Texas or Louisiana hub will be used for EOR.
Rather, the CNS NOI positions the regional hubs as part of DOE’s efforts to build out a carbon management ecosystem. The NOI lists a dozen projects and prizes already announced and underway. Still, DOE notes, “The gap between the goals of CNS and the current commercial viability of some CDR technologies is substantial.”
The NOI “provides a strategy to coordinate funding opportunities that involve a variety of CDR pathways, technology readiness levels, and DOE offices and programs.”
To help build the market, DOE will use $35 million from the IIJA to underwrite carbon removal purchasing agreements, aimed in part at standardizing the credits produced by CDR. Microsoft and Climeworks recently signed a 10-year agreement for the DAC startup to capture and permanently sequester 10,000 tons of CO2 on behalf of the computer software giant.
Deich said the CDR purchase initiative is intended to “show how this tool can be scaled in the future and how it can drive innovation in the carbon removal space.”
The relatively small amount allocated to the program means it would have minimal impact on U.S. emissions, he said.
But standards are needed “in terms of what counts as carbon removal credits, how to actually go about measuring and verifying the carbon removal that … actually was delivered and stays delivered,” Deich said. “So, our aim in this program is to really help demonstrate what we think is best in class and hopefully crowd in a lot more private sector purchases in the near term.”
‘When Deployed Responsibly’
The Responsible Carbon Management Initiative is another effort to develop standards for DOE’s projects and the industry at large, and perhaps quell concerns and skepticism among some environmental groups, which continue to see carbon capture as a lifeline for the fossil fuel sector.
The Environmental Protection Agency’s proposed rule to use carbon capture and storage as a “best system for emission reduction” at fossil fuel power plants also received a mixed reception in comments from a range of industry stakeholders. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)
Echoing IEA, the NOI on the initiative states, “When deployed responsibly, [carbon management technologies] are complementary [to], and not a replacement for parallel efforts to reduce emissions.”
DOE sees the initiative as a two-phase program, first developing the Responsible Carbon Management Principles and getting companies to commit to them. In the second phase, “FECM would provide resources to support project developers seeking to meet the principles or other aspects of this effort … [and] focus on evaluation of principle implementation, accountability and leadership.”
The principles outlined in the NOI focus broadly on different aspects of community engagement, equity and transparency. For example, developers are called on to consider the cumulative impacts a carbon management project might have on the community where it is located. Developers also should evaluate and mitigate environmental impacts and “publish environmental impact analyses and project monitoring data in a way that is timely and easy for the public to access.”
If the initiative is successful, FECM could develop “a robust recognition program” to raise the public profile of industry leaders and promote responsible carbon management, the NOI says.
The NOI also includes a request for information asking industry stakeholders for feedback on both the initiative and principles. Questions include whether the principles “would be likely to meaningfully advance carbon management,” whether stakeholders would either commit to or endorse them and what changes should be made to improve chances of industry acceptance. The deadline for comments is Sept. 11.
PORTLAND, Ore. — Potential SPP Markets+ participants last week endorsed the first pieces of the day-ahead market’s tariff, acquiring a taste of the grid operator’s stakeholder process at the same time.
The core of that process is a focus on reaching consensus. It is ideally driven by stakeholders with SPP staff support, with a final agreement that satisfies a solid majority of members.
SPP Director Steve Wright, who chairs the three-person Interim Markets+ Independent Panel (IMIP) responsible for the market’s development, complimented the Markets+ Participant Executive Committee (MPEC) and its working groups and task forces for quickly adapting to the stakeholder process.
“I’m really impressed with the way that you’ve embraced democracy. Democracy can be messy, and it can be hard, but that’s what we’re doing here,” Wright said during the conclusion of the MPEC’s Aug. 8-9 meeting. “We love to see the participation; the way the voting structure is working; the way that motions create clarity around what it is that’s on the table, and then being able to move forward.”
John Cupparo, who along with fellow director Liz Moore fills out the IMIP, recalled the tariff discussion led by Bonneville Power Authority’s Russ Mantifel. Standing isolated in front of the MPEC for almost an hour and a half, Mantifel described how he was able to “flex the democratic muscle” — flexing his own muscles for emphasis — during workgroup discussions and gain confidence in the recommendations and motions that came forward.
“I thought it was a very important point in terms of the confidence that it gave him and hopefully that group in terms of how the process works and what we’re building,” Cupparo said. “I’m hopeful that that confidence propagates and continues to propagate among the workgroups.”
Cupparo also noted the workgroup updates that filled the agenda included “natural” references to SPP staff and the SPP Market Monitoring Unit.
“It suggests that there’s a growing partnership, which is very important in this process, not only now but for the future,” he said.
With CAISO having about an eight-year head start in developing a Western RTO, and a group of utility commissioners from the West calling for an independent grid based on CAISO’s operating framework, that partnership could be key for SPP’s plans to offer “RTO-light” services that include day-ahead and real-time unit commitment and dispatch. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.)
SPP plans to complete this second phase of Markets+’s development by filing a completed tariff with FERC early next year. The IMIP and MPEC are expected to sign off on the tariff language in December, with the RTO’s Board of Directors taking up a vote in January.
Wright reminded Markets+ stakeholders that once the tariff is filed, potential participants will have to decide whether to proceed with costly systems development or wait for FERC’s approval. He urged further discussion on that next step during the MPEC’s upcoming virtual and in-person meetings.
“The SPP staff needs this guidance because this is an allocation-of-resources issue. Folks have got to know what their work plans are going to look like, and so we need some sense of what the market participants are thinking,” he said. “I know there’s a bit of a chicken-and-egg issue here. It’s, ‘Well, I need to know for sure the tariff is proceeding before I’m prepared to commit dollars.’ On the other hand, if we wait until everything is final, then it will have a significant impact on the overall scheduling and the go-live date for a Markets+ market.”
MPEC Chair Laura Trolese, with The Energy Authority, said that while the program is on track, there is “some potential risk” of the schedule slipping over approval of the “boilerplate” tariff language.
“The working groups have been a little hesitant to approve boilerplate language,” she said. “There’s been quite a bit of education and level-setting and bringing everyone up to speed.”
Trolese said stakeholders have reaffirmed moving forward with the boilerplate language, with an understanding that the final tariff will include changes to accommodate issues unique to the West.
Carrie Simpson, SPP’s director of Western services development and MPEC’s staff secretary, pointed out that the boilerplate tariff language the stakeholder groups have started with is limited to principles and concepts outlined in the Markets+ service offering that participants agreed to last year.
“It’s the SPP existing market design, and the SPP market design is largely based on MISO’s market design, which is largely based on PJM’s market design. These are best practices,” she said.
The IMIP agreed with MPEC’s recommendation to delay the implementation of the price convergence financial product, or virtuals, by six months after the market goes live and with built-in circuit-breakers.
Virtuals are proposals to buy and/or sell energy at a settlement location for a specific time period in the day-ahead market. They were created to foster price convergence between the day-ahead and real-time markets and add liquidity. Settlements are based on the difference between the day-ahead and real-time price.
Stakeholders reasoned that virtuals, or the lack thereof, will not affect must-offer obligations. In addition, Markets+ boundary interface settlement locations are not eligible for virtuals. SPP will assess the settlement locations within a year of the virtuals becoming binding.
“My impression is that it was a rather robust conversation at the workgroup level, and it demonstrated that there’s differing points of views and there’s a way to get to a compromise or a consensus,” Cupparo told the MPEC. “That’s at the heart of what we do every day within the SPP way of life. That’s the model. That’s how it works.”
It was the only item the IMIP took up for consideration, saying it wanted to avoid interfering in the developmental work.
“There should be no sense of a signal that we have concerns about what’s going on. We’re trying to make sure that we’re not micromanaging you,” Cupparo told the MPEC.
The MPEC did endorse tariff language governing day-ahead and operating day activities, and LMPs and market clearing prices (MCPs). Committee members agreed a draft of language on scarcity pricing’s effect on LMPs and MCPs should be reviewed and brought back to the MPEC.
GHG Issue: ‘Emissions Leakage’
Clare Breidenich, who co-chairs the Markets+ Greenhouse Gas Task Force (MGHGTF), said the team is currently reviewing a draft and providing feedback on its tariff language, which is on track to be approved in October.
The task force’s primary objective is to develop a market solution, best practices, rules and protocols that support the Northwest’s only cap-and-trade program, that of Washington state, Breidenich told the MPEC.
“That program is already in place. Entities are incurring carbon obligations as of this year,” she said. “The live Markets+ would need to accommodate that program from the get-go.”
Labeled as cap-and-invest in Washington, the program began earlier this year with the Department of Ecology conducting the first two quarterly auctions. The department had to put up more than 1 million carbon allowances to help keep emitters’ costs in check after the May auction cleared at an unexpectedly high price ($56.10/allowance). (See Wash. Auctions Reserve Carbon Allowances to Relieve Price Pressure.)
Breidenich, who specializes in carbon policy, markets and regulations for the Western Power Trading Forum, said the task force is focusing on megawatt re-designation, or emissions leakage. This occurs when a change in market dispatch to accommodate the Washington program reduces emissions associated with generation serving load in the state but increases the market footprint’s emissions.
“The bulk of our work within the task force is trying to narrow down the definition of this problem to solve it,” she said.
The task force is evaluating the need for a multi-solve solution in the market-clearing engine and developing other options to minimize leakage, Breidenich said. The intention is to “identify what megawatts from what resources are eligible to be attributed to Washington state,” she said.
“Washington state is my bread and butter at this moment,” Breidenich said, noting that there is not perfect solution to the leakage problem.
“Anybody who has looked at this problem for any length of time realizes it pretty much is intractable. It is not caused by a deficiency in today’s market. It is not caused by a deficiency in the state program,” she said. “It is caused solely by the fact that you have a greenhouse gas pricing program in a limited geographic area with a much broader market footprint, full stop.”
“The only way you can fundamentally completely solve the leakage problem is if every jurisdiction within the market adopted a pricing program. We shouldn’t get too committed to the perfect solution because we won’t find it,” Breidenich added.
Trolese pointed out that with carbon allowances clearing at more than $60, it amounts to a $30 adder to a participant’s energy prices.
“It’s a significant impact to market dispatch … that adds to the complexity,” she said. “There’s no perfect solution, but every imperfect solution has some pretty serious impacts to the market and different market participants.”
Several other western states have adopted greenhouse gas-reduction targets or have clean energy programs that don’t rely on pricing elements in their dispatch. Most of these efforts have a 2030 target before they become binding, allowing the task force additional time to determine how to incorporate them into the tariff.
“We’ve heard very clearly from regulators and market participants in those states that these are important, and we need to think about how the market solution can address these programs,” Breidenich said. “We are starting that work, but it’s going to be in a longer time frame than meeting the pricing program details.”
The California Public Utilities Commission issued a decision Thursday adopting a settlement over the massive leak at the Aliso Canyon Natural Gas Storage Facility in 2015 that includes a $71 million penalty against Southern California Gas, the facility’s owner.
As part of the settlement, SoCalGas agreed it would not try to recover $485.5 million in costs related to the incident and it would refund more than $18 million to ratepayers. It also admitted to a violation of Public Utilities Code section 451, which requires public utilities to operate their facilities safely.
The CPUC’s decision approved an agreement between SoCalGas and the CPUC’s Safety and Enforcement Division and Public Advocates Office.
“The settlement agreement … is consistent with the record in that it includes an admission of a safety violation of section 451 for the totality of the Aliso Canyon incident, as well as a significant fine consistent with the magnitude and impacts of the violation,” it says.
CPUC President Alice Reynolds and administrative law judges Jessica Hecht and Marcelo Poirier drafted the decision.
Ratepayer advocates opposed the settlement as premature and possibly inadequate.
The proceeding against SoCalGas was initially “phased,” with “Phase 1 devoted to the number and nature of violations and Phase 2 covering costs, fines and penalties,” The Utility Reform Network (TURN) and the Southern California Generation Coalition (SCGC) noted.
Phase 2 was never litigated, and the settlement bypasses it, TURN and SCGC said.
“Under the settlement, all of the Phase 1 and Phase 2 issues will be resolved, with SoCalGas bearing $610 million in purported monetary remedies in exchange for an admission of a single violation of [the] Public Utilities Code,” they said.
“Despite the extensive litigation that has already occurred, the key discussion of costs assigned to Phase 2 has not yet occurred [and] the record is insufficient to determine that the monetary remedies identified are appropriate,” they said.
The settlement overstates the dollar value of the settlement because “in order for the commission to assess whether the proposed monetary remedies are a sufficient penalty for the conduct at hand, the commission must first assess whether the included dollars would have been appropriate to collect from ratepayers under any circumstances,” TURN and SCGC argued.
The CPUC decision agreed “that a disallowance of cost recovery cannot be considered equivalent to a penalty unless the foregone amount was likely to be recoverable from ratepayers” but said that “in this instance, the settlement agreement clearly protects ratepayers from the risk of litigating hundreds of millions of dollars of potential costs, some of which likely would have been found to be reimbursable by ratepayers.
“In principle, we agree with the opposing parties that the settlement motion may overstate the value of the settlement for ratepayers; nevertheless, we find that SoCalGas’s agreement to forego cost recovery provides some (perhaps non-quantifiable but still real) ratepayer value,” the decision says.
The decision adopting the settlement, known as a presiding officer’s decision, takes effect after 30 days unless a party appeals it or a commissioner requests a public review.
“In case of an appeal or request for review, administrative law judges will assess and potentially modify the decision before presenting it to the commissioners for voting during a public session,” the CPUC said. “Commissioners may also offer an alternate decision for consideration.”
Proposal to Replace
In a separate proceeding, the CPUC has proposed replacing Aliso Canyon, the state’s largest natural gas storage facility, with a combination of non-gas-fired generation, building electrification, energy efficiency and storage. (See California PUC Proposes Aliso Canyon Endgame.)
The facility’s fate has been controversial since a ruptured pipe at the SS-25 well poured more than 100,000 tons of natural gas into the air, leading to a blowout and sickening nearby residents. The leak was contained after four months in February 2016.
After the gas leak, the facility reopened at reduced capacity in July 2017, but in November 2021, the CPUC increased its storage limits by 7 billion cubic feet (Bcf) to just over 41 billion Bcf amid concerns about winter gas supply. At the time, it rejected a plan to increase the allowable storage to 69 Bcf. (See CPUC Approves More Gas at Aliso Canyon.)
On July 28, the CPUC issued a proposed decision that would increase the maximum storage level allowed at Aliso Canyon from 41 billion cubic feet to 69 Bcf “on an interim basis to help secure energy reliability and protect against high natural gas and electric prices.”
The proposal is scheduled to be taken up at the CPUC’s Aug. 31 voting meeting.
VALLEY FORGE, Pa. — The PJM Market Implementation Committee voted to endorse one of several packages to flesh out the rules around loads seeking to receive their power from behind the meter of a generator. (See “Vote on Rules for Generation with Co-located Load Deferred,” PJM MIC Briefs: July 12, 2023.)
A 51.2% majority of stakeholders supported Exelon’s proposal for co-located loads not considered to be receiving service from the wholesale grid, passing over three competing proposals. None of the four proposals for co-located loads receiving grid service received majority support.
The Exelon proposal would permit a generator to retain its capacity interconnection rights (CIRs) for the share of its output supplied to the co-located load, so long as that load curtails within 10 minutes of PJM calling on the generator to supply that capacity to the grid.
For co-located configurations to be considered to not be receiving grid service, they would need to be designed to ensure that they’re exclusively supplied by the corresponding generator and disconnected whenever they’re not being served by the generator.
The proposal would consider the generator to be a load-serving entity for the co-located load and levy all relevant load-serving entity (LSE) credits and charges.
The approach of allowing co-located load to not be considered receiving grid service — but assigning some of the charges a wholesale customer would be assessed to the generator — has raised stakeholder questions, with some arguing it could muddy the waters of state and federal jurisdiction.
PJM’s Tim Horger said the current rules for generators receiving grid service remain unclear without a package approved addressing those configurations, and he plans to examine the Exelon package for ways to discuss additional changes.
“I think we probably still want to do that, but we also want to take into account the Exelon package that was approved,” he said. “To be clear, we do have rules in place now and we are following them.”
Lynn Horning, of American Municipal Power (AMP), said any approach PJM plans to take on co-located load with grid service should be clear when stakeholders make their final endorsement vote on the Exelon package.
MIC Rejects Reactive Power Compensation Proposals
Stakeholders rejected four proposals to revise the compensation structure for generators providing reactive power service and voted to sunset the Reactive Power Compensation Task Force (RPCTF). Generator owners are required to submit a FERC filing for each facility providing the service to receive compensation, which creates administrative burden and lacks a standardized approach. (See “First Read on Reactive Power Compensation Proposals,” PJM MIC Briefs: July 12, 2023.)
The clean energy coalition (CEC) proposal, formed by a group of renewable developers, received the most support at 62.2% when compared to the other three packages. But it didn’t hold onto that support when compared to the status quo and failed to pass at 44.3% support.
The CEC package would create a cost-of-service structure with a flat rate based on the methodology FERC uses to evaluate reactive filings and would require testing to validate that generators receiving compensation are able to provide the service.
The PJM proposal would have determined each generator’s reactive capability, measured in MVAR, and compensated them monthly. Synchronous and storage resources would have been compensated based on their availability in the prior month.
The Independent Market Monitor made two proposals, the first of which would have eliminated compensation outside of existing markets on the basis that all generators are required to provide reactive service as part of their interconnection service agreement (ISA).
The Monitor’s second would have used a flat rate structure based on demonstrated capability, similar to PJM’s proposal, but would have phased out compensation.
The proposals would have affected only new generators or facilities entering new compensation agreements, with the task force’s scope precluding changing existing reactive rates. The MIC voted down a proposal to expand the task force’s scope to include existing service rates last month. (See “Stakeholders Reject Proposal to Expand Reactive Power Task Force Scope,” PJM MIC Briefs: June 7, 2023.)
Danielle Croop, facilitator for PJM’s Reactor Power Compensation Task Force, said in the absence of a main motion to move to the Markets and Reliability Committee, stakeholders could decide to continue deliberations at the task force, move discussion to the MIC or sunset the task force and close the issue.
David “Scarp” Scarpignato, of Calpine, said it’s significant that none of the proposals gained support over the reigning rules and given that the task force began its work two years ago it’s unlikely more discussion would yield new proposals.
“It doesn’t look to me like it’s a good idea to go back to the task force. I don’t think it’s a matter of whittling down the existing proposals to better proposals, I think people like the status quo,” he said.
Scarp motioned to sunset the task force, which was approved by acclamation without objection.
First Reads on Proposals Addressing Multi-schedule Modeling in MCE
Package sponsors gave first reads of three proposals aimed at addressing the expected performance impact of implementing multi-schedule modeling in the rebuild of the market clearing engine (MCE). (See “Merged IMM-PJM Issue Charge on Multi-schedule Modeling Endorsed,” PJM MIC Briefs: March 8, 2023.)
The discussion stems from a finding that introducing the enhanced combined cycle (ECC) model and energy storage resource (ESR) and hybrid model into the Next Generation Markets (nGEM) overhaul of the engine would cause the amount of time it takes for PJM to determine what resources will clear in the day ahead market to become impractical.
For combined cycle generators, the number of different configurations they can operate in, with varying numbers of turbines paired with heat recovery steam generators (HRSGs) and multiple offers for each configuration, multi-schedule modeling could lead to an exponential increase in MCE computation times.
PJM’s Package A would address the issue by creating a formula that would select one offer resulting in the lowest total dispatch cost to be modeled in the MCE.
PJM’s Keyur Patel said the schedule selection built into the MCE is the most optimal approach, but he does not see any way of getting the benefits of including the new models into the engine without some compromises. A joint PJM and GT Power proposal would use the Package A approach, but consider only cost-based offers for resources that fail the three-pivotal-supplier (TPS) test. Price-based offers would be used for resources that pass the test, aside from price-based parameter-limited schedule (PLS) offers being used for capacity resources under emergency conditions.
The Monitor’s proposals could combine the lowest offer points and most flexible parameters from resources price and cost based offers under certain scenarios, impose offer capping and parameter limits to all resources that fail the TPS test and apply parameter limits to capacity resources during emergencies.
Deputy Monitor Catherine Tyler said there are market power concerns in the MCE which allow resources to inflate LMPs by using high markups and to extract uplift using inflexible parameters, both of which would be made worse by PJM’s proposal. She said that parameters other than minimum run time aren’t considered under PJM’s approach.
Endorsement of the proposals is scheduled for the Sept. 6 MIC meeting. Customized Energy Solutions’ Carl Johnson said deciding between the packages likely will remain difficult for stakeholders who aren’t as familiar with offer structures.
“For those of us who aren’t really in the weeds on this, this is a really difficult choice to make,” he said.
Voltus presented an issue charge and problem statement making the case that demand response resources lack the parameters other generators can include in their offers, limiting the consumers able to participate as an economic resource.
David Aitoro, of Voltus, said DR now can be dispatched for a single five-minute interval, then be curtailed only to be called on again in the third interval. For many DR participants, that may not match their curtailment capabilities and is not in line with parameters other generation resources can include in their offers, he said.
He also argued that many consumers who could curtail air conditioning systems could do so for one to three hours without a major impact to building temperatures, but there’s no capability to structure an offer to reflect that.
“It’s really DR that’s getting left out in the cold here,” Aitoro said.
Several stakeholders discussed the scope of the issue charge and how economic DR in the energy market relates to DR entering the capacity market. Aitoro said Voltus’ intent is to focus on the energy market, which could include resources that also offer into the capacity market.
PJM’s Peter Langbein said there’s around 8 GW of DR in the capacity market with corresponding energy market offers, most of which are in excess of $1,000/MWh. Economic DR also can offer separate energy-only offers, with about 2 GW doing so.
Scarpignato said generators are required to enter their most flexible parameters in their offers and those Voltus is seeking to include appear to reflect desires rather than true capability.
Exelon’s Alex Stern noted that discussion held at the Distributed Resources Subcommittee (DISRS) on the issue charge and problem statement was raised during the July MIC meeting, with stakeholders questioning if the topic fit into the group’s scope or if it should be discussed elsewhere. (See “Stakeholders Question Scope of Distributed Resources Subcommittee,” PJM MIC Briefs: July 12, 2023.)
MIC Facilitator Foluso Afelumo said the scope and proper group to host the discussion are the primary issues to be ironed out before a vote.
Stakeholders Discuss Proposals to Include Local Factors in Net CONE
Paul Sotkiewicz, president of E-Cubed Policy Associates, presented a second proposal to create rules for incorporating local considerations that could impact generators’ net cost of new entry (CONE), such as local or state regulations or legislation. (See “Discussion on Local Considerations for Net CONE,” PJM MIC Briefs: March 8, 2023.)
The package would create a fifth CONE area for the Commonwealth Edison region, which Sotkiewicz has argued will see significant impacts to generator lifespans under the Illinois Climate and Equitable Jobs Act (CEJA). PJM also automatically would create new CONE areas for any regions where new local factors cause a reduction in asset lifespan or set emissions limits that “imply a reference resource with different technology” than the current resource net CONE is based on.
Sotkiewicz said the proposal would capture the potential for hydrogen fuel blending or carbon sequestration requirements to increase operating and maintenance costs or introduce issues with the asset life.
If the reference resource were to remain a combined cycle generator at a point when those resources are being required to blend hydrogen, he said there would be a need to incorporate that in the energy and ancillary services (E&AS) offset and update its asset lifespan more regularly.
The PJM package would also create a fifth CONE area for the ComEd region but does not create any provisions for the future addition of new areas.
FERC on Thursday approved NERC’s plan for funding the interregional power transfer capability study ordered by Congress in June, which will require the ERO to redirect 2023 budget funds intended for other purposes and tap its Assessment Stabilization Reserve (ASR) (RR22-4).
NERC submitted the plan to the commission in June, shortly after its Finance and Audit Committee approved the plan in a special meeting. (See NERC FAC Approves Transfer Study Funding.) The proposal was developed after Congress ordered the study as part of the Fiscal Responsibility Act, passed in June.
The FRA requires NERC to deliver to FERC by December 2024 a study on the total transfer capability between neighboring regions, additions to transfer capability that could strengthen grid reliability and recommendations to meet and maintain total transfer capability. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.)
NERC calculated it would require $1.55 million in funds not accounted for in its budget because it did not know about the requirement to perform the study when it created its 2023 business plan. To accomplish this, the ERO decided to reprioritize its 2023 work plan to free up cash. The effort included deferring several projects planned for this year, along with the ERO’s intentions to fill three open positions in bulk power system awareness, engineering and security, and standards.
After these steps, NERC determined it still would need to draw $700,000 from the ASR to avoid a special assessment. In its filing to FERC, NERC described the use of the ASR — which is funded only by U.S. entities — as fitting because the U.S. federal government mandated the study without input from Canada’s government.
In its decision last week, the commission said it found NERC had “provided sufficient information to justify” its proposal to tap the ASR. No motions to intervene or protests were filed with FERC, and the commission indicated no disagreement with NERC’s reasoning.
FERC did, however, take issue with the ERO’s reason for filing the budget request. While NERC only asked permission to use the ASR, the commission observed that the ERO is required to seek the commission’s approval for any change in how it uses budget. This meant, in FERC’s eyes, that NERC’s proposal as submitted was incomplete.
Despite this mild rebuke, the commission acknowledged that NERC had justified the reallocation anyway, and “because we understand the importance of expediency in this matter,” FERC said it would approve both parts of the plan without requiring another filing from the ERO.
The commission’s approval means NERC officially can begin work on Phase 1 of the study. A NERC spokesperson told ERO Insider that staff expects to start this phase — which includes identifying areas of surplus and deficient generation; performing the transfer capability analysis; and identifying thermal, voltage and stability limits — on Aug. 15.
FERC’s decision accounts for only the 2023 expenditures; paying for the work to be done next year requires revising NERC’s 2024 business plan and budget, a draft of which the ERO already had completed before Congress passed the FRA. NERC’s Board of Trustees and board committees will meet this week in Ottawa to consider the revised budget.
According to the FAC’s agenda, the study is projected to cost $3 million next year. NERC plans to pay $400,000 of this with “repurposed contractor and consultant funds,” leaving a total budget increase of $2.6 million. This cost will be split evenly between the ASR and the Operating Contingency Reserve.
VALLEY FORGE, Pa. — The PJM Planning Committee last week endorsed the load model recommended by the RTO for calculating the load forecast for the 2023 reserve requirement study (RRS).
The selected distribution, derived from data from 2013 through 2019, has a more conservative estimation of future loads than the model used in the 2022 study, with loads being higher in most percentiles.
The study will set the installed reserve margin and forecast pool requirement for the 2027/28 delivery year and inform any modifications to the previous three years’ values.
Alongside the Probabilistic Reliability Index Study Model (PRISM) program, PJM will use software developed for the hourly loss-of-load modeling used for effective load-carrying capability (ELCC) studies in this year’s RRS. PJM says the ELCC software has the potential to produce better results and will generate two sets of data, which will be presented to stakeholders when the study is complete for endorsement of one set of outcomes. (See “Reliability Requirement Study to Use New Software,” PJM PC/TEAC Briefs: May. 9, 2023.)
The load model selection process is required only for the PRISM software, which requires normal distributions of data, whereas the PJM forecast data are empirical. The ELCC process models the monthly peak load uncertainty by deriving load scenarios and frequency weight for each delivery year between 2012 and 2021.
The top three performing load models all project PJM’s peak overlapping with the peak for the “World,” defined as MISO, NYISO, TVA and VACAR. The RTO recommends the World peak be moved to a different week in July to avoid the overlap, which historically it has found unlikely and would lead to a decreased capacity benefit of ties (CBOT) value.
PJM’s Patricio Rocha Garrido said in the past 24 years, the World and PJM have not peaked on the same day in just over half those years. The PRISM software used to conduct the load model analysis treats each day as a five-day week, which would compound the impact a coincident peak would have in the data.
PJM Presents Preliminary Capital Budget
PJM presented a $44 million capital budget to stakeholders, a $2 million increase over the amount it projects to spend in the 2023 fiscal year. The preliminary budget is dominated by the cost of current applications and systems reliability, facilities and technology infrastructure and application replacements.
Though the $44 million ask is an increase over recent years, PJM’s James Snow said the RTO remains within the $45 million range it expected to spend.
Spending on applications makes up nearly half the budget at $21 million, which includes upgrades to PJM’s Dispatcher Application and Reporting Tool (eDART) system, improvements to credit or risk applications and cybersecurity. Facilities and technology spending would sit at $11 million and include replacement of backup generators at the control center and server upgrades.
The $8 million in proposed application replacements includes spending on the Next Generation Markets Systems (nGEM) project being undertaken with several other RTOs to build a new market clearing engine and related software.
Spending on new products and services would be $3 million, while $1 million would be spent on interregional coordination.
Migration of eDART Accounts to New Platform Underway
PJM began the process of working with members to transition from managing their accounts through eDART to its Account Manager software. The migration of the 7,443 accounts in eDART started on July 25 and will continue through Dec. 13.
PJM’s Maria Baptiste recommended users begin transitioning as quickly as possible to give themselves time to work through any issues that may arise. The Account Manager dashboard can be used to create new user accounts, reset passwords, unlock accounts and grant or terminate eDART account access.
Transmission Expansion Advisory Committee
AEP Proposes $202 Million Rebuild of 345-kV Line
American Electric Power proposed rebuilding its 51.8-mile, 345-kV Desoto-Sorenson line, telling the Transmission Expansion Advisory Committee last week the majority of the lattice structures and conductor on the line are more than 70 years old. The utility proposed rebuilding the line in a double-circuit configuration at a $202.4 million cost, including new structure entrances at the Sorenson, Keystone and Desoto substations.
The line has experienced 22 momentary outages and 12 permanent outages since 2014. AEP has found that the paper-expanded conductor installed on it is difficult to splice during repairs because of limited replacement materials.
AEP also evaluated rebuilding the line as a single circuit, but it determined that because of the number of generators seeking to interconnect on both sides of the line, as well as its status as the only transmission connecting the Fort Wayne grid to the 345-kV Tanners Creek hub, a double circuit would be more appropriate. The cost of a single circuit rebuild was estimated at $187.4 million.
FirstEnergy Presents Data Center Interconnection Projects
FirstEnergy proposed $27 million in upgrades to meet a projected 336 MW in data center load growth near its proposed 230-kV Sage substation.
The proposal includes a $1.5 million expansion of the substation, including installing three additional 230-kV circuit breakers, two new transformers and two 34.5-kV buses. The 138-kV Bartonville-Meadow Brook line also would be upgraded with an additional wave trap and revised relay settings for $700,000.
The third phase of the project, estimated at $25 million, would add nine additional breakers to the substation, bringing the total to 15, and terminate the 230-kV Doubs-Eastalco line at Sage. The substation also would be looped into the 230-kV Doubs-Lime Kiln line.
PJM’s Sami Abdulsalam said the data center load was identified in the 2022 Regional Transmission Expansion Plan (RTEP) Window 3, which is in the proposal selection phase, and the proposal addresses the interconnection requirements for the load.
Philip Sussler, of the Maryland Office of People’s Counsel, asked if there was any transmission headroom available from the deactivation of the Eastalco Aluminum plant, which used about 300 MW prior to its retirement in 2010.
FirstEnergy’s Larre Hozempa said some of that transmission capability has been consumed by load growth over the intervening decade and the new data center load is expected to be significantly larger than the plant’s. The load included in Window 3 was about 1,300 MW, with 900 MW already under contract.
Update on RTEP Windows
Abdulsalam also presented an update on the 2022 RTEP Window 3 and the first window of the 2023 RTEP, which opened on July 24 and is set to close Sept. 25. (See “2023 RTEP Window 1 to Open this Month; 2022 RTEP Window 3 Selections in September,” PJM PC/TEAC Briefs: July 11, 2023.)
Window 3 closed on May 31 after receiving 72 proposals from 10 entities, and PJM has completed the individual proposal screening and planning evaluation steps. It now is conducting proposal scenario evaluations. In developing and analyzing dozens of scenarios, PJM looks at the full proposals made and modifications to them, and combines elements to create mix-and-matched variants.
Abdulsalam said the window had an atypically low rate of cost-containment commitments, signaling that developers believe there is higher risk associated with the projects and it may be harder to ensure cost estimates remain accurate.
Ranking of the scenarios will include scalability to address future needs, use of existing rights of way, cost evaluation and avoiding redundant capital investment. Abdulsalam said part of the analysis will include looking at other proposed projects outside the window and evaluating if they can be modified or synergized with the RTEP to reduce costs. He said the $786 million in transmission upgrades associated with the deactivation of the 1,295-MW Brandon Shores coal generator near Baltimore is one such project.
Some of the proposals that were focused on addressing the 2027 model needs do not appear to be expandable to address needs expected in the following year, Abdulsalam said. Analysis of the 2028 model also shows more grid reinforcements needed in the eastern and southern Dominion regions.
PJM is aiming to hold a special TEAC meeting in October to present the window evaluation results, followed by asking the Board of Managers for approval in December.
Stakeholders Endorse Manual Changes Related to NERC Winter Readiness
The Operating Committee voted during its Aug. 10 meeting to endorse manual revisions to conform with essential actions NERC included in a May cold weather readiness alert.
PJM’s Donnie Bielak said the changes to Manual 13 are essentially verbatim from NERC’s language and focus on ensuring that infrastructure used for manual load shedding doesn’t overlap with equipment designated for use in underfrequency or undervoltage load shed. The manual changes are slated to go before the Markets and Reliability Committee during its Aug. 24 meeting.
The NERC alert includes eight actions for asset owners and RTOs to take to increase readiness for winter storms. The additional actions include: identifying generators capable of operating at the lowest hourly temperature seen at their locations since 2000; updating balancing authorities’ operating plans to account for fuel supply, environmental constraints and availability; and generation owners detailing each facility’s cold weather preparedness plan, cold weather critical components and any freeze protection measures that have been implemented on those components prior to the upcoming winter.
Stakeholders encouraged PJM to talk with generation owners about the NERC alert actions that apply to them and their responsibilities.
PJM Proposes Synchronized Reserve Deployment Language
PJM brought a quick-fix issue change, problem statement and a proposal to specify that generators should respond to synchronized reserve deployments immediately after receiving an Inter-Control Center Communications Protocol (ICCP) signal or an all-call message. Bielak said outreach to generators about poor reserve response rate has found that many wait until they receive the all-call message even after receiving the ICCP.
“You don’t need to wait for that all-call, if you get that ICCP to spin, start deploying your reserves,” he said. “The all-call should be more of a confirmation. … It is an older technology.”
The all-call is an automated phone message that can take a few minutes to reach all generators, Bielak said, while the ICCP signal can be transmitted nearly instantly following a reserve deployment.
Reserve performance has been a concern since the response rate declined following an overhaul of the reserve market implemented Oct. 1, 2022. During the July MRC meeting, PJM brought an issue charge and problem statement seeking to open a broader stakeholder process, including the creation of a task force, to investigate several issues and possible solutions related to reserves. (See “PJM Seeks Stakeholder Process on Reserve Certainty,” PJM MRC/MC Briefs: July 26, 2023.)
July Sees Several Days of High Load Forecast Error
Load forecast error exceeded PJM’s 3% goal for several days in July, which PJM attributed to inaccurate weather forecasts. Delivering the operating metrics report, PJM’s Hong Chen said the 3% figure is an internal goal to measure forecasts against.
PJM overforecast loads July 25-29, when Bielak said a heat wave was expected to bring peaks around 152 to 154 GW. Unexpected thunderstorms contributed to temperatures coming in lower than forecasted, leading to a peak of 147 GW on July 27.
“We had up to 10, 15 degrees weather forecast error and that was consistent across the board from all our vendors,” PJM’s Joseph Mulhern said.
PJM’s analysis of the forecast during the heat wave suggests the error came down to weather, rather than load forecast error.
Stakeholders asked PJM to include a narrative explanation and any backcast analyses in future operating metrics reports when forecast error is high.
Bielak said loads were on track to near an “all-time peak” in the last week of July, but the loads didn’t materialize. PJM issued hot weather alerts for the entire RTO on July 26 through 28 and issued a maximum generation alert on July 27 and 28, triggering a NERC Energy Emergency Alert (EEA) Level 1. The hot weather alerts also defer transmission outages.
PJM issued a maintenance outage recall for the event and had good response from the resources that were offline, which was a small number given it being “peak season,” Bielak said. Both generation and transmission performed well through the event, he said.
PJM Proposes Manual Revisions Related to Communication Failures
PJM’s Ryan Nice presented proposed revisions to Manual 1, which relates to the control center and data exchange requirements, drafted through the document’s periodic review. The changes detail when transmission owners must notify PJM that interpersonal communication capabilities have been disrupted.
The new language specifies that communication can include several forms of contact, including cell phones, satellite or radio, and that a notification of failure has to be made only when all modes have failed.
PJM Brings Quick Fix Issue on Data Sharing
PJM presented a quick fix issue charge, problem statement and proposed manual changes to create a carve out from the requirement that PJM provide five days’ notice before providing confidential information to NERC, reliability coordinators, transmission operators and similar groups.
The problem statement says PJM regularly provides such information and has found the notification requirement can be inefficient and burdensome in certain instances. The proposed manual language would create an exception for data transmitted during a NERC audit or investigation into whether PJM is in compliance with reliability standards and when using tools created by regional entities, such as NERC’s Generator Availability Data System (GADS).
PJM Details Cybersecurity Threats
PJM Chief Information Security Officer Steve McElwee said new cybersecurity threats are rising, including the use of artificial intelligence to create targeted messages designed to trick targets into divulging sensitive information and groups ransoming data.
An offshoot of the language learning model ChatGPT has been created to bypass safeguards preventing the model from being used to create “phishing” emails aimed at stealing information, and McElwee highlighted recent Congressional testimony about the threat Chinese artificial intelligence advancements present the American electric industry.
McElwee said a “critical infrastructure company” has been targeted by an exploit found in the software Citrix, which allowed data to be collected on targeted systems. The Cybersecurity and Infrastructure Security Agency (CISA) has released an advisory recommending that Citrix users evaluate their systems for potential compromise and apply patches released by the developer to resolve the issue.
Critical Load Verification Process to Begin Shortly
PJM is preparing to initiate the critical load verification step in its black start request for proposal process. Starting in late August or early September, generators will be required to validate the amount of existing critical load they possess or submit data for new generators.
PJM’s Dan Bennett said critical loads are the components that will require power from the grid to restart a generator as black start resources “crank” the grid after a blackout. The restoration process focuses on generators with a start time of four hours or less. He said critical load includes equipment such as electric gas compressors and nuclear units’ shutdown, safety and cooling systems.
The parameters PJM will be looking for includes the energy requirements of the critical load, motor sizing and transformer parameters. The analysis also will look at the cranking paths to ensure the transmission grid can route power from black start units to generators being restarted.
PJM and IMM Plan Joint Filing on Real Time Values
PJM and the Independent Market Monitor plan to make a joint filing asking that FERC act on its real time values proposal made in July 2021. The filing was made in the commission’s pending order to show cause stemming from a concern that PJM’s tariff may not be just and reasonable due to uncertainty around what happens if a generator cannot meet its unit-specific parameters in real time (EL21-78).
PJM’s Lauren Strella Wahba said PJM’s proposal would allow real time values to be submitted only for actual physical unit limitations or those outside management control. Real time values would be required to be submitted after the close of the day ahead market.
The order to show cause stated that PJM’s tariff may allow generators to avoid market power mitigation by submitting offers that increase the likelihood of market-based, rather than parameter-limited, offers are selected. (See FERC Issues Show Cause Order on PJM Parameter Limited Offers.)
“Sellers may be able to structure their market-based parameter-limited offer strategically to ensure that PJM chooses the market-based offer, which is not subject to parameter limits,” the commission said. “This undermines the purpose of parameter-limited offers, which is to ensure sellers are not able to exercise market power through the use of inflexible operating parameters.”
The order to show cause came after the commission rejected PJM’s proposal to allow sellers to change their unit-specific parameter limits in real time in May 2021.
New Mexico regulators have launched a process to develop “guiding principles” regarding participation in a regional day-ahead market or RTO.
The Public Regulation Commission on Thursday voted 3-0 to approve an initial order opening a docket on the matter and scheduling a workshop at 2:30 p.m. Sept. 21.
The docket will be used to investigate factors that two investor-owned utilities in the state, Public Service Company of New Mexico (PNM) and El Paso Electric (EPE), should consider when deciding whether to enter an RTO or day-ahead market. Both utilities currently participate in CAISO’s Western Energy Imbalance Market.
Following one or more informal workshops, the PRC may opt to begin a formal rulemaking process.
Commissioner Patrick O’Connell called the order “a good step forward on a very important topic.”
“This is not a trivial thing,” O’Connell said. “I think there is a lot of potential value for our customers. Getting it right is where the work is.”
The commission also gave a homework assignment to PNM and EPE in the form of questions to answer in writing on RTO and day-ahead market issues. The utilities will present their answers during the workshop.
The questions are organized under 14 topics. On the topic of reliability, the commission wants to know whether system reliability is improved by regional market participation and how a utility’s responsibility for local reliability might change.
Two questions fall under the topic of transmission. The commission has asked if participation in a day-ahead market would improve the transmission system for New Mexicans and how that would compare to joining a full RTO. A second question asks whether the regional market should require participating transmission providers to make all their capacity available to the market and what exceptions should be made.
Under the topic of market transparency and performance, the utilities will discuss the types of data that would be provided to the commission and the public to assess market performance.
On another topic, the utilities were asked to describe the impact of joining either CAISO’s Extended Day-Ahead Market or SPP’s Markets+ on “seams.”
Another question is how rural electric cooperatives can participate in the market.
With dozens of questions for the utilities to answer, the commission could decide that a series of workshops is needed, rather than a single session.
The PRC also has asked Southwestern Public Service (SPS), which is a member of SPP, to submit written comments about benefits or impacts to ratepayers resulting from RTO participation.
Other stakeholders are encouraged to participate in the process.
“Stakeholders’ comments here about what they expect to get out of regional markets will be very valuable as we try to develop the guidance principles and expectations,” Commissioner Gabriel Aguilera said.
New Mexico’s effort comes just as competition is heating up between CAISO and SPP over their respective efforts to bring day-ahead markets to the West, which likely would be a precursor to a full RTO. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.)
GRAND RAPIDS, Mich. — The annual Mid-America Regulatory Conference (MARC) Aug. 6-9 again centered on the clean energy conversion and transmission expansion, this time with an undercurrent of equity.
MARC’s 2023 conference, “Grand Vision: Past, Present, Future” originally was planned for late spring 2020 but was derailed by the pandemic until Aug. 6-9.
“It’s a conference more than four years in the making,” Michigan Public Service Commission Chair Dan Scripps said, welcoming regulators, utility representatives and “Barbies, Kens and even Allans” to the conference.
Equity Takes Center Stage
Multiple Indiana and Michigan-based grassroots equity and climate activist groups attended MARC this year, pressing regulators and utility representatives to decarbonize faster while addressing longstanding disparities in the grid’s design.
Wisconsin PSC Chair Rebecca Cameron Valcq said the energy transition affords the industry “a once-in-a-generation opportunity and responsibility” to include vulnerable communities in environmental justice. She said those communities have good reason to distrust the systems in place and have been neglected “for hundreds of years.”
Regulatory initiatives often are “dense and obtuse,” Cameron Valcq said, making an informed and participating public an uphill battle. She said “there’s more work to be done” in ensuring the public know where and when to comment.
Becca Jones-Albertus, director of the Solar Energy Technologies Office at the U.S. Department of Energy, said an “unevenly distributed” transition is underway, where some parts of the country already have rapidly transformed while other parts have little idea of what’s in store for them.
Jones-Albertus said over the next few years, she expects 5-10% of power consumed to originate on the distribution system.
“We’re at a fork in the road,” said Jeffrey Schlegelmilch, director of the National Center for Disaster Preparedness at Columbia Law School. He said the industry can either view the transition through the “lens of equity” and extend the benefits of innovation to all, or it can exclusively lavish investments on wealthier areas, forcing poorer Americans to pay more for power, be neglected from environmental redress and continue bearing the brunt of reliability breaches and dangerous weather.
Schlegelmilch said societal and economic costs will be much lower if the industry brings everyone along on the clean energy overhaul. He said he’s performed analyses where the medical costs of exacerbated health conditions and the “cascading impacts” of those costs alone make replacing a fossil fuel generator with a battery storage facility cost-effective in communities. But he also said that raises the question of who ultimately pays for action versus inaction.
Midwest Building Decarbonization Coalition’s Marnese Jackson said historic racism, capitalism and a single-minded drive for corporate profit is making a truly equitable decarbonization increasingly unattainable. She called for an emphasis on shifting away from “dirty” natural gas as soon as possible.
Consumers Energy CEO Garrick Rochow said equity and environmental justice can be baked into the energy transformation. He said he believes carbon capture will factor heavily into the clean conversion, and natural gas generation will “fill in the gaps” and then “diminish.” Rochow said once the grid is sufficiently greened, green hydrogen can enter the conversation.
Rochow also said Consumers has conducted unconscious bias analyses in its outage restorations and grid investments practices, something it “should have done 20 years ago.”
“What we’ve found is we’re investing more in our most vulnerable customers because the grid is in worse shape in those areas,” he said.
In a session on planning a just transition for power plant communities, Hilary Scott-Ogunrinde, deputy director of energy and utility at the Illinois Department of Commerce and Economic Activity, said the state is trying to “rectify the wrongs of the past” through the Climate and Equitable Jobs Act (CEJA).
She asked the audience to guess how many coal plants have closed in Illinois in the past decade. After speculations ranging from five to 20, she said the number is 11.
Scott-Ogunrinde said after the rash of closures, Illinois passed CEJA, which contains grants for coal-to-solar facility changeovers, both for underprivileged individuals seeking to invest in renewable development and for communities transitioning from coal, nuclear, natural gas or mining operations.
Larry Steckelberg, an administrator of community services at the Michigan Department of Treasury, said Windsor, Ontario’s twinkling lights across the Detroit River are in stark contrast to Detroit’s lack of recreational waterfront, brownfield sites, abandoned factories and shuttered coal plants. He said River Rouge, Mich., the former site of heavy industry and DTE Energy’s River Rouge coal plant, which closed in 2021, is one of the most polluted sites in Michigan and will take several years of remediation until people are enticed to move there.
Steckelberg said revitalizing a former coal plant city is a long-term project, often taking 15-20 years, with cities “swept up in global events” out of their control. He said he personally couldn’t predict how fast coal would fall out of fashion globally.
Steckelberg said the town of Covert, Mich., was unprepared for the closure of the Palisades nuclear plant, even though indications were clear. He urged communities to diversify energy sources and not “just become a site” for solar panels because it’s the trendy resource now. But he acknowledged that the list of federal resources and the requirements can be “bewildering” for some communities.
“Putting in layers of bureaucracy does not get the help that people need,” Scott-Ogunrinde agreed. “…If we’re going to have the money available, then have the money available. Because the people filling out the forms, they need it. Even if they don’t have 20 pages of documentation.”
EPA Senior Adviser Jon Grosshans said historically the U.S. has supported communities suffering manufacturing losses, but it hasn’t provided backing for communities that transition from coal plants.
Grosshans said the federal government is seeking to create a “front door” for financial resources for transitioning communities.
“Sitting around in 2019, it was pretty obvious to us that this was going to be a decade of closing more coal and bringing on more renewables,” said Emily Fisher, Edison Electric Institute executive vice president of clean energy.
Fisher said EEI quickly realized that net-zero plans would need to incorporate dispatchable technologies with the assistance of carbon capture, green hydrogen and long-duration storage.
“No company has released a plan that hasn’t carefully thought this through,” she said.
But Fisher said it became apparent over the past few years that “maybe this decade isn’t going to be as easy as we thought it was going to be,” referring to how difficult it remains for new generation to clear interconnection queues and receive grid treatment.
Fisher also said post-pandemic, utilities have become more acutely aware of affordability. She said when utilities raise concerns about customer affordability, it’s often perceived as utilities trying to stall the clean energy transition. But she said utilities are justified in their concern whether costs can be recovered from ratepayers.
“Solar seemed unreachable from an economics standpoint about 10 years ago. What seemed impossible a decade ago has become very, very possible,” Norcia said.
Norcia also said he’s optimistic about green hydrogen and predicted the technology will improve, and costs will plummet so that what seemed insurmountable will become achievable.
Norcia also said DTE’s service territory has begun to see “violent storms… and weather patterns that were reserved for states south of us,” upping the pressure to make infrastructure investments for the sake of reliability. He said the climate crisis and growing demand for electrification means utilities need to “build the grid out slightly ahead of time.” He also said worsening weather means utilities need to seriously consider “how to get stuff underground,” indicating burying lines.
“That’s something we’re going to start experimenting with and seeing how we can get the costs down,” he said.
Google Global Head of Energy Caroline Golin said Google is conscious it demands a lot of electricity and wants to accelerate the switch to carbon-free sources. She said Google is focused on how to partner with suppliers on pilot projects for green hydrogen, long-duration storage and carbon capture.
“I can tell you this [carbon-free] growth is coming, it’s coming now, it’s coming fast. We wanted it yesterday. …We will not grow somewhere where we don’t see a goal,” she said of renewable energy targets.
Golin also said Google doesn’t want to wait on a “six-year interconnection queue” before planned generation can link up to the grid. Google aims to achieve net-zero emissions across all operations by 2030.
“We make two-year, three-year business commitments,” she said.
Towering Transmission Investments
“What we do know is that the future is going to [be] significantly more complex than anything we’ve ever planned for before,” SPP Vice President of Engineering David Kelley said, noting that the U.S. has sustained about 360 weather and climate disasters since 1980 where overall damages and costs have reached at least $1 billion. “Planning for a loss of load event every 10 years is no longer going to cut it,” he said.
Advanced Power Alliance’s Steve Gaw said transmission system expansion is necessary to unlock clean, low-cost energy and shrink congestion.
Gaw said if grid operators aren’t proactively planning, “you’re risking being 10 years behind.”
“In the words of Dwight Eisenhower, I’d say plans are nothing — and basically worthless — but planning is everything,” he said.
Gaw also said transmission projects — even ones built to further a lone public policy goal — rarely fulfill a single purpose. He said transmission often offers a myriad of economic, reliability and decarbonization benefits. He said it’s nearly impossible to build transmission for a single goal.
“You’ve got to think about the consequences if you don’t make that investment,” ITC’s Charles Marshall said of transmission planning, pointing out that his friend’s electric bill will contain an up to $10 surcharge every bill for decades to fund the recovery efforts after Winter Storm Uri because the system wasn’t built to weather the storm.
FERC Commissioner Mark Christie said contrary to the perception of a crumbling and decrepit transmission system, there’s a surge in new transmission projects.
“We’ve heard a lot about how the grid is old, it’s creaky, it’s built for a World War II era,” he said.
But Christie said the national transmission rate base has tripled in the past decade and is set to double over the next eight years. He said grid planners need to be sensitive to regional costs. “You ain’t seen nothing yet” in terms of how high transmission price tags will ascend in the coming years, Christie warned.
Siting infrastructure isn’t going to get any easier, multiple panelists said.
“There’s so much development that communities are reacting. They’re being asked to solve global energy infrastructure problems, and they’re thinking ‘that’s not my problem,’” University of Michigan Director Sarah Mills said.
Mills said developers should sell their projects as solutions to lift farmers’ incomes and increase local tax bases.
Mills also said regulators should be upfront about collecting comments and if the contents stand to change the outcome in a decision.
Mills admitted even she didn’t fully understand how to comment in Michigan Public Service Commission proceedings. She said only the wealthy usually have the time and the means to register their opinions.
Grid United CEO Michael Skelly said infrastructure upgrades, renewable additions and carbon capture facilities stand to benefit disadvantaged communities by improving air quality.
Causes for Concern
America’s Power CEO Michelle Bloodworth said 80 GW of the nation’s 200-GW coal fleet will retire over the next seven years, “putting a lot of pressure” on natural gas infrastructure as a source of fuel-secure dispatchable generation. She said state regulators should slow down the pace of retirements for coal units and let them live their “natural, useful lives” until the grid can secure generation replacements with reliable attributes.
“I don’t want to be the angel of death and cast a pall on this discussion … but I think it’s important to speak very bluntly about the situation we’re in,” consultant Bob Gee said.
Gee said gas suppliers desperately need the creation of a gas reliability organization even though it’s a “hornet’s nest.” He said the grid risks outages in the winter and now in the summer as demand grows.
Grid Strategies’ Rob Gramlich agreed grid operators are leaning on natural gas more, and more needs to be done to make the supply dependable.
Gramlich credited MISO’s 2011 portfolio of Multi-Value transmission projects for keeping the lights on during severe winter weather. He said it’s possible to build the grid “bigger than the weather” and thanked MISO for its work on its first, $10 billion long-range transmission plan (LRTP) portfolio. Gramlich also said grid-enhancing technologies and plans for interregional transmission are necessary going forward to safeguard reliability.
MISO COO Clair Moeller said while about 80% of the first LRTP portfolio used existing rights of way or adjacent routes, the second, multibillion-dollar portfolio on greenfield locations will be more difficult to site and build.
“So, buckle up buttercup, this one’s going to be hard,” he said.
Moeller also said the greater transport capability between organized markets is the most significant change in recent years to avoid load shed events.
“In the old bilateral days, it would take days to move that kind of power,” he said.
Moeller said he continues to worry about what the Germans call “dunkelflaute,” or multiday periods of overcast skies and little wind. He said storage technology doesn’t yet have the capability to cover those prolonged conditions.
