Multiple “paradigm shifts” in the way New England produces and consumes energy could lead to thousands of miles of overloaded transmission lines, according to the preliminary results of ISO-NE’s 2050 Transmission Study.
The study, initiated by the grid operator in response to a request from the New England States Committee on Electricity for longer-term transmission planning, was designed to examine the next few decades as the region continues to ramp up its decarbonization efforts.
It found that as the region moves from a summer-peaking area to winter-peaking, increases its use of renewables and doubles peak power consumption, about half of its 9,000 miles of lines could be overloaded.
“Significant new transmission will be needed to reliably serve load under the assumptions analyzed in this study,” ISO-NE said in its presentation to the Planning Advisory Committee on Wednesday.
The most challenging scenario is the 2050 winter peak, in which overloads are caused primarily by high heating load and a shortfall in supply requires new resources.
Regional discrepancies also pop up in the study. “The paths between north and south would need significant upgrades to transfer surplus generation in Northern NE to generation-deficient Southern NE,” ISO-NE said. Other possible solutions include relocating large amounts of generation from north to south or putting more offshore wind in the southern part of the region.
The RTO is planning to perform further analysis to determine if summer-only overloads can be solved by different solar resource distributions, and to develop possible transmission solutions.
The Vermont House of Representatives passed a bill (H.715) Thursday that would direct the Public Utility Commission to create a clean heat standard for reducing greenhouse gas emissions in the state’s thermal sector.
A CHS is part of a suite of recommendations issued in December by the Vermont Climate Council in its initial Climate Action Plan to meet the GHG reduction mandates of the 2020 Global Warming Solutions Act (GWSA). In Vermont, about 70% of the thermal sector uses natural gas, fuel oil and propane, which subjects Vermonters to “fuel price volatility,” said Rep. Timothy Briglin (D), chair of the House Energy and Technology Committee. (See Vt. Lawmakers Working on Clean Heat Standard Bill.)
Fuel oil prices in the state have increased 96% since last winter, Briglin said during a debate on the bill in the House on Wednesday.
Opponents of the bill, however, are concerned that the standard will further increase fuel costs and have no clear climate benefits.
“This bill is designed to impose a hidden carbon tax on heating oil … and supposedly meet the arbitrary carbon dioxide emission reduction requirements” of the GWSA, Rep. Terri Williams (R) said.
The standard could increase fuel costs by an estimated 1.5 to 2%, based on comparable standards, such as Vermont’s Renewable Energy Standard, according to Briglin.
“That’s a modest increase relative to … the extraordinary increase in prices that we’ve seen Vermonters pay in just the last two or three weeks,” he said.
Rep. Arthur Peterson (R) expressed doubt during Wednesday’s session that Vermont’s efforts to reduce thermal emissions will have a positive effect.
“We’re 50th in the nation in the production of carbon, and the change we make [with a clean heat standard], in my opinion, won’t affect the world’s climate at all,” he said.
The bill would direct the PUC to create a system of tradeable clean heat credits that natural gas utilities and fossil-based heating fuel wholesalers can buy or earn by reducing GHG emissions through the delivery of clean heat measures. Those measures could include advanced wood heating, cold-climate heat pumps, biofuels, renewable natural gas or weatherization.
Switching from fuel oil to natural gas would not qualify as a clean heat measure.
Each credit created under the standard would be based on the lifecycle CO2e emission reductions associated with the provision of a clean heat measure. Vermont’s current GHG inventory tracks emissions by sector within the state only. A lifecycle accounting would provide a complete picture of the energy and environmental effects of any applicable heating technologies under the standard.
If the bill is enacted, the PUC would establish a docket in August for CHS development, resulting in an order in mid-2024 that implements the standard in January 2025. Clean heat measures implemented this year would earn credits under the standard, according to Briglin.
“Early action credits are important not only because we want as many emissions-reducing actions as early as possible, but because it will allow for a buildup of credits in the market in the early years of the program and lower the cost of compliance for obligated parties,” he said Wednesday on the House floor.
LANSING, Mich. — The state is behind many others in developing electric storage systems and should start taking steps to develop 4 GW by 2040 to both “ensure grid reliability and avoid curtailment of renewable energy generation,” a report released this week said.
The report, prepared for the state’s Department of Energy, Great Lakes and Environment (EGLE), also called for Michigan to reach both a short-term goal of 1 GW of storage by 2025 and a midterm goal of 2.5 GW by 2030. Storage is needed both behind the meter, in home and commercial building renewable energy setups, as well as in front, it said.
To meet the goals, the report outlines a series of 56 different policy actions that should be taken by state officials between now and 2040.
The report was developed by a project team including EGLE, the Institute for Energy Innovation, the Michigan Energy Innovation Business Council and 5 Lakes Energy, and overseen by Michigan State University professor of civil and environmental engineering professor Annick Anctil. It said that the state is taking major steps to decarbonize, with a goal of carbon neutrality by 2050, but it is not keeping pace with other states in developing new storage.
Storage will also help Michigan’s economy, the report said. “As the increasingly electrified automotive manufacturing capital of the country, Michigan’s economy stands to benefit from increased demand for energy storage technologies, including for those energy storage technologies that can be used for both mobile and stationary applications,” the report said. “There are currently 11,400 jobs in Michigan in transportation electrification, representing the largest transportation electrification workforce outside of California. Putting policies in place to support energy storage deployment will serve to grow Michigan’s supply chains in energy storage and transportation electrification — both of which promise to be large global markets.”
The state was one of the first to develop a major storage center in the Ludington Pumped Power Storage Plant along the shores of Lake Michigan in 1973.
Public Service Commissioner Katherine Peretick, whose professional background is in the storage industry, agreed that the state began ahead of others in terms of overall storage efforts, “but in terms of newer technologies, we are lagging behind other” locations.
The PSC, helped by the U.S. Department of Energy, has begun a study to evaluate where and how large-scale energy storage systems should be developed across the state, Peretick said. The researchers conducting the study will look at how the facilities “fit with our grid, with our load profile, with our generation mix [and] our utilities,” as well as give guidance on where such facilities should be built.
Despite its critical need as energy generation moves more toward renewable sources, Peretick said there hasn’t been much discussion overall on storage issues, but that is now changing. Last month, Peretick testified to the Michigan House Energy Committee on storage issues, and she said legislators asked a series of “excellent” questions on a wide array of topics, including safety.
Along with technical issues, the report goes into issues such as monetizing storage at both the wholesale and retail levels; changing legal and regulatory policies that currently focus on fossil fuel-based generation; how to properly value storage; how it fits into the state’s renewable energy standards; and incentives to develop storage systems. In each of these areas, the report looks into how other states are acting on them.
“In some cases, energy storage is simply not contemplated in Michigan policy and regulatory frameworks, while in other cases, regulations and policies place actual limitations on how energy storage can best participate in the market for electricity,” the report said.
“Michigan needs to prepare for and support the deployment and use of energy storage at the level that will be necessary to support and balance our state’s future electricity grid. This will require leadership, business innovation, appropriate incentive programs, regulatory changes and new state laws.”
In its first Lessons Learned report of the year, NERC said the winter storms of February 2021 and resulting mass outages in Texas illustrate the benefits of allowing transmission operators (TOPs) greater flexibility to manage firm load shed operations.
The document builds on a FERC and NERC joint report on the February storms, a section of which discussed the difficulties experienced by TOPs managing the load shed ordered by ERCOT on Feb. 15 in order to keep the power grid stable. Particularly challenging were the situations — which became more frequent as the day wore on — when ERCOT began to order TOPs to “implement controlled outages of electric circuits normally reserved for” underfrequency load shed (UFLS) operations.
Grid planners “typically exclude load connected to UFLS relays from manual load shed plans whenever possible,” the Lessons Learned report said, because these circuits are critical to bringing the grid back under control during an underfrequency event. Underfrequency programs are normally designed to “shed a predetermined percent of load at specific frequency setpoints.” If this load has already been taken offline manually, the system cannot function as intended and a frequency excursion becomes more likely.
ERCOT requires at least 25% of load — not including critical loads such as hospitals, military facilities and police stations — to be reserved for automatic load shedding schemes, including UFLS. However, at times on Feb. 15 and 16, load shedding in the region progressed to the point where UFLS resources represented more than 60% of the remaining load left online, and the grid was already dangerously close to a complete breakdown. (See ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)
This situation was a significant risk because it was far outside the bounds of any scenario envisioned by grid planners. UFLS relays were designed to take no more than 25% of load offline, but here they had control over more than half of the grid at some points. As the report said, “an actual UFLS operation while the system is in this state could lead to an overshoot in frequency and further system instability.”
In response to these conditions, TOPs requested and received approval from their reliability coordinators (RC) to use UFLS circuits to meet ERCOT’s load shed orders; ERCOT’s protocols and operating guides have since been revised to “specifically allow entities to shed UFLS load as long as they continue to meet their UFLS obligations.” NERC’s report said this strategy might be useful on a wider basis, and that RCs and planning coordinators should consider revising their own UFLS programs to allow the practice.
“Having this operational flexibility would increase the amount of load available for rotation, spread the burden of outages to a larger pool of load, and reduce customer outage times,” NERC said. In addition, “taking this approach of including UFLS circuits during load shed lowers the risk of an overshoot in frequency if UFLS operates when actual UFLS loads substantially exceed the required obligations.”
The organization also mentioned that rather than giving the same treatment to all loads designed as critical, TOPs can consider adapting their strategies to the specific requirements of each situation. If a particular load can “withstand outages of several hours without having negative impacts,” it might be considered for load shed of a shorter duration.
While the Biden administration has touted the infrastructure bill approved last year as a way to address climate change, state and local discretion over highway spending could actually cause increased emissions, an analyst told the Maryland Greenhouse Gas Mitigation Working Group Tuesday.
James Bradbury, mitigation program director for the Georgetown Climate Center, told the working group that the Infrastructure Investment and Jobs Act will provide about $599 billion in funding for surface transportation for 2022-26, giving state and local governments discretion to spend as much as 27% of it — or as little as 4% — on new highway construction.
According to the Climate Center’s analysis, spending on new highways could increase emissions beginning in 2026, resulting in a 1.6% increase relative to the baseline by 2032.
“That’s because building more roads consistently results in more traffic — an ‘if you build it, they will come’ effect known as ‘induced demand,’” the center said. “In short, traffic expands to fill the new lanes within a few short years, bringing with it more pollution.”
In contrast, limiting new highway spending to 4% of the total would reduce emissions by 1.3% from the baseline.
“This may not sound like much, but it’s substantial for nationwide transportation emissions in just five years,” Bradbury said.
The Infrastructure Investment and Jobs Act, which provides about $599 billion in funding for surface transportation, gives state and local governments discretion to spend as much as 27% of it — or as little as 4% — on new highway construction. | Georgetown Climate Center
Between 2010 and 2020, an average of 15% of obligated federal funds administered by the Federal Highway Administration was used for highway expansion projects, including new construction, relocation, reconstruction (added capacity), new bridges and major bridge rehabilitation.
“We think the real-world outcome will end up somewhere in between” the high-emission and low-emission scenario, Bradbury said. “Certainly it’s too soon to say where things are headed; It’s a five-year spending bill. But projects are already being funded.”
Although formula funding programs have long provided flexibility for highway dollars to be used for emission-reducing investments like transit and electric vehicle charging, it’s not required by law.
“So those decisions are really largely left up to the states to make,” Bradbury said. “To ensure that investments result in meaningful [emission] reductions, concerted efforts are going to be needed across all levels of government, the state [departments of transportation] will obviously play a crucial leadership role, but governors, legislators, local governments, municipal planning organizations will also be a part of these decisions,” he added.
Telecommuting ‘A Wash’ on Emissions
Bradbury said the increase in telecommuting because of the pandemic has not had a significant impact on emissions because of “rebound effects.”
“While you have some people working from home, oftentimes, those people … might hop in their car at lunchtime and drive to the mall and do some shopping, and the net effect are they tend to have more trips near home,” he said. “You know, those commutes to work oftentimes would be multi-purpose: They pick up kids on the way home and stuff at the grocery store on the way home, as opposed to doing lots of local individual trips. … The net effect of telecommuting, working from home, on VMT [vehicle miles traveled] tends to be somewhat of a wash.”
Angst over EV Costs
Michael Powell, co-chair of the working group, questioned whether funding supporting EV charging would be better spent on subsidizing the vehicles.
“I just spent a lot of time in meetings with building owners and developers who are complaining that they’re putting in electric charging stations and nobody plugs in there,” he said. “I’m beginning to believe that it’s not an infrastructure issue in the short term: it’s the cost of the cars. … I’m beginning to think that we’re getting the cart before the horse here — that if we could lower the cost of the vehicles, people would solve a lot of the charging problems by putting just level one chargers in homes and workstations.”
The Rocky Mountain chapter of the Energy Bar Association this month hosted a panel to discuss the intricacies of creating an organized market in the West.
Erin Overturf, Western Resource Advocates | Energy Bar Association
Each panelist at the March 3 “Winter Energizer” gave a short presentation on their organization and its part in the energy transition. And each made it clear that an organized market would be crucial to reaching the region’s decarbonization targets.
“The aim of this conversation is to decarbonize … the power system as quickly as possible, as reliably and as cost effectively as we can,” Erin Overturf, director of clean energy programs for Western Resource Advocates, said. “We see regional markets as … a key tool to be able to achieve those aims.”
But the panelists acknowledged that the political diversity of the West means designing this market will not be a simple undertaking. Being flexible enough to accommodate states and their varied interests is key to creating a system that benefits states, utilities and ratepayers alike.
Carrie Simpson, Xcel Energy Colorado | Energy Bar Association
“Letting states speak for themselves about what it is that they need to be able to get out of a regional market in order for it to work, I think is absolutely critical,” Overturf said.
But designing a market that is mutually beneficial for all participants would only be the first step to widely decarbonizing the West. To curb greenhouse gas emissions more rapidly, interregional transmission will need to be constructed throughout the entire footprint. And as seen with MISO and SPP, an organized market does not inherently lead to the construction of interregional transmission, said Carrie Simpson, director of western markets for Xcel Energy Colorado.
“I don’t know that an RTO automatically just opens the door for transmission because I think it’s all about what the rules are and what the policies are and what the cost allocation rules are,” Simpson said.
Rachel Bryant, PA Consulting | Energy Bar Association
Though membership in an RTO may improve a utility’s situational awareness and allow it to better assess what kind of interregional transmission projects may be most beneficial, it does not necessarily ease the process of constructing these projects.
The main drawback states and utilities face when considering an organized market is the fear of a lack of autonomy. Rachel Bryant, a principal consultant with PA Consulting, said states have seen how some markets in the East have been rigid and were designed without diverse state policies and adaptability in mind.
“Breaking through that sort of stigma that you’re going to lose all your rights and be forced to do things you don’t want to do — I think is a huge part,” she said. “I feel like markets almost need a marketing manager to make this seem appealing to the people who are most resistant.”
PJM stakeholders at last week’s Planning Committee meeting endorsed an update to the generation deactivation process as some members asked the RTO to slightly modify the proposed timing language.
The issue charge, developed by PJM, received 148 votes in support (99%), with two members voting against it. In a vote asking stakeholders if they preferred the proposal over maintaining the status quo, 109 (83%) favored the proposed and 22 the status quo.
The tariff currently provides 90 days advance notice and 30 days to complete deactivation studies, Egan said, causing “insufficient” time for PJM staff to determine adverse impacts on reliability if more than one deactivation notice is made in a single study period. Industry trends and state energy policies are increasing the number of deactivation notices, Egan said, putting even more pressure on staff to finish deactivation studies in a timely manner.
PJM’s issue charge calls for tariff and manual changes that “provide more time to complete analyses, allow additional and improved studies, and provide the ability for more efficient work control and consistency regarding timing of deactivation studies,” Egan said.
The proposed deactivation process would establish quarterly study times for requests, with periods beginning Jan. 1, April 1, July 1 and Oct. 1. PJM staff would study deactivations as a batch. For example, the Jan. 1 study period would result in a reliability notification at the end of February.
PJM generation deactivation requests from June-August 2021 | PJM
Egan said the quarterly schedule would allow sufficient time for additional required seasonal, interim year and short-circuit analyses, scheduling upgrades and cost estimates. It would also allow PJM operations to identify additional needed operational measures, he said.
As a comparison to other RTOs and ISOs, Egan said MISO requires advance notice of 26 weeks for a deactivation, and the studies include 75 days to identify issues and 26 weeks to complete the deactivation study. NYISO requires advance notice of 365 days for deactivation, and studies are conducted in the subsequent quarter.
Becky Robinson of Vistra said she had concerns about possible upcoming actions on generation plants through EPA’s Coal Combustion Residuals Rule, which required most of the country’s 500 unlined ash pits to stop receiving waste and begin to close by April 2021. EPA began reinforcing the rule, established under President Barack Obama, this year after being targeted for rollback under President Donald Trump. (See EPA Coal Ash Enforcement Impacts Midwest Coal Plants.)
Robinson said a plant could be ordered to stop using ash pits within 135 days, effectively shutting it down and conflicting with the new deactivation timing. Resources affected by the rule have made compliance filings, she said, but EPA has yet to act on most of them, leaving the timing of their deactivation in limbo.
Paul Sotkiewicz of E-Cubed Policy Associates said he agreed with Robinson’s assessment of the EPA rulings. Other enforcement actions that can take place on a unit-specific basis through EPA or state rules don’t necessarily have well defined timelines for actions, he said.
Sotkiewicz recommended that PJM insert tariff language that “doesn’t pin” a generator down to a specific time frame and to create exemptions if a unit is forced to deactivate through actions of EPA or states. He said a goal of the new timeline should be to avoid running afoul of EPA or state environmental agency rulings.
“I’m trying to save everybody a lot of work and heartache here by putting in some language,” Sotkiewicz said.
Dave Souder of PJM said the RTO was willing to add appropriate tariff and manual language before the update is voted on at the Markets and Reliability Committee meeting in April.
Gov. J.B. Pritzker signed the legislation Sept. 15. It requires all investor-owned baseload coal-fired power plants and remaining oil peaker turbines in the state to shut down by 2030. (See Illinois Senate Passes Landmark Energy Transition Act.) Gas turbine plants, including ones currently under construction, must also close by 2045 under the terms of the bill, although the state has the option to retain plants that are critically needed.
PJM created a draft reliability guidance document to send to Illinois regarding the law and its impacts on the region. (See “Illinois CEJA Reliability Guidance Update,” PJM Operating Committee Briefs: Feb. 10, 2022.)
Egan said PJM has already identified retirement assumptions for two study periods in Illinois, with 9,905 MW impacted from the present until 2030 and 5,845 MW impacted from 2035 until 2045 for a total of 15,750 MW of generation in the state.
PJM will conduct additional sensitivity studies later this year, Egan said, with methods similar to a deactivation study using Regional Transmission Expansion Plan (RTEP) criteria for thermal and voltage studies. The RTO plans to have the study completed by July.
Egan said PJM is coordinating with MISO to conduct a study on the deactivations and have agreed to use a 2031 base case of the Multiregional Modeling Working Group (MMWG). The RTOs will model already announced generation deactivations and assumed deactivations based on the Illinois legislation. The models will also use projects in the interconnection queues for the generation replacement from deactivations.
PJM will work with the affected transmission owners for case assumptions and identifying any mitigation upgrades, schedules and costs resulting from the deactivations, Egan said.
Jason Connell, director of infrastructure planning for PJM, discussed the possibility of forming a new subcommittee to continue discussions of interconnection process changes after work in the Interconnection Process Reform Task Force (IPRTF) finishes.
PJM’s proposal regarding the development of new rules for the interconnection process that came out of the IPRTF won near unanimous support from stakeholders at the January PC meeting. (See “New Interconnection Rules Endorsed,” PJM PC/TEAC Briefs: Jan. 11, 2022.)
Connell said PJM staff have had discussions for several weeks internally and with stakeholders about creating a new subcommittee to continue discussions on additional interconnection issues identified in the task force. PJM is working on formulating a subcommittee charter to bring to the April PC meeting for a first read. Connell said the intention is to begin holding meetings of the new subcommittee by June and establish a near-term agenda if it’s endorsed by stakeholders.
Manual 14F Update
Joseph Hay of PJM’s infrastructure coordination department provided a first read of Manual 14F: Competitive Planning Process regarding the biennial review. Hay said the review involved two main changes to the manual.
First, the critical energy/electric infrastructure information (CEII) in Manual 14F was referenced over to Manual 14B because that manual is the source document for PJM’s CEII. Hay said the change will eliminate the requirement to edit Manual 14F whenever a change is made to 14B.
The second significant update was that the Secure File Transfer Tool used to submit all proposals was replaced with a requirement to use “Competitive Planner” to submit proposals. Hay said the Secure File Transfer Tool is still available for stakeholders and will be used to submit supplemental data on an “as needed” basis.
Stakeholders will vote on the manual changes at the April PC meeting.
Manual 21A Revisions
Joshua Bruno, senior analyst in PJM’s resource adequacy planning department, provided a first read of revisions in Manual 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis. The revisions are part of an effective load-carrying capability (ELCC) model run timing update and other changes to reflect the continuation of the current method of providing unit-specific backcasts only as requested.
The committee will be asked to approve an issue charge and problem statement and endorse the proposed manual revisions as part of the “quick fix” process at the April PC meeting.
PJM rules allow voluntary submission of unit-specific wind and solar parameters for development of backcasts for newer resources, Bruno said, but current manual language has an expiration date of March 1 for voluntary submissions. The submission of unit-specific parameters for all wind and solar is mandatory after the expiration date.
The alternative method is to use a zonal backcast, Bruno said, which PJM has found to be an “adequate” process.
The quick fix calls for removing the March 1 expiration date, Bruno said, which would allow PJM to continue the current practice where newer resources have the ability to elect to submit the unit-specific data or use the zonal backcast.
Bruno said another change included in the proposal is that the 2025/26 Base Residual Auction would use the December 2022 ELCC run instead of the older July 2022 run. He said the change would allow for the most recent data to be used for the when calculating the accredited unforced capacity (UCAP) for the 2025/26 BRA.
Aaron Berner, PJM manager of transmission planning, provided an update on the New Jersey offshore wind state agreement approach (SAA) proposal window at last week’s Transmission Expansion Advisory Committee meeting.
Berner said PJM has divided Option 1a, which involves onshore upgrades to existing transmission facilities, into several different geographical clusters to help in the review process. The clusters include: Northern New Jersey; Central New Jersey; Southern New Jersey; the Southern New Jersey border; and the Pennsylvania-Maryland border.
PJM is also continuing a market simulation analysis for the project combinations selected for a reliability analysis, Berner said, along with constructability and independent cost reviews of both the onshore and offshore proposals.
Berner said the New Jersey Board of Public Utilities recently posted a notice regarding a series of stakeholder meetings to collect stakeholder input on the evaluation of the transmission proposals. The first meeting takes place on March 22 with a focus on the SAA goals, the evaluation process and a review of the applications received.
Potential solution options for offshore wind projects in New Jersey | PJM
A second meeting on March 30 deals with how the potential transmission projects will integrate with future offshore wind projects.
Generation Deactivation
Phil Yum of PJM’s system planning modeling and support department provided an update on two recent generation deactivation notifications.
Generation deactivation requests in PJM from 2018-present | PJM
The 1.9-MW Ottawa County Landfill in Ohio’s American Transmission Systems Inc. (ATSI) transmission zone requested a deactivation date of May 31, while the 81-MW Essex 9 gas-fired generation unit in the Public Service Enterprise Group zone in New Jersey requested a deactivation date of June 1.
Yum said reliability analyses for both units are currently underway.
PJM wants the Resource Adequacy Senior Task Force (RASTF) advance discussions to evaluate the RTO’s need for procuring additional reliability-based generation as more intermittent resources are integrated into the grid.
Chris Pilong and Alex Scheirer of PJM provided a first read at last week’s Operating Committee meeting of a proposed “initial direction” regarding reliability products and services required in the RASTF charter.
Pilong said stakeholders began looking at the list of generator “reliability attributes” at the beginning of the year, examining PJM’s renewable integration studies and papers to determine the recommendations for addressing potentially new reliability services and next steps in the process at the RASTF and other committees and task forces.
Pilong said stakeholders will discuss reactive capability and supply issues in the Reactive Power Compensation Task Force to make sure PJM is able to “utilize, measure and compensate the full reactive capability of synchronous and non-synchronous generators independent of their power output.” The issue also calls for discussions on the ability of all resources to follow voltage schedules and demonstrate performance.
From a regulation perspective, Pilong said, stakeholders recommend reviewing existing regulation market signals and considering future system needs as part of the regulation market redesign issue charge approved by the Market Implementation Committee. (See “RTO to Propose Review of Regulation Market,” PJM MIC Briefs: Nov. 3, 2021.)
“If the signals are going to be reviewed and looked at, we should be looking at what are the right signals for the future,” Pilong said.
Members recommended that the Energy Price Formation Senior Task Force consider how to value flexibility of generation within the existing or modified ancillary services, Pilong said, while another recommendation would have RASTF explore how to value fuel assurance for all resources that can be relied upon for “unexpected system conditions.”
Pilong said PJM and stakeholders may evaluate methods for data submission and review the existing penalty structure if data reporting requirements in PJM manuals are not followed. He said a potential problem statement and issue charge could be brought to the OC to examine manual language changes.
“We do see, in some instances, the data is not as accurate as we need it to be, especially as the fleet of inverter-based resources begins to grow,” Pilong said. “We really need to make sure we have accurate forecasts.”
Stakeholders will vote on the recommendations at the April 14 OC meeting.
UFLS Requirements Applicable to EKPC
Denise Foster Cronin of the East Kentucky Power Cooperative (EKPC) provided a first read of a problem statement and issue charge to appropriately document EKPC’s under frequency load shedding (UFLS) requirements in PJM.
Foster Cronin said EKPC is seeking stakeholder approval of limited PJM Operating Agreement, tariff and Manual 36 changes to document the UFLS.
The purpose of the UFLS requirement is to avoid an uncontrolled loss of load situation, Foster Cronin said, and the requirements establish a total percentage of load shed that must be achieved when the system frequency drops to a certain level to maintain the system.
All electric distributors must comply with the UFLS requirement established by their respective NERC region. When EKPC integrated into PJM in 2013, the cooperative was in the SERC region of the ERO.
Before EKPC’s integration, PJM’s OA documented a UFLS requirement for entities in the “PJM Mid-Atlantic Region,” the “PJM West Region” and the “PJM South Region.” But the OA was not changed with EKPC’s 2013 integration to incorporate the cooperative’s applicable UFLS requirement, and it wasn’t included in any of the regions.
In 2018, EKPC was added to the PJM West Region when the RTO worked with stakeholders to clarify the region definitions in its governing documents. However, other entities included in the PJM West Region are in the ERO’s ReliabilityFirst region, while EKPC remained in SERC, which has slightly different UFLS requirements.
Forster Cronin said a recent review of the region revisions “highlighted a potential confusion” of EKPC’s appropriate UFLS requirement. She said the oversight did not create a reliability problem or a “compliance vacuum” for the cooperative.
“There hasn’t been any gap with respect to the actual compliance and reliability,” Foster Cronin said.
Foster Cronin said EKPC has been working with PJM on the language correction issue.
The OC will be asked to approve the issue charge and endorse the proposed solution at the April meeting. The Markets and Reliability Committee and Members Committee will ultimately endorse and approve the solution and corresponding OA revisions.
“We’re hoping the committee agrees this is a pretty straightforward item and only impacts East Kentucky Power Cooperative,” Foster Cronin said.
Derin said the manual changes partially resulted from revisions in NERC standards CIP-012, COM-001 and EOP-008.
Minor changes were made throughout the manual, Derin said, including removing revision numbers from where NERC standards are referenced and replacing the term “member” with “PJM member” where applicable to keep the term uniform throughout the manuals.
In Section 2.5.6: Recovery Procedures, PJM clarified the loss of control center functionality procedures and documentation relating to EOP-008 and TO/TOP Matrix.
In Section 3.2.1.1: PJMNet Communications System, the language was clarified to ensure PJM is responsible for protecting all real-time assessment and real-time monitoring data through the PJMNet private network as the data is “in transit” between the PJM control centers and its routers. The RTO must also make sure all data is encrypted.
The committee will be asked to endorse the changes at its April meeting.
Manual Changes Endorsed
Several manual changes resulting from the periodic review were unanimously endorsed by stakeholders, including:
Manual 13: Emergency Operations, with a review of the language that added columns with winter values for estimated peak load and estimated load reduction in the voltage reduction summary table.
Manual 37: Reliability Coordination, with a review of the language that corrected Silver Run Electric to properly show as a transmission owner in Attachment A of the manual.
Lawmakers in Connecticut are taking another look at legislation that would allow auto manufacturers with an exclusive electric vehicle strategy to circumvent franchise law and sell directly to consumers in the state.
The bill (SB.214) “allows Connecticut to join 22 other states that allow all-EV-only, non-franchised manufacturers, like Rivian (NASDAQ:RVIN), Lucid (NASDAQ:LCID) and Tesla (NASDAQ:TSLA), to invest in brick-and-mortar dealerships in Connecticut,” said Kaitlin Monaghan, manager of public policy and senior counsel at Rivian.
EV-only companies would be subject to the same regulations as franchise dealers in the state under the law, if passed, according to Monaghan, who spoke Monday in support of the bill during a Transportation Committee hearing.
While current law in Connecticut requires auto manufacturers to sell their vehicles through a third-party dealership, the bill would allow the state to issue a dealer’s license to EV-only manufacturers. Under the bill, EV manufacturers would not be allowed to have a prior franchise agreement with a new car dealer or a controlling interest in or be owned by another licensed manufacturer.
“The bill allows Connecticut customers to choose the EV model and the EV purchasing experience they want,” Monaghan said. “A poll last year showed 83% of respondents support direct sales of EVs to consumers.”
A similar bill introduced in January 2021 gained some traction in the Connecticut legislature but did not pass the Senate before the end of the session. New York lawmakers are also considering a bill (S1763) that would alter dealer franchise law in the state in favor of EV manufacturer direct sales.
Recent auto sales statistics show that the presence of EV manufacturers with a direct sales approach is not hurting franchise dealerships, according to testimony by Daniel Witt, director of state and local public policy at Lucid.
“Dealers have been more profitable in the last two years than ever before,” Witt said. “That’s as Rivian and Lucid have started producing and delivering cars and as Tesla has sold more cars than ever before, globally.”
States that have allowed direct sales to customers have not lost jobs at dealerships, Kenneth Gillingham, a professor of economics at Yale University, said in testimony. “If there’s any impact at all, it’s not statistically distinguishable from zero.”
Connecticut EV owners, however, will have more money “in their pockets” because of lower costs on fuel and maintenance than for internal combustion vehicles, he said. That money, he added, will go toward in-state purchases that drive tax revenue.
Opponents of the bill in Connecticut say allowing the direct-sales model would establish two sets of rules for automobile competitors within the same market.
There is no law prohibiting Tesla, Rivian and Lucid from selling their vehicles in the state, as long as they “follow the same rules on automobile distribution that every other automaker is required to follow by law,” said Wayne Weikel, senior director of state affairs at the Alliance for Automotive Innovation, in testimony.
The franchise dealer model, however, does not work with Tesla’s approach to sales, according to testimony by Tesla Senior Policy Adviser Zach Kahn.
“By utilizing the direct-to-consumer sales model, Tesla has created a sales experience completely unlike the typical car buying experience in a dealership,” Kahn said. “We spend the time to educate our customers on the technology, answering countless questions about charging, battery performance and the like, and prepare them for electric vehicle ownership.”
Tesla’s call to change dealership laws was founded originally on its claim that the company was too small and its technology too new to compete in the existing market. But Weikel says that’s no longer the case.
An estimated 130 new EV models are due to hit the market by 2026, he said, and more companies are following in Tesla’s footsteps.
“Rivian and Lucid are asking for the same special treatment, but understand that there is a line of other startup companies right behind them,” he said.
The Maryland Senate late Monday approved legislation increasing the state’s greenhouse gas emission reduction goal to 60% below 2006 levels by 2030 — up from the current 40% target — and setting a 2045 deadline for reaching net-zero emissions (SB 528).
The Climate Solutions Now Act of 2022, which must also be approved by the House of Delegates, would target landfill methane emissions, set new energy conservation standards for buildings and require the purchase of zero-emission vehicles (ZEVs) for public school buses and the state fleet.
The bill, sponsored by Sen. Paul G. Pinsky (D), chair of the Senate Education, Health and Environmental Affairs Committee, cleared the Senate on a 32-15 vote, with all Republicans opposed.
The vote came after Pinsky last week withdrew a requirement that all new buildings use electric power, rather than fossil fuels, for space and water heating by 2024 and a mandate that new buildings be equipped to install solar energy systems and electric vehicle charging. Instead, the legislation requires the Public Service Commission to report to the legislature by September 2023 whether the electric grid can support an all-electric building code in the future.
Maryland GHG emissions and targets by year | Maryland Department of the Environment
Pinsky tweeted that the bill was “a major step forward but weakened by the utility industry that placed their profits ahead of people & the environment.”
Last year, negotiations to increase the state’s emissions-reduction target collapsed after the Senate rejected House revisions that would have set the state’s 2030 goal at only 50% of 2006 levels. (See Md. Climate Bill Dies in House-Senate Standoff.)
Among other provisions, SB 528:
Requires the Maryland Department of the Environment to adopt standards for methane emissions for municipal solid waste landfills by 2024 that are at least as stringent as those adopted by California.
Creates a Climate Justice Corps Program for 18- to 25-year-olds to work on clean energy or climate mitigation projects.
Requires a transition to zero-emission school buses: Beginning in fiscal 2024, county school boards would be prohibited from signing contracts to purchase or use any school bus that is not a zero-emission vehicle (ZEV) unless the school board is unable to obtain federal, state, or private funding to cover the “incremental costs” of ZEVs or there are no available ZEVs to meet the district’s performance requirements.
Transitions the state vehicle fleet to ZEVs: The bill sets a goal that all passenger cars in the state vehicle fleet be ZEVs by 2030 and that other light-duty vehicles in the fleet be ZEVs by 2036. It would require the state to make ZEVs 25% of all passenger cars purchased in fiscal 2023, rising to 100% beginning in fiscal 2027. Beginning in fiscal 2024, any passenger car purchased for the state fleet that is not a ZEV must be a hybrid vehicle.
Creates the Climate Catalytic Capital Fund, administered by the Maryland Clean Energy Center to promote environmental justice and to leverage private capital investment in technology development and deployment, including project planning. Minimum annual funding for fiscal 2024 through 2026 would be $5 million.
Requires annual funding of $12 million from fiscal 2024 through 2032 to help school systems cover the cost difference between meeting basic high-performance building requirements and net-zero energy requirements. Subject to funding, at least one of the schools constructed in each school system from July 2023 through June 2033 would be required to meet net-zero energy requirements. During the same period, districts would have to consider including rooftop solar panels on new schools.
Requires funding of $5 million annually in fiscal 2024-26 for projects to reduce direct GHG emissions from multifamily residential buildings.
Requires development of performance standards for “covered” buildings (non-school or historic buildings of at least 25,000 square feet) owned by the state: a 50% reduction in net direct GHG emissions by January 2030 compared with 2025 levels and net-zero direct GHG emissions by 2035. For covered buildings not owned by the state it requires a reduction of at least 30% in GHG emissions by 2035 and net-zero emissions by 2040.
The House of Delegates has been considering SB 528’s provisions in three bills heard by separate committees.
“It’s my understanding that the House is actually going to work off the Senate bill versus those three independent bills,” Kim Coble, co-chair of the Greenhouse Gas Mitigation Working Group, told a working group meeting Tuesday.
She said the Senate Budget and Tax Committee on Monday endorsed the funding for implementing the Pinsky bill. “So that is embedded in the budget at this point in time,” said Coble, who represents the Maryland League of Conservation Voters.
Working group member Sandy Hertz, of the Department of Transportation, noted that the bill passed by the Senate struck a provision making the state fleet EV targets “subject to the availability of funding.”
The bill said that “it will be done, regardless of whether or not you have the funding set aside for it,” Hertz said. “That was one thing that stood out to me as fairly impactful to us at the state level.”
