The Department of Energy must provide better justification for its 2020 rule increasing the energy efficiency standards of boilers used in commercial buildings and multifamily housing, the D.C. Circuit Court of Appeals ruled Tuesday, giving the department 90 days to respond.
In issuing the remand, the court said DOE exaggerated the savings that would result from its rule on commercial-packaged boilers. The rule was more stringent than the standards of the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE).
The Energy Policy and Conservation Act prohibits DOE from establishing a standard more stringent than ASHRAE’s, barring “clear and convincing evidence” that it is economically justified, technically feasible and will lead to significant energy savings.
Commercial-packaged boilers are gas- or oil-fired and have rated inputs of at least 300 kBtu/h and are used for space conditioning and/or water heating. DOE said the rule, which was set to take effect in January 2023, would save consumers $36,832 for a large oil-fired boiler, a payback of 2.7 years out of an estimated 25-year lifespan.
The rule was challenged by the American Public Gas Association, which represents publicly owned gas distribution systems; the Air-Conditioning, Heating & Refrigeration Institute (AHRI), which represents manufacturers; and Spire Inc., an owner of gas utilities, including Spire Missouri. The American Gas Association, which represents local distribution utilities, intervened in support of the challengers.
The three-judge panel — Chief Judge Sri Srinivasan, Circuit Judge Ketanji Brown Jackson and Senior Circuit Judge Douglas H. Ginsburg, who wrote the opinion — noted that the “clear and convincing evidence” standard “is unusual,” saying, “We are aware of no other authorization for rulemaking subject to this heightened evidentiary standard.
“This unusual framework creates an unusually strong bias in favor of the status quo,” it added.
Bad Assumptions
The law requires DOE to consider the difference in the life-cycle cost (LCC) of equipment with and without a more stringent standard and the projected energy savings likely to result from the standard. The LCC is the sum of the purchase price (including installation) and lifetime operating cost (fuel, maintenance and repairs), discounted to present value.
The LCC analysis required DOE to describe the mix of boilers if it issued no new standards versus the mix with the new rules.
DOE said it had historical shipping data — the most accurate picture of the mix of boilers in a world without new standards — for only two of the eight relevant categories of boilers. Thus, it assumed the distribution of efficiency levels in shipped equipment was the same as that found in models listed in the database maintained by the AHRI.
In its “no-new-standards case,” DOE assumed the distribution of efficiencies among shipped boilers is the same as the distribution of efficiencies across the models listed in the AHRI database.
“As a result, when the DOE ran trials randomly assigning boilers to buildings in the no-new-standards case, the chance a boiler with a certain efficiency level would be assigned to a building in the sample was equal to the percentage of boilers in the AHRI database with that efficiency level, without regard to the characteristics of the building to which the boiler was assigned,” the court observed. In doing so, the court found, DOE failed to acknowledge that a rational building owner would consider the costs and benefits of its new boiler purchase to produce the best economic performance for its building.
“If a purchaser selects the most efficient unit for its building, then the DOE’s model will assign the benefits of that choice to its rule, rather than attributing it, correctly, to the purchaser’s rational decision-making,” the court said, inflating the economic value of the more stringent standard.
The court said DOE was “dismissive” in rejecting comments challenging its random assignment.
“DOE essentially said it did the best it could with the data it had. This is not enough to justify assuming a purchaser’s decisions will not align with its economic interests in purchasing a boiler,” the court said. “Indeed, the DOE’s lackadaisical response would have been inadequate even if the rulemaking were not governed by a heightened evidentiary standard, for the DOE’s failure to ‘engage the arguments raised before it.’”
The court also said DOE “significantly overstated” the fuel cost savings from the new standard.
“Because operators of commercial packaged boilers are among the largest purchasers of fuel from energy utilities, they receive volume discounts and enter into hedging contracts, and therefore pay significantly less” than predicted average energy prices, the court noted.
And it said the agency exaggerated in estimating that the median burner operating hours — a “crucial” variable in the LCC analysis — for most burners was more than 1,000 hours per year.
It cited an AHRI consultant who said “commercial buildings are generally cooling load dominated, so it would be highly unusual to have 1,000 system operating hours per year.”
“By no stretch was this an exemplar of reasoned decision-making,” the court said. “A commenter pointed to seeming anomalies in the DOE’s data, and the agency ignored them.”
Remedy
DOE told the court it expected to be able to provide “a full and sound” justification satisfying the clear and convincing evidence standard.
“Under these circumstances, we think it should be afforded a limited opportunity to do so,” the court said. “Therefore, we shall remand the final rule to the DOE for the agency to take appropriate remedial action within 90 days. If the DOE fails to do so, the final rule will automatically be vacated unless the agency demonstrates within 10 days of the issuance of this decision the need for additional time.”
The ERO Enterprise has begun rolling out the third release of the Align software platform and the ERO Secure Evidence Locker (SEL), but some of the functionality planned for the release has been separated out and will be released later this year, SERC staff said Tuesday.
Speaking at SERC’s 2022 Open Forum, Todd Curl, the regional entity’s senior manager for risk awareness and oversight, said that Release 3 of Align — which adds audits, spot checks, compliance investigations and complaints to the functionality covered in previous releases — went online in December.
A spokesperson from NERC told ERO Insider that REs are currently working out plans for training and adoption. Curl said SERC intends to conduct training sessions in the second quarter of 2022, “consistent with what several other regions are doing.”
NERC originally planned for Release 3 to happen in the third quarter of 2021, and to be the final stage in Align’s deployment. (See Release 2 of ERO Align Tool Goes Live for All Regions.) As intended, Release 3 would have also included inherent risk assessments and compliance oversight plans. However, the ERO Enterprise’s experience implementing the first two releases in 2021 led NERC to set more modest goals for the release.
“As the ERO Enterprise subject matter experts worked together to identify the specific requirements needed around this very large Release 3 functionality, it became clear that these processes, which had never before been automated or harmonized, would be simply too complex for one single release,” Curl said. “So, given the importance of the smooth transition for these processes to the effectiveness of the CMEP [compliance monitoring and enforcement program], there were some adjustments to the original plan.”
These remaining functions have been separated into a separate Release 4, which will roll out in the third or fourth quarter of 2022, according to NERC. As with previous releases, the functionalities added in Release 3 and 4 only apply to new cases. Registered entities should continue to process and submit supporting evidence for existing self-reports using their current tools.
First Two Releases Already Online
Release 1 and 2 of Align, along with the SEL, went live last year. (See ERO Align Tool Goes Live for NERC, MRO, Texas RE.) The first release took effect starting in March and covered creating and submitting self-reports and self-logs, creating and managing mitigating activities and mitigation plans, and responding to requests for information. The second, which came online in July, added technical feasibility exceptions, periodic data submittals, attestations and self-certifications.
Align began in 2014 as the CMEP Technology Project, with the rollout date originally set for September 2019; this was delayed because of concerns about the software vendor’s sale to an Australia-based company whose investors include a private equity firm based in Hong Kong. (See NERC Investigating Chinese Tie to Software Vendor.)
This security issue prompted NERC to include the SEL in Release 1 rather than debut it later as originally planned. Because the SEL is intended to provide secure storage where potentially sensitive information can be kept separate from work papers managed through the Align tool, it is not part of the main software package, and REs are allowed to construct their own lockers for CMEP evidence if they meet NERC’s reliability and security specifications.
Stakeholders last week had mostly negative reactions at FERC to MISO’s bid to reconfigure its resource adequacy design into seasonal auctions with availability-based resource accreditations.
DTE Energy characterized MISO’s new accreditation as a “severe over-correction” that is “based on chance.” It predicted year-over-year capacity credit volatility and generation overbuilt at the expense of ratepayers, should the proposal go into effect.
“MISO’s proposal would inappropriately require a resource owner to do what MISO cannot or will not do, namely predict when system conditions will be tight in advance,” DTE wrote in its protest. “Even if forecasts based on weather predictions and historical patterns were accurate enough to indicate potential operating periods of concern, tight conditions are also driven by unpredictable events such as other resources’ forced outages or transmission outages.”
Louisiana utilities Entergy and Cleco also said the design would expose market participants to an “unreasonable level of volatility.”
The Coalition of Midwest Power Producers said MISO failed to show how the new auction and accreditation design would stem the RTO’s tide of reliability issues and asked FERC to order a technical conference to investigate problems with the plan.
MISO late last year sought the commission’s approval to perform four seasonal capacity auctions, with separate reserve margins, by 2024 and apply a seasonal accreditation based on a generating unit’s past performance during tight system conditions (ER22-495).
The grid operator also filed separately to establish a minimum capacity obligation. MISO load-serving entities would have to demonstrate that they have secured at least 50% of the capacity required to meet their peak load in advance of voluntary capacity auctions (ER22-496). (See FERC Grants Comment Extension for MISO Capacity Filing.)
MISO originally intended the minimum capacity requirement be included in the seasonal auction design. However, stakeholders said including it in the same filing could risk FERC’s rejection of the entire resource adequacy modification. Written opinions on the RTO’s plans were due Jan. 14.
Multiple market participants said MISO’s requested effective date was too soon, since preparations are already underway for the 2023-24 planning year capacity auction(s).
The Clean Energy Coalition, which includes the Sierra Club, Sustainable FERC Project, Natural Resources Defense Council and Clean Grid Alliance, said the seasonal design “is rigid and does not allow for a changing risk pattern that will continue into the future as the resource mix continues to evolve.” The groups criticized MISO for not considering fuel supply risks in accreditation and for using different risk hours to accredit thermal resources and wind resources. The latter will continue rely on the RTO’s existing effective load carrying capability calculation.
They also said the accreditation proposal is incomplete because it doesn’t offer a capacity accreditation approach for electric storage resources.
Ameren said while it can get behind seasonal auctions, it disagreed with the proposed accreditation because of the disparate treatment of resource types when calculating capacity credits.
WEC Energy Group objected to MISO’s plan to plump up seasons with low or no loss-of-load risk with a resource’s annual availability values for accreditation purposes. It said a resource’s capacity credits in low-risk seasons would “inappropriately include resource availability from other seasons.”
MISO’s transmission owners said while they supported a transition to seasonal auctions and availability-based performance incentives, they wanted the grid operator to explain whether it will continue to limit capacity accreditation to summer interconnection rights. In MISO, a market participant’s annual unforced capacity value cannot exceed the resource’s summer interconnection rights.
“If the proposed seasonal construct is implemented, MISO effectively will be limiting non-summer capacity accreditation to summer interconnection rights,” the TOs said.
The Organization of MISO States (OMS) was one of few to lend support to the seasonal plan, saying it represents an “improvement over the status quo.”
“While MISO cannot control when a generator or transmission line goes down or when and how an extreme weather pattern will affect the system, it can control the signals generators receive to be available in the face of uncertainty,” OMS said. “This proposal more accurately identifies seasonal risk than MISO’s current resource adequacy construct and more accurately accredits resources’ ability to contribute to the system during tight conditions.”
OMS said it is “entirely reasonable for MISO to require resources that receive capacity credit and capacity payments be available to offer energy for a large part of a given season.”
Not all state regulators were in step with OMS. The Mississippi Public Service Commission said the accreditation proposal “interferes with state jurisdiction over generation resource decisions because existing and future generation that does meet MISO’s criteria will be devalued as sources of capacity.”
The PSC said the accreditation is “untested” in any other grid operator and is “a costly experiment.”
The Louisiana PSC also panned the accreditation design as placing “too much significance on too small a sample size” of risky hours. It added that MISO’s month-long limit on planned outages in any season will cause “discriminatory treatment of generation that requires outages greater than 31 days, particularly nuclear generation.”
Manitoba Hydro also said while the filing may not be perfect, it is necessary to confront escalating reliability risks in the footprint.
International Transmission Co. invoked climate change in addition to the resource fleet’s continued transition as evidence that seasonal auctions and accreditations will be necessary. It urged FERC to adopt the resource adequacy overhaul.
Minimum Capacity Rule Draws Ire
The possible introduction of a 50% minimum capacity obligation also proved unpopular. Several said it was a pointless mandate.
The Illinois Commerce Commission protested the possible requirement as unproven and discriminatory against retail choice areas in MISO, which rely on “a robust competitive wholesale market” instead of regulated, integrated resource planning.
The ICC said the rule will “likely result in higher rates that are unjust and unreasonable and is likely to result in the exercise of market power.”
Big Rivers Electric Corp., Hoosier Energy Rural Electric Cooperative, and Southern Illinois Power Cooperative said MISO didn’t describe what reliability problems the minimum obligation is tailored to address.
Shell Energy North America similarly said MISO didn’t explain its reasoning for introducing the rule. It said the grid operator’s worries about load-serving entities’ (LSEs) increasing overreliance on its voluntary auction are overblown.
“In the last 2021-2022 Planning Resource Auction, MISO procured 96.4% of its capacity from self-scheduled and fixed resource adequacy plan resources, up from 94.5% in the 2020/2021 auction. This trend shows LSEs are acquiring more resources on a forward basis counter to MISO’s claims,” Shell Energy wrote.
Exelon called the minimum capacity obligation “a solution in search of an unsubstantiated problem, which will impose regulatory constraints that will inevitably increase costs to customers.”
However, the minimum capacity rule had its defenders. Entergy said the requirement is a “practical safeguard to ensure that LSEs engage in reasonable resource planning practices” and don’t develop a dependence on the Planning Resource Auction. DTE Energy also called it a “necessary first step in maintaining local and regional reliability.” Duke Energy characterized it as a “a much-needed backstop.”
Consumers Energy said the rule would level the playing field between the LSEs under state obligations to plan their capacity procurement years in advance and those that aren’t. It called the rule a “gentle mitigating measure.”
As the California Air Resources Board moves toward requirements to electrify truck fleets, concerns are surfacing about the demands large electric vehicles will put on an already-strained grid.
A wide range of stakeholders commented on the issue during a medium- and heavy-duty infrastructure workgroup meeting that CARB hosted last week as part of its process for developing the Advanced Clean Fleets regulation.
“We obviously have power delivery problems today in California,” said Thomas Jelenic, vice president of the Pacific Merchant Shipping Association (PMSA). “And as we intensify electrification, we become more vulnerable. So what we have been doing in the past is not sufficient.”
Jelenic asked how electric resilience would be provided to ports, which he described as “a node of everything heavy-duty that’s going to be electrified in the future.” He said a PMSA analysis found that California ports would need about 600 MW for future transportation electrification — seemingly more than a microgrid would provide.
The goal of the Advanced Clean Fleets regulation is to accelerate the adoption of zero-emission trucks and buses by requiring fleets that are well-suited for electrification to transition to ZEVs where feasible. An informal discussion draft of the regulation was released in September.
Wastewater Worries
Eva Plajzer, assistant general manager for engineering and operations at the Rancho California Water District in Temecula, called the timing of the regulation unrealistic. The proposed rule would require half of new vehicles purchased for public fleets to be electric starting in 2024, increasing to 100% in 2027.
Plajzer asked whether grid reliability issues would be addressed by the time the fleet regulations take effect.
“This is a tremendous concern,” Plajzer said. “When do you see having enough capacity on the grid where this reliability issue is no longer significant?”
Plajzer said Rancho Water, which provides water and sewer service, doesn’t have the luxury of taking several days off because of a power outage, such as a public safety power shutoff.
She said the district has about 8 MW of solar power. But it doesn’t have space to add the “football field of batteries” it would take to provide backup power supply, she added.
In a written chat comment during the meeting, Kiel Pratt, vehicle-grid integration unit supervisor at the California Energy Commission, suggested that Plajzer look at the Laguna Wastewater Treatment Plant in Santa Rosa. The plant has engines fueled by biogas produced on-site, he said, as well as a photovoltaic system and battery storage.
Jason Dake, vice president of legal and regulatory affairs for Orange EV, a manufacturer of industrial EVs, pointed to the challenges of terminal tractors that may be used around-the-clock at distribution centers. The trucks are often “clumped together” geographically in warehouse districts, such as those in the Inland Empire, he said.
“Terminal tractors don’t have routes,” Dake said. “They are located on that site. They charge continuously during the day. That presents a very localized stress on the grid.”
Another issue raised during the meeting is that truck fleets are typically in use during the day and therefore can’t charge during off-peak times when solar power is plentiful. Charging overnight may rely on gas-fueled power that doesn’t have the same emissions-reduction benefits, a participant said in chat-section comments.
Leslie Goodbody from CARB’s Mobile Source Control Division said the agency is aware of the issue.
Planning Ahead
Utility representatives who participated in the meeting urged stakeholders to let them know in advance of plans to electrify fleets.
“The key thing is lead time — letting us know sooner than later that you’re planning to electrify,” said Vishal Patel, principal manager of integrated system analysis at Southern California Edison.
“Getting that discussion started is really important for the utility to be aware so we can put that into our processes.”
The Jan. 12 workgroup meeting was the third in a series of sessions related to Advanced Clean Fleets. The meeting’s focus was electricity and the grid. CARB is now planning a follow-up meeting on a date to be determined.
Another meeting, focused on costs and funding, was scheduled for this week but has been postponed to a date yet to be decided.
PJM updated stakeholders at last week’s Operating Committee meeting regarding ongoing discussions with the Illinois Environmental Protection Agency over the impacts of the state’s sweeping energy legislation passed in September that has it on a 30-year path to 100% carbon-free electric generation.
Chris Pilong, director of PJM’s operations planning department, provided an update on the Illinois Energy Transition Act and the RTO’s response. Signed into law on Sept. 15 by Gov. J.B. Pritzker, the legislation requires all investor-owned baseload coal-fired power plants and remaining oil peaker turbines to shut down by 2030. (See Illinois Senate Passes Landmark Energy Transition Act.)
Gas turbine plants, including ones currently under construction, must also close by 2045 under the terms of the bill, although the state has an option to allow continued operation if they are critically needed.
Pilong said the broad scope and impact of the legislation has created a need for generation owners and Illinois state entities to have discussions and resolve issues.
“We’re well aware that there’s still a number of unanswered questions that generator owners have with respect to the legislation,” Pilong said.
PJM has been focusing on and working with the Illinois EPA and other state agencies on language within the legislation permitting generators “out of run hours” in the near term if there’s a reliability need for the resources. Pilong said there’s not much detail in the legislation about what out-of-run hours mean, resulting in a “source of confusion” and questions about how it will be implemented.
PJM wants the EPA to “provide clarity” on the guidance for generators and to post the language publicly. Pilong said the RTO hasn’t drafted language yet on the issue to present to the EPA, but it plans on having draft language ready by the end of the month. He said PJM is focusing on five areas of reliability needs in the language, including capacity, thermal constraint control, reactive support, system restoration through black start resources and testing of resources.
The RTO has also performed some initial analysis to see if there were any concerns this winter with thermal or voltage constraints resulting from the implementation of the legislation, Pilong said, but it didn’t find any concerns. PJM is also looking at analysis of the medium- and long-term impacts of the legislation on generation.
Paul Sotkiewicz of E-Cubed Policy Associates said he had concerns PJM was “abdicating its reliability responsibility” in favor of the language in the Illinois legislation. Sotkiewicz said the Illinois EPA is not subject to oversight by FERC and NERC like PJM.
Pilong said the language PJM is working on with the EPA is meant to give generation owners “more confidence” that the RTO isn’t taking unilateral actions that will put them in conflict with the state legislation.
“We’re not looking to get the blessing from the state about how reliability is maintained,” Pilong said. “Illinois is well aware that’s PJM’s responsibility.”
Sotkiewicz asked if PJM is pushing Illinois to conduct a rulemaking process on the legislation, calling it “absolutely critical” to provide guidelines. He said PJM in the past has met with state staffs to explain what needs to be included in rulemakings to guarantee reliability in the RTO.
“You’ve been given the reliability needs, and a state could turn around and say, ‘No thank you,’ and you’re stuck with it,” Sotkiewicz said.
Stephen Bennett, PJM manager of regulatory and legislative affairs, said Sotkiewicz misunderstood. He said the Illinois EPA told PJM that the “omission of explicit language” authorizing rulemaking on the issue in the legislation was a “conscious choice” made by the legislature and that the agency “does not have the authority” to conduct a rulemaking process.
“PJM has been explicitly clear that PJM and our members need as much clarity as possible to allow for us to move forward with our No. 1 priority of managing reliability,” Bennett said.
Marji Philips, vice president of wholesale market policy at LS Power, said her company believes the Illinois legislation could result in a reversal of some of the “extraordinary gains” made on emission reductions in PJM. The company’s analysis shows more coal plants could end up operating in Illinois and in other states to make up for the loss of generation resources, she said.
She asked PJM to help identify some of the “environmental consequences” of the legislation on other states in the RTO through additional studies.
“When you turn off natural gas in Illinois, that might mean a whole lot more coal runs in Indiana or Ohio, actually defeating the whole purpose of the legislation,” Philips said.
Dynamic Line Rating Issue Delayed
PJM is delaying requirement language for several manuals related to the implementation of a dynamic line rating (DLR) system in the RTO after a FERC decision in December that ended static ratings.
Chris Callaghan, senior business solution engineer with PJM’s applied innovation department, had presented a first read of a problem statement and issue charge regarding DLR at last month’s OC meeting. (See “Dynamic Line Rating,” PJM Operating Committee Briefs: Dec. 2, 2021.) PJM is looking to install sensors on or near existing transmission lines to collect real-time data. The technologies include weather stations, electromagnetic field detectors and thermal cameras.
Later that month, FERC ordered transmission providers to employ ambient-adjusted ratings for short-term transmission requests and seasonal ratings for long-term service. (See FERC Orders End to Static Tx Line Ratings.)
Callaghan said PJM is now waiting until the committee’s February meeting to conduct a second first read of the proposed problem statement and issue charge as the RTO’s legal staff reviews the commission’s order.
“We want to make sure we have time to digest the order and make sure we fully understand it,” Callaghan said.
Renewable Dispatch Endorsed
Stakeholders unanimously endorsed an issue charge aimed at improving dispatch of renewable resources and increasing forward-looking visibility.
Frogg said that as the number of renewable resources grows, manually managing dispatch becomes more difficult and leads to inconsistent performance.
“We’re in the middle of a significant transition in fuel mix with a large influx of new solar and wind projects,” Frogg said. “We want to get ahead of this now before the next significant wave of new renewable resources becomes commercial.”
Key work activities of the issue charge include reviewing education on existing renewable dispatch practices, with a goal of proposing solutions to enhance the overall renewable dispatch process.
Frogg said stakeholder suggestions led to PJM adding education on renewable dispatch performance statistics, and solutions and practices from other RTOs/ISOs.
PJM also added the tariff term “intermittent resources” to go along with the term “renewable dispatch” to better align with existing language in the RTO’s governing documents. Frogg said PJM wanted to keep the issue broad to include all renewable resources.
Work on the issue charge will take place in the OC beginning in February and is estimated to take six months.
Frogg said PJM was originally looking to pursue the CBIR (consensus-based issue resolution) Lite approach to develop a proposal, but the issue charge was changed to use the normal process after several stakeholders questioned the RTO at last month’s OC meeting.
Manual 38 Revisions Endorsed
Stakeholders unanimously endorsed minor revisions to Manual 38 as a part of a periodic review.
Hoang said the minor changes include adding language stating that the Eastern Interconnection Reliability Assessment Group will conduct “assessments to identify key reliability issues and the risks and uncertainties affecting adequacy and security of the bulk power system in the Eastern Interconnection.”
Members will vote on final endorsement of the changes at the Markets and Reliability Committee meeting Jan. 26.
A new study from ISO-NE offers a warning that distributed energy resources equipped with outdated inverters could be a weak link in the region’s grid as it continues to rely more on renewable generators.
A fault on New England’s transmission lines could bring down thousands of megawatts of DERs under certain conditions, with ripple effects that could move into neighboring power grids, the study found.
The study, which commenced in September 2020 as a response to changing conditions and stress on the region’s transmission system and published this month, used a broader lens than many previous reports.
It took a range of four load and solar output conditions (the “four corners” of a scatter plot containing historical daily data) and turned them into six base cases, rather than the more typical consideration of just peak and minimum loads.
Most worryingly, the report found that “significant” amounts of DERs could trip or experience temporary power reduction after a transmission line or transformer fault in the spring weekend midday minimum load case, which involves high solar output and relatively low power consumption.
Those trips could lead to serious impacts on New England’s grid and beyond.
“As much as 1,850 MW of DERs (which is 25% of DERs assumed online) could trip for a fault in New England, which is greater than the current loss of source threshold of 1,200 MW where New England events could begin to impact the New York and PJM systems,” the study says.
The spring weekend conditions which could cause large amounts of DERs to trip | ISO-NE
Up to 5,300 MW of DERs could also go into temporary power reduction, potentially causing “huge power swings within neighboring systems,” even though they would come back to full power output within 10 seconds.
A large piece of the challenge presented in the study is that many of the DERs are what ISO-NE calls “legacy” systems that have older inverters that do not allow them to “ride through” faults.
The RTO tested several mitigation strategies, including replacing those legacy inverters with new inverters, enabling dynamic voltage control on new DERs, turning generators into condensers and reducing solar output. But none of those solutions offered enough improvement in the system conditions to alleviate worries.
“The exposure to this concern is not limited to a small number of hours per year, but is something that must be addressed to avoid reliability concerns under fairly frequent system conditions,” the study says.
The study concluded that there are a number of outstanding questions that need to be answered and additional data collected. Several of them focus on the interregional effects of DERs tripping and whether the current 1,200-MW threshold is low enough.
The RTO’s analysis for other conditions finds fewer reasons for concern. It projects a “number” of N-1-1 high-voltage violations during minimum load conditions, as well as thermal violations for one summer peak case. The study found that the high-voltage violations, caused by a lack of centrally located synchronous generators and lightly loaded transmission lines and transformers, could be addressed by installing five shunt reactors, costing approximately $25 million to $50 million in total.
The thermal violations could be managed by reducing generation by 30 MW in the relevant region (Massachusetts and Rhode Island), the study says.
PJM announced Tuesday that it’s delaying the return to campus for employees and stakeholders because of “recent events” surrounding the rise of COVID-19 cases from the Omicron variant.
CEO Manu Asthana made the announcement in a message sent to members, saying the RTO originally expected to reopen the campus to employees in a phased-in approach beginning in January and return to in-person meetings for specified stakeholder committees in the first quarter.
But Asthana said “new guidance” from the U.S. Centers for Disease Control and Prevention and consultation with PJM’s epidemiologist have led the RTO to delay employee return until the middle of March and the start of most in-person stakeholder meetings “in a phased manner” to April through June.
“At PJM, the safety, security and reliability of the high-voltage electric system and the wellbeing of our employees and stakeholders are paramount,” Asthana said. “Since January 2020, we have taken a variety of actions to safeguard our people and the power grid against the risk posed by the coronavirus pandemic.”
In November, PJM mandated COVID-19 vaccines for its employees, contractors, vendors and stakeholders working at or attending meetings at the Valley Forge, Pa., campus or to attend RTO events on and off campus beginning Jan. 4. (See PJM to Mandate COVID-19 Vaccines.)
Asthana said the Liaison Committee, the first scheduled stakeholder meeting, will take place on April 19 as part of the Board of Managers’ meeting.
The PJM Annual Meeting, which is usually held at a remote location, will take place on the campus on May 17. Meetings of the board with the Transmission Owners Agreement-Administrative Committee and the Public Interest & Environmental Organizations User Group are scheduled for May 18.
An in-person meeting of the Markets and Reliability Committee is now scheduled for May 25.
Meetings for all standing committees and senior task forces will be held on campus beginning in June. Those include the MRC, and Members, Planning, Market Implementation, Operating and Risk Management committees.
Sometime in the fall, PJM will hold the MC and General Session at a remote location that will include a “reception and leisure activities,” Asthana said.
In-person state and member training events are scheduled to resume in March for the 2022 PJM Operator Seminar. Those include:
March 7 to 25, in Baltimore;
March 28 to April 22, in Columbus, Ohio; and
April 25 to May 13, on the PJM campus.
Asthana said PJM business travel is expected to resume in the spring. He said PJM plans on providing more detail on the campus reopening process, protocols and meeting logistics as the dates come closer.
“As always, we will continue to evaluate our plans based on the trajectory of the pandemic,” Asthana said.
New York’s Black, Puerto Rican, Hispanic and Asian (BPHA) Legislative Caucus wants to create a pathway for young adults to enter the energy and environment workforce through a program to make the state’s schools clean and resilient.
“School buildings are some of the highest polluters in our state,” Rep. Kenny Burgos said on Monday during a BPHA Caucus webinar on priorities for the next New York budget.
The 68-member caucus is proposing New York create a healthy school buildings program to support the goals of the Climate Leadership and Community Protection Act (CLCPA). The program would help young people acquire entry-level jobs retrofitting schools to transition away from fossil fuel and prepare them to withstand the stresses of climate change.
“Our schools need infrastructure updates that are going to create thousands of green jobs … and help bring money back to our communities,” Burgos said.
The program would emphasize investments in schools in marginalized and disadvantaged communities and supporting young people from those communities in job placement.
Gov. Kathy Hochul unveiled a $59 million initiative last fall to improve indoor air quality in pre-K-12 schools in disadvantaged communities. The program, which is slated to launch early this year, will provide the technical support schools need for energy efficiency and clean heating and cooling projects.
Hochul will release her full budget proposal this week, then move into budget negotiations with legislators before a final vote this spring. The school buildings program is one of 15 budget priorities the caucus is proposing for climate action, environmental justice and energy.
To further emission reductions in the state’s buildings sector, the caucus is supporting the All-Electric Building Act (S6843A) co-sponsored by caucus member Sen. Jabari Brisport. The bill would require municipalities to deny permits for new residential or commercial building construction if they are not all-electric, effective in 2024.
Climate Bills
One of the caucus’ top priorities is a bill that would establish a carbon tax to fund state climate investments.
“We’re proposing to meet the very strong, landmark goals of the [CLCPA] by mandating New York prioritize investments for up to $15 billion for well-paid jobs across the state, with 40% of these investments flowing to disadvantaged communities and workers most impacted by the pollution intensive fossil fuel economy,” Burgos said.
The Climate and Community Investment Act (S4264A), sponsored by caucus member Sen. Kevin Parker, would authorize the state to establish a fee for entities that emit greenhouse gases. Supporters of the bill estimate the fee could raise $10 billion to $15 billion over 10 years.
Also on the caucus’ priorities list are bills to end fossil fuel subsidies and expand the New York Power Authority’s ability to build renewable generation.
The Fossil Fuel Subsidy Elimination Act (S4816) would repeal $330 million in tax exemptions provided by the state to the fossil fuel industry. The bill, according to the caucus, would eliminate certain exemptions to the sales and use tax and the petroleum business tax.
The New York Build Public Renewables Act (S6453), sponsored by Parker, would eliminate the cap on the New York Power Authority’s portfolio of clean generation assets. Currently, NYPA cannot own more than six generation facilities at 25 MW each, which the caucus says is a “huge limitation.”
Adirondacks and Equity
The caucus also proposed celebrating New York’s Adirondack Park as a “cradle of the early civil rights movement” through the intersection of climate science education and environmental justice.
Adirondack Park is a 6-million-acre protected area of New York that includes forest preserves and private land, where Burgos says some communities are disproportionately affected by climate change.
One initiative would highlight an early suffrage settlement in the Adirondack Park, called Timbuctoo, where Black men received property that enabled them to vote. The Timbuctoo Pipeline would create a summer climate and careers institute through a partnership between Medgar Evers College and the State University of New York College of Environmental Science and Forestry.
The initiative “will help create an exploration of intersectional careers and address systemic issues of access to the Adirondack Park from an equity and justice perspective,” the caucus said.
PJM’s proposal regarding the development of new rules for the interconnection process won near unanimous support from stakeholders at last week’s Planning Committee meeting.
The proposal, developed in the Interconnection Process Reform Task Force, received 275 votes in support (99%), with only one member voting against it. In a vote asking stakeholders if they preferred the proposal over maintaining the status quo, the PJM proposal again received 275 yes votes (99%).
PJM’s new interconnection process framework overview. | PJM
Jack Thomas of PJM’s Knowledge Management Center reviewed the RTO’s proposal, first presented at the December PC meeting. (See “Interconnection Process Proposals,” PJM PC/RMC Briefs: Dec. 14, 2021.) Three other proposals originally presented at that meeting were pulled by their sponsors, leaving only the PJM proposal to be considered.
Thomas said the PJM proposal, which consisted of more than 90 design components in the matrix developed at the task force, includes moving away from the concept of “first come, first served” projects in the queue to a “first ready, first served” concept. The change will ensure projects that are ready to be built are prioritized instead of allowing speculative projects to fill the interconnection queue.
The proposal also adds language saying that if a facility study isn’t needed and no network upgrades are necessary for a project, then it could move to the final agreement stage early, speeding up the process. The study window for projects is also proposed to be scheduled for 710 days, or just under two years.
Jason Connell, director of infrastructure planning for PJM, said the RTO and stakeholders worked “very diligently” over the last several months to craft a solution that could receive majority support from members.
“I understand we weren’t able to incorporate everyone’s suggestions and changes throughout the entire process, but if feedback or input was provided, it was carefully considered,” Connell said.
Iker Chocarro of RWE Renewables, one of the sponsors of an alternative proposal, thanked PJM for all the work done on the issue over the last year. RWE decided to pull its proposal from consideration because most of its content was found in the PJM proposal except for additional details on affected systems, he said.
“We would like to encourage PJM to keep working on affected-system issues,” Chocarro said.
Arash Ghodsian of EDF Renewables called the process a “great collaboration effort” that brought a popular proposal forward for a vote.
“I think we’re in a good place,” Ghodsian said. “It was a great accomplishment.”
Paul Sotkiewicz of E-Cubed Policy Associates said PJM’s planning and interconnection teams did an “excellent job” in coming up with a proposal with widespread support among stakeholders. Sotkiewicz singled out Connell for his work, saying he went out his way to listen to concerns and would come back with “reasonable explanations” for the decisions that were made.
“Even if we didn’t get everything we wanted, PJM was extremely thoughtful,” Sotkiewicz said. “While this interconnection process was contentious, this is the way the stakeholder process should work.”
Interconnection Process Transition
Besides the vote on the interconnection process rules, stakeholders also heard plans on how PJM will transition into a new interconnection process.
Thomas provided a first read of two transition proposals from the work done at the Interconnection Process Reform Task Force.
An issue charge for work to be completed on the interconnection issue was approved 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.
PJM held a nonbinding poll focusing on the interconnection transition proposals, with a total of 545 companies participated, including 290 RTO members. The PJM proposal received 92% support from all stakeholders and 93% support from members, while a proposal from National Grid Renewables received 13% support from all stakeholders and 18% support from members.
Thomas said the PJM proposal features an expedited interconnection process of “fast lane criteria” that includes projects with any cost allocations of $5 million or less, amounting to about 450 impacted projects with a completion date of 18 months. He said the $5 million cutoff should cover the bulk of substation and terminal equipment upgrades and, as a result, shorten durations for facilities to study the work needed to be done.
The National Grid proposal for fast lane criteria in the expedited process has no network upgrades or cost allocation set. The expedited process in the proposal would include around 300 projects with an estimated completion date of 12 months.
Thomas said the advantages of the PJM proposal is that it consolidates the transition into two distinct parts: the fast lane criteria and two transition cycles. He said the fast lane is bound by projects that can proceed upon completion of a facilities study, while the transition cycles include more complicated projects in the interconnection queue.
The PJM proposal also preserves 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 also reduces the time that the queue is closed for the transition.
Connell said the transition proposal was an “extremely controversial topic” for stakeholders, but compromises were agreed upon to push options forward.
One stakeholder said they were supportive of the PJM proposal, but his company had some small issues to address. The stakeholder asked PJM to reconsider the $5 million fixed limit in the fast lane criteria, calling it a “bit arbitrary,” and requested that if a limit is set, it should be done on a per-megawatt basis.
“There could be an issue of smaller projects being able to get through relative to larger projects,” the stakeholder said.
Carl Johnson of the PJM Public Power Coalition said he “did not imagine” that PJM and stakeholders would be able to come together on transition proposals when the process first started. Johnson said stakeholders understood that they needed to move forward and come to a compromise.
“We should all bask in the glow of a very successful stakeholder process and hope that when it gets to FERC it’s similarly successful,” Johnson said.
Stakeholders will be asked to vote on the proposals at the February PC meeting.
Deactivation Process Timing
David Egan, manager of PJM’s system planning modeling and support department, provided a first read of a proposed deactivation process timing update, presenting a problem statement, issue charge and revisions to Manual 14D and the tariff.
Egan said the current timing of 30 days in the tariff to complete deactivation studies “works fine” when there’s only a single deactivation notice in a period. But when multiple deactivation requests are received, the 30-day timetable is “insufficient” to determine any adverse impacts on reliability.
Trends in state energy policies could lead to more large volume deactivation notices in the future, Egan said, putting more pressure on PJM staff in the deactivation studies. Egan said the short duration 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.
“All this work is being stacked up on top of each other, and it’s very difficult to come up with holistic solutions,” Egan said.
The 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.
PJM is proposing quarterly study times for deactivations, with study periods beginning Jan. 1, April 1, July 1 and Oct. 1. The RTO staff will study deactivations as a batch with reliability notifications to be made by end of February, May, August and September, respectively.
To request a deactivation, a generation owner must submit 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 is seeking endorsement of the issue charge at the February PC meeting through the “quick fix” process because its “just targeting the current tariff timing” for deactivations, Egan said.
Sharon Midgley of Exelon said her company is “sympathetic” to the issues being raised by PJM, agreeing the problem should be discussed by stakeholders. But Exelon staff had concerns over using the quick-fix process on the issue because of the complexities in the deactivation process that could arise by modifying the schedule.
“We think the proposal does change the rules around a generator notice for deactivation, which is a pretty fundamental change,” Midgley said.
Johnson said he agreed with Exelon in trying to avoid the quick-fix process on the issue, saying it is a “pretty substantial change.”
Egan said PJM staff will discuss what stakeholder process to use before the next PC meeting.
Transmission Expansion Advisory Committee
Market Efficiency Update
Nick Dumitriu, principal engineer in PJM’s market simulation department, provided an update on the 2020/21 long-term market efficiency window at last week’s Transmission Expansion Advisory Committee meeting.
Dumitriu identified four projects that are ready for a final recommendation by the PJM Board of Managers. They included:
the 230-kV Juniata-Cumberland line reconductor, a $9 million upgrade in the PPL zone. The estimated in-service date is Dec. 1, 2023.
the 230-kV Charlottesville-Proffit line series reactor, a $11.38 million upgrade in Dominion. The estimated in-service date is June 1, 2023.
the 230-kV Plymouth Meeting-Whitpain terminal upgrades, a $620,000 project in PECO. The estimated in-service date is June 1, 2025.
the 138-kV French’s Mill-Junction terminal upgrades, a $770,000 project in APS. The estimated in-service date is April 1.
The board will vote on the projects at its upcoming meeting in February.
Generation Deactivation Notification
Phil Yum of PJM provided an update on recent generation deactivation notifications.
Yum said PJM completed its reliability analysis on two battery deactivation requests in the ComEd transmission zone, including the Joliet Energy Storage battery and the West Chicago Energy Storage battery, which are both six years old. No reliability violations were identified, and they can be deactivated by Feb. 8.
PJM also received three additional deactivation notices since its last TEAC meeting in November, including New Jersey’s last two remaining coal generation 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, and a reliability analysis is currently underway.
The 9.3-MW Orchard Hills Landfill in the ComEd transmission zone in Illinois made a requested deactivation date of March 31. A reliability analysis is currently being conducted by PJM.
PJM members endorsed an issue charge at last week’s Market Implementation Committee meeting to study the treatment of generation with co-located load after making modifications to its key work activities stemming from concerns over the scope of the issue.
The issue charge, sponsored by Exelon and Brookfield Renewable, received 207 votes in support (92%) with 29 abstentions. Jason Barker of Exelon reviewed the problem statement and issue charge first presented at the December MIC meeting. (See “Capacity Offer Opportunities,” PJM MIC Briefs: Dec. 1, 2021.)
Exelon has seen growing consumer interest in co-locating new, large interruptible commercial loads behind the meter of existing generation resources. Customers are asking for low-cost physical energy supply from generator resources with specific characteristics, such as carbon-free physical energy supply.
“We see a gap in the rules that could, if filled, both facilitate commercial transactions and customer choice,” Barker said. “The fast-curtailment capability of these resources is the innovation that is driving the need for rule reform.”
The issue charge includes investigating market rule changes to support new interconnection configurations for co-located load. Key work activities feature education regarding current capacity offer requirements for existing generation resources and interconnection requirements for “new, large, fast-response interruptible commercial load.”
Debate over the issue charge at the MIC meeting led to the addition of two more key work activities. They include examining federal and state “jurisdictional bounds” that could impact co-located load configurations and the potential impact of co-located load configurations on generator capacity capability.
The key work activities were also broken into two phases, with the examination of the potential provision of ancillary services facilitated by highly interruptible, co-located load coming in the second phase once work in the first phase is completed.
Work on the issue is expected to take six months at the MIC.
Independent Market Monitor Joe Bowring questioned the issue charge, saying he was “highly skeptical.” Bowring said the issue would represent a “really radical change” to the capacity market and should be considered as part of the work being done at the Resource Adequacy Senior Task Force.
He also said the thinking that this is a narrow issue that will make commercial opportunities available to a subset of customers is “not really relevant.” He said the potential also exists that all effective load-carrying capability (ELCC) calculations will have to be redone because the current calculations already account for the generation resources.
“One person’s benefit is another person’s cost,” Bowring said. “It’s changing the definition of capacity, converting a baseload resource to an interruptible resource. Should an interruptible resource have the same ELCC, the same capacity value to the market, as a baseload resource?”
Bowring also said by dedicating low-carbon nuclear output to a new load that would not otherwise exist, additional emitting resources would need to operate to meet PJM load, causing carbon emissions in the RTO to increase.
Barker said Exelon and Brookfield disagree that the issue charge presents a “radical change” in the capacity market and that it would not change the definition of capacity. Absent any changes, PJM could see the “loss of economic development” or a loss of emissions-free resources from the grid, he said.
“We just have to evolve with the changing needs of the customer base,” Barker said.
Aaron Breidenbaugh, director of regulatory affairs for Centrica Business Solutions, said that when he first brought the issue to his company, commenters said it “seems like a solution in search of a problem.” Breidenbaugh said what was being proposed in the issue charge could be done through the “existing demand response construct” in PJM’s capacity market or through the purchase of renewable energy credits.
“I’m wondering why we need to create this exception,” Breidenbaugh said.
Barker said customers have expressed a desire to move away from DR and have also asked for a physical supply of a clean energy resource, rather than just purchasing RECs. He added that customers with no grid interconnection are not permitted to participate in PJM’s DR programs.
“I strongly disagree that this is an exception,” Barker said. “This is a reform and an evolution because we haven’t seen these types of commercial loads seek this type of service before.”
De-energized Bus Replacement Revisions Endorsed
Stakeholders unanimously endorsed manual revisions related to five-minute dispatch and pricing.
Vijay Shah, lead engineer in PJM’s real-time market operations department, reviewed revisions to Manual 11: Energy and Ancillary Services Market Operations designed to incorporate enhancements to the dead bus replacement logic for assigning prices to de-energized pricing nodes (pnodes). The revisions were first discussed at the December MIC meeting. (See “De-energized Bus Replacement,” PJM MIC Briefs: Dec. 1, 2021.)
The revisions were intended to provide increased transparency in the logic and how it performs replacements for de-energized buses, Shah said. PJM is required to produce LMPs for all pnodes in the RTO’s network model for all intervals, including de-energized pnodes.
Shah said PJM wants to use new logic based on Dijkstra’s algorithm, an industry standard, to find a suitable replacement for de-energized pnodes. He said the algorithm uses the “least impedance path” to find a suitable source, and it’s to be implemented in both day-ahead and real-time market clearing engines.
The manual changes include updated language to reflect the new logic.
Shah highlighted a change to section 9.1.1: Intraday Offers Optionality that was not included in the first read at the December MIC, which clarifies language to state that a generation resource’s fuel-cost policy only needs to be updated when opting in to intraday updates for the cost-based schedule.
PJM will seek final endorsement at the Jan. 26 Markets and Reliability Committee meeting, and the new dead bus replacement logic would take effect March 1.
Minimum Run Time Guidance Endorsed
An issue charge addressing pseudo-modeled combined cycle minimum run time guidance won unanimous stakeholder support.
Hauske said PJM and the Monitor brought the issue forward as a result of the “disaggregation of many multiple block combined cycles” into individual pseudo-model market units, or virtual modeled combined cycle units. Market sellers can currently model a combined cycle unit as multiple pseudo units composed of a single combustion turbine and a portion of a steam turbine.
If the market units of a pseudo-modeled unit are dispatched at different times on parameter-limited schedules, Hauske said, the potential exists for one or more of the pseudo-modeled units to operate “for some period beyond the minimum run time parameter limit for an identical non-pseudo-modeled combined cycle unit.”
Key work activity in the issue charge included stakeholders developing guidance for market sellers regarding offering operating parameters for pseudo-modeled combined cycle units through education on the issue. Expected deliverables include revisions to Manual 11 or other relevant PJM governing documents.
Hauske said PJM wanted to use the CBIR (consensus-based issue resolution) Lite process in Manual 34 to develop any manual changes and have final endorsements by the March 23 MRC meeting because the RTO’s unit-specific parameter adjustment process starts on Feb. 28. PJM must provide a determination on the requests by April 15.
“We do want to have some sort of guidance in place during this period before it ends in case there’s any impact on any unit out there,” Hauske said. “We’re looking at a very limited-scope item.”
The committee began interest identification and the development of design components and solution options on the matrix after the vote.
