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.
Attendance was light last Thursday at a hearing on a bill to allocate funds to deal with probable upcoming droughts in Washington, but participants were unanimous in supporting the measure.
The state Senate’s Agriculture, Water, Natural Resources and Parks Committee held the hearing on the bipartisan Senate Bill 5746, introduced by Sen. Judy Warnick (R).
If passed, Warnick’s bill would allocate $2 million every two years to a new drought preparedness fund. Also, if Washington’s governor declares a drought emergency, another $3 million would be automatically transferred from the state general fund to a drought response fund.
This bill was prompted by Gov. Jay Inslee declaring a drought emergency in July 2021 for most of Washington. That declaration caught the legislature off guard with no money set aside for dealing with a drought emergency. Inslee’s declaration activated a special legislative drought committee, which was mostly helpless because it first met a few months after the legislative session — with accompanying appropriations— ended in May 2021. (See Drought Catches Wash. Officials Off Guard.)
“It was logistically very frustrating. … We need to be prepared next time,” Warnick said at last week’s hearing. In 2021, she was the chairwoman of the Joint Legislative Committee on Water Supply During Drought.
Last Thursday, representatives from the state Ecology and Agriculture departments testified in favor of the bill, saying a new drought is expected to be declared this year. State officials expect a drought to re-emerge in 2022 because Washington would require 150% of its regular rainfall through this spring just to recover the water lost in 2021 in the agricultural breadbasket of the Columbia River Basin.
Representatives from the Washington Farm Bureau and the Washington Association of Wheat Growers also supported the bill.
“Agriculture was especially impacted by heat and the drought,” testified Farm Bureau lobbyist Tom Davis. “We’ve had some growers with total crop loss,” testified Diana Carlen, representing potato and wheat growers’ associations.
Last year’s wheat crop was 46% of 2020’s harvest, the state’s lowest harvest since 1964. In 2021, the March-to-August temperatures were the third warmest in Washington history — 2.1 degrees Fahrenheit above average. Fifteen of Washington’s 39 counties posted their driest conditions ever. The easternmost quarter of the state underwent drought conditions that normally show up once or twice every 100 years.
SPP last week laid out the clearest explanation yet of its plan to expand its presence and establish an RTO in the Western Interconnection.
“We’re currently … seeking opportunities to expand existing services in the West,” Bruce Rew, SPP’s senior vice president of operations, told the Strategic Planning Committee during a discussion of its new five-year strategic plan Wednesday. “If you look at a couple of years from now, our goal is to be viewed as an attractive market service provider in the West.”
Under its five-year plan, SPP will first grow its existing services in the West, which include its real-time Western Energy Imbalance Service (WEIS) market, its role as a NERC-certified reliability coordinator and its RTO West proposal, which has attracted nine entities and is expected to become operational in 2024.
By then, SPP plans to be operating the Western Resource Adequacy Program, evaluating commitments to its Markets+ service and developing a strategy for the best expansion of transmission markets and transfer capability between the Western and Eastern Interconnections. Markets+ offers centralized day-ahead and real-time unit commitment and dispatch and “hurdle-free” transmission service to those not ready for full RTO membership. (See Implementation Underway for NWPP’s Western RA Market.)
In 2026, SPP plans to have an established RTO in the West, with business development and market initiatives ongoing in the Desert Southwest, Basin and Northwest regions.
David Kelley, director of seams and tariff services, said the plan is a living document, noting “themes are evolving quite rapidly.”
“As that continues to play out in the West, we’re going to need to be able to adapt, so this is certainly not written in stone,” Kelley said.
Board Chair Larry Altenbaumer said the plan’s metrics should focus on value created for both legacy members and the Western members. “I think it is certainly equally important that we focus on the value that our existing membership is deriving from the expansion in the West,” he said.
Several SPC members pointed out the challenges SPP may encounter in the West from entities leery of RTO membership. They also warned staff to counter fears that the Board of Directors will favor its Eastern members over the West.
“Certainly, there are concerns and challenges [in the West] and it’s dependent upon each party that you talk to and what their position is,” Rew said. “Part of the overall strategy and approach is to work through those challenges as we move forward, whether it’s the RTO expansion to expansion of the existing WEIS market or even working with the WRAP.”
Counterflow Optimization on Hold
Committee members sided with stakeholders and staff in deciding to keep the current market construct, rather than adding counterflow optimization to the congestion-hedging process, as recommended three years ago by the Holistic Integrated Tariff Team (HITT). (See SPP SPC Takes on Congestion Hedging Issues.)
The HITT’s recommendation to add counterflow optimization — limited to excess auction revenue — to SPP’s market mechanism that hedges load against congestion charges has become an issue with no solution since its board approval in 2019. The proposal, which would essentially keep system transmission flows between two points balanced, was meant to address stakeholders’ and staff’s concerns about how congestion rights instruments are awarded and the current process’s efficiency.
The Market Working Group was tasked with developing a policy paper. Education workshops were held for the board and SPC, which created an advisory team to move the recommendation forward. Last year, consulting firm Nexant was charged with providing a root-cause analysis that found it to be the “latitude and pattern of nominations submitted to the annual allocation.”
An SPP 2025 future study found market participants’ hedging positions will change in coming years thanks to new topology, HITT initiatives and the changing generation mix. The study indicated a net positive value for all load-serving entities with counterflow optimization.
SPP’s Market Monitoring Unit weighed in during the MWG discussions, saying it does not endorse counterflow optimization and the grid operator and stakeholders should identify alternatives to congestion-hedging issues that carry less risk.
“There are other options that are less complex, less risky, and easier to unwind to address counterflow optimization,” MMU Executive Director Keith Collins said.
The Monitor said the proposal doesn’t give participants a say in the amount of counterflow they receive and there is no way for them to avoid being affected by optimization even when they opt-out. It also said auction participants will adapt to the market changes, which will affect auction revenue. It also said auction participants will adapt to the market changes, which will affect auction revenue.
Arkansas Electric Cooperative Corp.’s Andrew Lachowsky recalled an MWG meeting at which the MMU’s John Luallen referred to the proposal as “a risky, expensive redistribution of wealth.”
“I hope I [got] the quote verbatim,” Lachowsky said.
In the end, the MWG was unable to reach consensus to approve counterflow optimization and voted in 2020 to keep the current market construct. Although they acknowledged that counterflow optimization would benefit LSEs, staff also recommended keeping the current construct, noting some market participants want to review the transmission service process for efficiencies.
Although the HITT recommendation was brought back to the MWG “time and time again,” SPP’s Micha Bailey said staff were unable to gather membership support.
“We can’t get the majority there, so that’s why we said we need to keep the current market construct,” Bailey said. “We need to move on and see what other efficiencies we can garner.”
“It was a pretty tough, complex subject,” the Nebraska Power Review Board’s Dennis Grennan, a member of the advisory group, told the SPC.
“This process is a stream of different processes,” Nexant’s Joseph Bright said.
SPC Chair Mark Crisson called for a “cooling-off period” to rethink counterflow optimization.
“I would request [that] sometime this year, we put our heads together … to talk about how we consider examining this issue again, and whether there are issues besides or in addition to counterflow optimization that we consider,” he said.
“We see the issues there. We just haven’t seen where the organization over the last couple of years has been able to coalesce around a solution or a change that would be agreeable to the organization,” Rew said. “We’ll probably be [able to reach consensus] at some point a year from now because that’s what the goal for this was.”
The SPC endorsed two other HITT recommendations: an effectiveness study of SPP’s new three-phase generator interconnection process that began in 2019, and a working group’s tariff language establishing cost allocation and rates for energy storage resources (ESR).
The new GI process addresses overwhelming demand for service by providing incentives to accelerate the study process and avoid multiple restudies. (See FERC OKs New SPP Interconnection Process.)
However, staff said only one cluster study of interconnection requests has been partially completed after restudies of previous clusters delayed full implementation. A second cluster is expected to finish its first phase this month.
Staff compared the three most recent clusters that went through the legacy process with the three-phase process’s first two studies. Principal engineer Steve Purdy said multiple restudies were avoided, with 41% of the IC requests remaining after two iterations, compared to 65 to 77% in the three legacy clusters.
“It appears the three-stage process had the desired effect,” Purdy said. “We were able to get a more stable group of requests in the cluster quicker, and we were able to move on to these later studies more efficiently.”
That said, the two studies currently being evaluated may be the only ones that go through the three-stage process. Purdy said the GI queue backlog mitigation procedure docket before FERC and SPP’s transmission-planning improvements will eventually supersede the three-phase study.
The Regional State Committee is reviewing tariff language for ESRs’ cost allocation and rates developed by the Cost Allocation Working Group
The Markets and Operations Policy Committee earlier approved a revision request (RR476) that will treat ESRs as transmission assets. The SPC conditioned its endorsement upon the RSC’s approval of RR476 in July.
Task Force Addressing Winter Storm Recs
COO Lanny Nickell told the committee that a task force has begun working on recommendations from SPP’s report on last year’s winter storm, when thermal plant outages forced the grid operator to order its first-ever load sheds. (See “Grid Operator Releases Report on Performance During Winter Storm,” SPP Board of Directors/Members Committee Briefs: July 26-27.)
The Improved Resource Availability Task Force (IRATF), comprising members and state regulators, is working to recommend policies that address the report’s 26 Tier 1 recommendations as well as fuel assurance, resource planning and availability issues. The group has completed two of the recommendations and another 17 are in progress.
“This effort is going to take a lot of work, and there’s a lot of debate. A lot of it has already begun with the task force,” Nickell said.
Southwestern Public Service’s Bill Grant asked that the group consider force majeure issues that arose during last February’s winter storm, when natural gas pipeline companies were unable to meet contractual terms and provide fuel to some gas plants. Nickell said the task force will address the issue when it next meets.
“We’re using the IRATF as that platform [between the electric and gas industries], as it touches both the regulatory committee and our membership,” Nickell said.
“I feel like we’re obligated to do it,” SPP CEO Barbara Sugg said. “If the IRATF is not the right group, we’ll take another tack. We can’t just wait for something to happen organically.”
The report also made 92 Tier 2 and 3 recommendations. Eight of those are complete and 13 are in progress.
Crisson Takes the Chair
The meeting marked the first for Crisson as SPC’s chair and the first for Oklahoma Gas and Electric’s Usha Turner and WAPA’s Sanders as committee members.
Board member Crisson took over the chairmanship role from Altenbaumer, who was quick to point out he left no open action items after his two years leading the committee.
“I just want to let you know I gave you a clean slate,” Altenbaumer said.
Daniel Brooks thinks the energy industry is going about resource adequacy the wrong way.
With hundreds of gigawatts of new renewable power, widespread electrification and an enormous buildout of transmission all expected in the next decade, “the question that gets asked often is how do we maintain the reliability and resiliency of the grid with such a massive transformation? And that is completely the wrong question,” said Brooks, vice president of integrated grid and energy systems at the Electric Power Research Institute (EPRI).
“Resiliency is not a barrier to achieving decarbonization; it is a prerequisite,” Brooks said during a Thursday press call. “The question that we have to be asking is not how to maintain the existing reliability, but how do we actually increase the reliability and resiliency with that massive increase in the dependence on the grid” as electricity provides more of the nation’s energy.
Brooks was one of four EPRI executives speaking on the call, highlighting the work of the organization and the trends and priorities that will drive the U.S. energy transition in 2022 and beyond.
For example, expanding and upgrading the grid will also be essential for developing and optimizing other low- and no-carbon technologies, said EPRI CEO Arshad Mansoor. “We need to make sure that the resources we have … the hydro, the nuclear, not only remain in operation but we are operating them so we are getting more from them,” he said.
Held three days after the Rhodium Group made headlines with its announcement that U.S. carbon emissions were up 6.2% last year, the EPRI call was nonetheless upbeat and optimistic about the country’s ability to cut its greenhouse gas emissions 50% by 2030.
Mansoor said that ambitious target, set by President Joe Biden at the UN Climate Change Conference (COP26) in Glasgow, was “a clear indication globally that our ambitions for a clean energy transition, our aspirations are becoming more tangible.”
“We’re seeing large industries that consume a lot of energy focusing on clean energy,” he said. “So now you’re bringing industry together with the electricity sector, just like they’re bringing the transportation sector [together] with the electricity sector, so collaboration and innovation become the theme of this transition.”
Thus, in the wake of recent extreme weather events and the resulting power outages in California and Texas, EPRI launched a new initiative on resource adequacy for a decarbonized future, enlisting a range of industry stakeholders, including NERC, to look at the metrics and methods used to assess risk.
“What’s clear is the way that we’ve actually conducted resource adequacy assessments in the past — with the changing resource mix and with the changing climate and extreme weather that we’re exposed to — those methods just may not expose the actual risks to the electricity grid going forward,” Brooks said.
The industry needs to rethink resource deployment, he said. “What are the right metrics? … How do we actually represent the performance of all of the different supply and demand resources under the context of that changing weather and climate? … How do you take that information, overlay that on to a particular utility grid and determine what the impacts are on the grid and then start to look at the investments that are needed to ensure that it is more resilient?”
Affordable, Equitable Transition
Along with grid resilience, Mansoor believes transportation electrification is going to be a key driver of the transition. It is, he said, “what will make this clean energy transition affordable and equitable.”
With U.S. automakers rolling out a range of electric vehicles, Mansoor sees EVs reaching price parity with gas-powered cars within the next three years. A family of four, spending a total of $4,500 per year on energy — including electricity, natural gas and gasoline — could save $1,000 a year by buying an EV, creating a major economic stimulus, he said.
The caveat is charging infrastructure, or the current lack of it, but Mansoor was again optimistic about state programs and the $7.5 billion for EV charging in the bipartisan Infrastructure Investment and Jobs Act.
At the same time, EPRI’s view of the energy transition encompasses nuclear, green hydrogen and the mitigation of coal and natural gas emissions, all technologies offering opportunities for the U.S. to innovate and compete in global markets. Neva Espinoza, vice president of energy supply and low-carbon resources, talked up a range of EPRI initiatives focused on accelerating the development and deployment of low-carbon technologies, including those that are not yet available. Just one example, the 2021 launch of EPRI and Georgia Power’s Ash Beneficial Use Center, which “allows for testing and validation of emerging policy or technologies that can help address residual coal products as we move forward,” Espinoza said.
The closing of coal plants has also led to a greater dependence on natural gas, Espinoza said. “We need to better understand methane, carbon, NOx emissions and other emissions profiles, how to characterize them, how to measure them and, of course, how to mitigate them,” she said.
Projects such as the New York Power Authority pilot on blending hydrogen with natural gas to generate power “will be critical as we think about integrating new low-carbon fuels into our energy system, understanding their operational profile, understanding overall air impacts, understanding overall safety impacts as we move forward to operationalize them and bring them into the energy system,” she said.
Multiple Paths to Decarbonization
Calling in from Abu Dhabi, Neil Wilmshurst, EPRI’s senior vice president for energy system resources, stressed the importance of looking beyond the energy transition in the U.S. and leveraging international collaboration as a “force multiplier.”
Tracking the energy transition in the Middle East is “a really, really educational thing,” Wilmshurst said. “You have tremendous solar installations. You’ve got countries entering into new-build nuclear issues. You’ve got people with oil-based economies thinking, ‘What does the future look like in 20, 30, 40 years?’”
Wilmshurst also focused on nuclear issues. First on keeping the existing U.S. fleet in operation “as much as possible, as much as feasible.” And second, on developing smaller, modular or micro reactors, particularly to produce hydrogen. Pointing to the advanced nuclear demonstration projects being supported by the Department of Energy, he said, “We need to have reactors being built, [and] hopefully operational in the next seven to eight years.” (See Strong Bipartisan Support for Advanced Nuclear at Senate Hearing.)
But the energy transition in the U.S., while irreversible, still faces political obstacles, most prominently the stalled Build Back Better Act and the federal tax incentives it contains for diverse clean technologies.
Confronting the current political landscape, Espinoza said, EPRI tries “to look above and beyond what those potential implications can be and what is required for different technologies.”
EPRI’s research has looked at mapping out multiple pathways to decarbonization, based on different assumptions and sensitivities, she said. “There will be different mixtures of technology. We know reliability and resiliency will be critically important; we know energy efficiency will be critically important; we know the electric sector decarbonization will enable economy-wide decarbonization,” she said.
“So, the sensitivities and the political and policy decisions can tweak the overall pathway,” Espinoza said. “But still those resounding, underlying findings remain the same.”
