FERC this week refused a MISO interconnection agreement for a Michigan solar farm while Commissioner Mark Christie used the order to point out what he called a defect in the MISO tariff.
The commission said MISO is free to file another generator interconnection agreement for EDP Renewables’ Eagle Creek solar farm in the future (ER23-2443-001).
Currently, the parties to the failed GIA are embroiled in a dispute over how to divvy up ownership interests in the interconnection facilities and network upgrades necessary to accommodate the 120-MW solar farm.
Only transmission owner Michigan Public Power Agency (MPPA) executed MISO’s GIA. Michigan Electric Transmission Co. (METC), Wolverine Power Supply Cooperative and generation developer Eagle Creek declined to execute the GIA, which would have split ownership 33.33% apiece among METC, MPPA and Wolverine. The three jointly own the Styx-Murphy 345-kV transmission line, which will need to be extended into a new 345-kV station to connect the solar generation. The line is located on METC’s transmission system, and METC said it believes it should have sole ownership over the interconnection facilities and upgrades.
FERC ruled that while MPPA and Wolverine also are legitimate transmission owners with rights to the line, MISO’s GIA is inapplicable because it was written for multiple transmission facilities while the Styx-Murphy line is a single transmission facility, albeit jointly owned.
When it filed the GIA with FERC, MISO said Eagle Creek couldn’t sign the GIA because the final ownership interests of the network upgrade will affect how much it ultimately owes.
Ordinarily, MISO interconnection customers are responsible for all costs associated with network upgrades to accommodate their generation. When the network upgrades are rated 345 kV and above, interconnection customers can receive a 10% reimbursement.
However, METC operates under a circa-2007 grandfathered arrangement where interconnection customers might be eligible to be fully reimbursed when their projects are designated as network resources or have entered capacity contracts with a network customer. Those costs are covered by the load in METC’s transmission pricing zone.
FERC provided guidance to MISO when it refiled the GIA. It said Eagle Creek should pay for MPPA’s and Wolverine’s proposed combined ownership share of 66.66% of costs, with the 10% reimbursement due after commercial operation. Eagle Creek also initially should fund METC’s 33.33% ownership share and be eligible for the 100% reimbursement.
Christie wrote separately to disagree with METC’s exemption to the usual interconnection costs in the MISO tariff. He said while he agreed with the order because it follows the current tariff, interconnection customers should bear the cost of network upgrades necessary for their projects, not load.
“In 2007, the commission likely made a mistake by accepting the carve-out, which on its face appears to be unduly discriminatory and preferential and, most importantly, unfair to consumers, who should not have to pay a developer’s interconnection costs,” Christie wrote.
If NERC’s latest proposed cold weather standard fails another ballot round, the ERO’s Board of Trustees may have to take matters into its own hands, Chair Ken DeFontes warned at the board’s quarterly meeting Dec. 12.
DeFontes reported “with great disappointment” that EOP-012-2 (Extreme cold weather preparedness and operations) received only a 58% segment-weighted vote in favor in the ballot round that closed Nov. 30, short of the two-thirds required for approval.
NERC Board Chair Ken DeFontes | NERC
EOP-012-1 was approved by FERC in February with the stipulation that more work be done. (See FERC Orders New Reliability Standards in Response to Uri.) The commission identified several shortcomings in the standard and ordered NERC to submit a revised version for approval within a year.
Industry stakeholders have rejected EOP-012-2 before; the first time the standard went to a vote in July, it received only a 44% segment-weighted vote in favor. (See Industry Cool on Revised Winter Weather Standard.) But DeFontes warned that the latest rejection meant NERC was in danger of missing FERC’s February deadline.
DeFontes said the board still wishes for the standard to pass through NERC’s normal stakeholder process. To that end, NERC staff attending this week’s meeting of the Standards Committee will request the committee authorize another posting in January with a shortened comment period.
However, if the committee does not approve the posting, or if the standard fails to pass yet again, DeFontes said “the board will have no other choice but to invoke” its authority under section 321 of NERC’s Rules of Procedure to approve a standard without a successful ballot.
In the event that the board determines a ballot pool has failed to approve a proposed standard that addresses a FERC directive, section 321 allows the board to direct the Standards Committee or NERC management to develop a draft standard without stakeholder input. The standard must then be posted for a 45-day public comment period. After the comment period, the board can modify the draft standard in accordance with comments received and file it with FERC, with an explanation for the board’s decision.
“We continue to hope that our stakeholders will rise to the occasion once more and address these important reliability issues promptly, and [that] we will not have to invoke this special rule,” DeFontes said. “However, in the end, NERC must do what it needs to do, and that includes using all of the procedural tools that are available.”
DeFontes added that he would direct staff to “tentatively schedule a special call for the board to invoke the [section 321] rule,” because if the Standards Committee does not authorize the posting or the standard fails to pass the ballot, the board must make its decision “as soon as practicable.”
Trustee Sue Kelly and Vice Chair George Hawkins both expressed support for DeFontes’ position. Kelly said failing to fulfill FERC’s directive is a “situation that I just do not think is tolerable,” while Hawkins assured DeFontes that he had the board’s full support.
“Maybe this goes without saying, but [I want] everyone to understand that this is a unanimous, very powerful statement of all of us. … We are all supportive of you and your statement as board chair,” Hawkins said.
Standards Actions
While EOP-012-2 remains in limbo for now, the board did approve two other standards at the meeting.
CIP-012-2 (Cybersecurity — communications between control centers) was developed under Project 2020-04 following a January 2020 directive from FERC to refine CIP-012-1. The new standard adds requirements for actions to be taken in the event of loss of communications, NERC Vice President of Engineering and Standards Soo Jin Kim told the board.
The board also approved WECC regional standard VAR-501-WECC-4, which governs performance criteria for power system stabilizers in the Western Interconnection. The existing standard mandates that WECC review it at least once every five years to determine if any updates are needed; the regional entity’s Standards Committee developed several minor vocabulary and grammar changes as part of this review.
Trustees then voted to adopt NERC’s 2024-2026 Reliability Standards Development Plan, endorsed by the Standards Committee in October. Kim explained that the RSDP incorporates “certain administrative changes due to [FERC] Order 901,” which directed NERC to develop standards to improve the reliability of inverter-based resources. (See FERC Orders Reliability Rules for Inverter-Based Resources.) The changes were needed to allow “certain high-priority projects to be elevated” to fulfill FERC’s order, Kim said.
Finally, trustees approved NERC’s new working capital and reserves policy. The ERO’s Finance and Audit Committee adopted the policy recently in response to a FERC order in October authorizing NERC to expend unbudgeted funds from its operating reserves up to 5% of its business plan and budget without FERC approval, or to redirect budgeted funds without approval from certain program areas up to the same threshold (FA11-21).
Under the new policy, NERC must submit an informational filing to FERC if the amount drawn from reserves or redirected is between 3 and 5% of its budget; if the amount is less than 3%, no filing is needed.
Reliability Assessment Communication Questioned
A review by NERC staff of the ERO’s recently released Winter Reliability Assessment, and a preview of the upcoming Long-Term Reliability Assessment, prompted trustees to ask whether the organization is doing enough to communicate the grid’s growing risks to policymakers and the public.
Released last month, NERC’s winter assessment warned that much of North America faces elevated or high risk of energy shortfalls during extreme weather conditions, largely because of growing demand, uncertainty around the performance of solar and wind generators, and concerns about the natural gas system’s ability to serve both domestic heating and electric generation needs in extremely low temperatures.
Previewing the LTRA, which is set to be published this week, Mark Olson, NERC’s manager of reliability assessments, said risks to the grid are likely to continue rising over the coming decade. By 2028, he said, most regions of the North American grid will face a risk of energy shortfalls in extreme conditions, with MISO and a significant chunk of SERC Reliability at risk of shortfalls in normal peak conditions.
Following these reviews, Trustee Jane Allen asked NERC CEO Jim Robb if the ERO’s management is “confident that … the messages [in these reports] are getting to the right people.” She suggested that NERC might have more success getting “the attention of the people who need to address this” by being more explicit about the implications of inaction.
Robb told Allen that NERC’s outreach at the moment is focused on “those immediate actions that can alleviate the pressure.” He said a significant challenge in this area is “that the solutions are slow to bring to bear because most of these are structural issues,” and he praised the REs for “doing God’s work” by communicating with state and provincial governments that can help to implement the needed solutions.
Responding to Robb, Kelly returned to Allen’s point, urging management to consider whether other communication strategies could help get the needed information out.
“We say all these things, but we don’t necessarily do what lawyers would call the parade of horribles — [what ensues] if you don’t do something,” Kelly said. “Winter Storm Elliott provides a perfect example, [with] rolling blackouts; Winter Storm Uri, people freeze; these are the consequences of inaction. … If we could, perhaps, just do a little bit on what happens when we don’t do what we need to do … at least in the more popular press or [among] policymakers … it might help get the message out a little bit more.”
Level 3 Alert Results
Darrell Moore, NERC’s director of situational awareness and personnel certification/credential maintenance, provided an overview of results from the ERO’s first-ever Level 3 alert, issued in May to gather information on registered entities’ preparations for extreme cold weather. (See “ERO to Issue First Level 3 Alert May 15,” NERC Board of Trustees/MRC Briefs: May 10-11, 2023.)
Moore said replies to the alert were reassuring for the most part, with “an overwhelming majority” of generator owners reporting that more than 90% of their facilities would be capable of operating at their extreme cold weather temperatures. However, many utilities indicated that freezing conditions “remain a reliability issue for generators,” with concerns about improper heat tracing, frozen instrumentation and control valves, and lack of fuel supply in critical conditions.
Asked by Robb about the usefulness of the Level 3 alert, Moore said the ERO considered the previously unused process a success both in informing utilities of needed cold weather preparations and gathering information on their progress.
“One of the things that this alert has allowed us to do was get a greater understanding of what some of the entities are doing with their essential actions … and it’s allowing us to dig a little deeper … for some of the unfavorable responses that we receive,” Moore said.
NERC Chief Engineer Mark Lauby told trustees that the organization will likely issue another Level 3 alert in the next few months focused on IBRs.
Electricity restructuring is often discussed as a binary — either a state uses market forces, or it does not — but a recent webinar from the Energy Choice Coalition dove into all the complexities it has led to since it started in the 1990s.
While individual states all have their own unique mix of rules, the R Street Institute’s paper, “Electric Paradigms: Competitive Structures Benefit Consumers,” puts them into three categories: 18 traditionally regulated, 19 with a hybrid system of wholesale competition and no retail, and 14 (including D.C.) with both wholesale and retail competition.
“We wanted to diagnose that as sort of a basic fact about the current system,” Michael Giberson, R Street senior fellow and the report’s co-author, said on the webinar. “And then we wanted to see for each of these three systems, how does the evidence stack up in terms of how they’re serving customers.”
The report dives into details around how markets have been viewed as saving or costing money for customers; how they have impacted reliability; and their environmental outcomes. It summarizes numerous other studies from both sides of the argument.
“Restructuring, when done well, has done well,” the paper says. “Restructuring likely benefits reliability, reduces emissions and unleashes efficiencies at the wholesale level that get passed along to consumers when retail competition is allowed to work.”
How emissions have declined in the different organized markets | R Street Institute
Most of the change in recent years has come from states joining MISO and SPP but not deregulating their retail sides. That trend is ongoing in the West with discussions around market alternatives, but Meghan Nutting, Sunnova Energy executive vice president of government and regulatory affairs, said technological change has made generation monopolies at the retail level functionally nonexistent.
“Because of rooftop solar, and because of other technologies and alternatives that consumers have, it means they don’t have to rely solely on their monopoly generation provider for electricity,” Nutting said. “And so, the more that regulators and the more that our government structures try to support and protect those former generation monopolies, that’s just protectionism of individual companies at this point, because there is competition within their market.”
Retail competition has seen pushback in some states like New York and Massachusetts because retailers were offering higher prices than the standard offers from the utilities, which for the most part in restructured states were left as providers of last resort (POLR) for mass-market customers. Only Texas eliminated the utilities’ POLR role in its market, which even then is only inside ERCOT and only required of investor-owned utilities (leaving out Austin, San Antonio and other cities served by municipally owned utilities).
The paper says that critics of those higher-priced contracts have identified “valid problems” with the markets that can be fixed with better rules, such as improved licensing processes and oversight. It calls on states to move to “better paradigms” — i.e., those in hybrid states moving to full restructuring.
“When moves to a better paradigm are impossible at present, policymakers should seek out improvements within existing structures,” the paper says. “Importantly, even policymakers in fully restructured states have opportunities to improve competition within that paradigm as well.”
Moving toward more competition takes “significant decisions away from utilities and regulators” and places them in the private sector. Regulators are ostensibly supposed to make decisions that take into account the interests of consumers and other groups, but the paper notes that process can be corrupted in ways the market cannot, citing recent scandals with traditionally regulated utilities influence peddling, bribing officials and intimidating journalists.
“What we’re seeing is competition within these spaces that exists already, protectionism for the incumbent, and then inadequate regulation in place of markets that would allow consumers to drive the outcomes that would likely be better,” Nutting said.
Regulators have to make sure that utilities do not give into the economic incentive of investing in higher-cost resources to earn higher returns, while markets outright offer the opposite incentives, said Lynne Kiesling, director of Northwestern University’s Institute for Regulatory Law & Economics.
“If I come in with a lower-cost technology, and I’m competing in a market against higher-cost technologies, I’m going to earn more profit, because I’m lower-cost,” Kiesling said. “And that incentive is very, very powerful, and it benefits both producers and consumers.”
The paper highlighted how that effect of markets can influence environmental outcomes, as they have favored natural gas plants and renewables over coal.
“An earlier study found that reductions in natural gas prices and the growth of wind power both contributed to the decreased use of coal plants in RTOs, with a resulting reduction in carbon emissions,” the paper says. “The effects pushing emissions down were weaker in SPP, which researchers speculated was caused by the ways in which monopoly-owned generators — dominant in SPP — respond to market incentives as compared to non-utility generators.”
Natural gas prices have had major impacts on markets in other ways, with the report suggesting that the outcome of lower prices in retail markets depends on a state’s access to cheap supplies of the fuel.
A soon-to-be-published study in The Energy Journal has found mixed results with retail competition’s prices — finding they have gone higher in four of the five restructured states in New England while falling in Pennsylvania and Texas, the R Street paper says.
“Both Pennsylvania and Texas were well positioned to access cheap natural gas resulting from advanced drilling techniques like fracking,” the paper says. “New England, on the other hand, has limited ability to bring in domestically produced natural gas and must resort to importing expensive liquefied natural gas to run natural gas generators during periods of high gas demand.”
The Maryland Energy Administration (MEA) has $22.5 million it’s planning to use to make low-income homes more energy efficient and put solar panels on their roofs. It just wants to make sure none of the money is spent on new appliances or systems powered by fossil fuels.
The MEA, along with Gov. Wes Moore (D), announced Dec. 11 the money will be available through two long-standing programs — the Energy Efficiency Equity (EEE) Grant Program and the Solar Energy Equity (SEE) Grant Program — but with some new requirements and opportunities for 2024.
EEE will offer $19.5 million for energy-efficiency upgrades that “generate significant reductions in energy use and pass on the benefits of the savings” to Maryland’s low- and moderate-income residents, according to the MEA website.
But in a significant shift, the program will prioritize “electrification and zero-emissions technologies,” according to the funding announcement.
“Therefore, beginning in [fiscal 2024], the replacement of existing fossil fuel equipment (e.g., HVAC, water heater) with new fossil fuel equipment is ineligible for funding via the program, even if the proposed new equipment has a higher efficiency rating.”
Upgrades to existing fossil fuel equipment will be funded provided they increase system efficiency, the announcement says.
Extra funding also will be available to pay for additional upgrades that support electrification, such as the installation of new electrical panels or circuits.
The application deadline is Feb. 16.
The Solar Energy Equity (SEE) Grant Program will have $3 million to pay the full cost — up to $25,000 — of installing solar panels on the roofs of homeowners in LMI or “overburdened” communities, which are defined as areas that historically have suffered from high levels of air or water pollution or other environmental impacts.
To qualify for the program, a household already must have participated in a state-funded weatherization or energy efficiency program, such as EEE. Up to $5,000 of a $25,000 grant can be used for roof repairs or mold remediation.
The program also allows homeowners to choose either owning the rooftop panels outright or enrolling in a leasing program in which state funds are used to pay off a 20-year leasing contract so the homeowner has no further payments on the system.
Households that go for an ownership option will be allowed to sell the solar renewable energy credits (SRECs) generated by the system, with the proceeds to be used for system maintenance and insurance.
Solar owners earn one SREC for every 1,000 kWh of power their panels produce; the current value of an SREC in Maryland is about $52 to $56, according to the Flett Exchange, an online platform for SREC sales.
The application deadline for the SEE program is Feb. 22.
MEA Administrator Paul Pinsky framed the programs as an integral part of the state’s march toward a 60% reduction in greenhouse gas emissions from 2006 levels by 2031, a target set in the Climate Solutions Now Act (CSNA) of 2022, and Moore’s goal of a 100% clean energy grid by 2035.
Pathways to Electrification
Both Moore and Pinsky stressed that the funding for the two programs is aimed at ensuring an equitable energy transition in which no communities or households are left behind.
The funding for both programs will go through nonprofits or local governments but is set up to reach a range of communities. For the EEE program, Maryland is divided into five regions, each of which is allocated a certain amount of the $19.5 million, based on population, with a 25% carveout for funding to groups that previously have not been awarded grants from the program.
For example, the Western region of the state — including Frederick, Washington, Allegany and Garrett counties — has been allocated just under $1.9 million, with $484,203 earmarked for first-time applicants.
The EEE ban on new appliances powered by fossil fuels appears to be a careful step toward reducing natural gas use in Maryland, in the absence of direct state-level legislative action on the issue. In November 2022, Montgomery County, Maryland’s most populous county, passed a law requiring the electrification of all new residential and commercial construction, with exemptions for certain businesses, such as restaurants. The new rules are scheduled to go into effect by the end of 2026. (See Montgomery County, Md. Passes Building Electrification Law.)
The CSNA also required the Maryland Department of the Environment to develop building performance standards for commercial buildings of 35,000 square feet or more, with the goal of cutting GHG emissions from these buildings 20% below 2025 levels by 2030 and reaching net zero by 2040.
The proposed regulations are scheduled to be released Dec. 15.
High levels of self-scheduled exports out of CAISO’s balancing area to support stressful conditions elsewhere led the ISO to declare Level 1 energy emergency alerts in late July, the Department of Market Monitoring explained last week.
The alerts, issued for July 20, 25 and 26, were not related to bad weather conditions in California, but actually in areas to its north and south, said Ryan Kurlinski, senior manager of market and policy analysis with the DMM.
Typically, during peak net load hours in the summer months, power flows from the Northwest into the rest of the system. But this July saw relatively low hydro conditions in the Northwest compared with relatively high ones in California. This was coupled with extremely high temperatures in the Southwest that lasted even after peak net load hours, leading to record demand there.
“What we saw this year was a significantly different pattern from previous years,” COO Mark Rothleder said. “What we saw was a higher level of exports and demand outside of our system, and for a large period of time, we could support that demand, but there were times … where we could not.”
When the EEA was declared on July 20, CAISO operators had not yet identified exports they were unable to support in the hour-ahead market. As solar began ramping down, there was still relatively high demand across the system between 6 and 8 p.m. Throughout the day, CAISO had sufficient bids from its contracted capacity to cover its own requirements, but beginning around 8 p.m., “the addition of the exports required CAISO to rely on bids from resources not contracted to serve CAISO load,” Kurlinski said.
While the ISO was close to being unable to deliver exports that had received hour-ahead market schedules, operators ultimately did not curtail any load.
On July 25 though, CAISO was unable to award several thousand megawatts of self-scheduled exports between 6 and 9 p.m.
“I’m calling that the first significant market issue impacting WEIM [the Western Energy Imbalance Market] in this period,” Kurlinski said. “CAISO did not give hour-ahead market awards to all exports that wanted to self-schedule in the hour-ahead market.”
Each of the three real-time markets have a load forecast that the market solves for, and operators frequently adjust this load above the forecast, particularly during net peak load in the hour-ahead and 15-minute markets to cover any uncertainty over available supply. Uncertainty materialized quickly on July 20, Kurlinski said, and by July 25, operators began dramatically increasing the load adjustment.
“These large hour-ahead market load adjustments contributed significantly to the large quantity of exports attempting to self-schedule out of CAISO that did not receive hour-ahead market awards,” Kurlinski said, but “CAISO operators did actually end up allowing a decent portion of these exports to tag … and ultimately flow to other balancing areas.”
Not enough supply could prevent the hour-ahead market to self-schedule exports, but the load adjustment can also be supplied by advisory WEIM transfers flowing into CAISO’s balancing area. If the transfers don’t flow into CAISO in the five-minute market, however, the ISO may not have enough supply to meet load requirements and self-scheduled exports in the hour-ahead market.
“This concern arose on July 25, and my understanding is that it prompted the CAISO balancing area to start limiting the WEIM transfers into its area in the hour-ahead market,” Kurlinski said. From 7 to 8 p.m., the ISO put a 4,000- to 5,000-MW load adjustment into the market, and while much of it was supported by WEIM transfers in the hour-ahead market, almost no five-minute transfers flowed into CAISO.
On July 26, CAISO started strictly limiting WEIM transfers into its balancing area during peak hours, which marked the second significant issue.
The limit significantly impacted transfers in other WEIM areas, such as in Arizona, where transfers to CAISO from Arizona Public Service decreased to zero at one point.
Observations and Lessons Learned
Rothleder shared observations that could help the ISO prepare for any similar conditions in the future, should they arise.
“Between the 20th and the 25th, we took the learnings and the observations, and we applied that [in the 7 p.m. hour] on the 26th,” Rothleder said. “This is what triggered us to limit the amount of transfers the California ISO was relying on from others when we were clearing that hour-ahead scheduling process.”
Limiting transfers, he said, helped reduce uncertainty and increase confidence in the ability to serve load. He also highlighted that the load adjustment aided in dealing with additional uncertainty.
Unusual conditions led to the issuing of the EEA, but all things considered, Rothleder emphasized that it was a successful summer overall for the ISO.
“It’s unprecedented that we would be a net exporter in a summer period, but this past July, we saw periods where we were a large net exporter supporting other parts of the West as they were approaching 96% of their record load outside of the ISO,” he said.
While CAISO did enter a few EEA watches and declared the Level 1 alert, it did not have to issue any flex alerts or experience any load-shedding events.
“The system is becoming more complicated, and we’re seeing flow patterns that are significantly different from historical patterns, and this highlights really the need for that coordination and awareness of the constraints that may arise earlier,” Rothleder said. “That’s why we believe things like the Extended Day-Ahead Market provide the vehicle for that strong coordination, awareness and insurance.”
BOSTON — Hoping for a mild winter is not a sustainable plan for reliability, FERC Chairman Willie Phillips said at the Dec. 7 NEPOOL Participants Committee meeting. He said he’s concerned premature retirements of legacy generators and infrastructure will threaten the reliability of the New England grid.
While ISO-NE’s winter reliability studies indicate Everett doesn’t significantly improve the reliability of the grid during extreme weather conditions, Phillips said the RTO should “continue to work and think about the assumptions and the methodology that are used in that study to make sure that we get this right.” (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.)
Asked whether electric ratepayers should bear the costs of keeping Everett open, Phillips responded “I don’t have an opinion — and I’m not here to give one — on who should pay,” adding that it’s not FERC’s jurisdiction to make the decision.
The chairman also connected the need to maintain grid reliability to the region’s decarbonization goals. While applauding the states’ clean energy ambitions, Phillips said the region must keep reliability “top of mind” as it pursues its clean energy goals.
“If we get this wrong, it is the transition that will be blamed,” Phillips said.
Phillips also emphasized the need to consider environmental justice and existing energy infrastructure burdens when planning and siting new infrastructure.
“I grew up in an environmental justice community,” Phillips said. “I know what it smells like.”
He said he hopes to issue an “outward-facing guidance document” detailing expectations regarding engagement with environmental justice communities.
Prior to Phillips’ speech, a group of climate activists associated with the organization No Coal No Gas pressed NEPOOL officers to let them sit in on the meeting, which the NEPOOL officers allowed.
While New England ratepayers can join the organization for a $500 membership fee, several members of ISO-NE’s Consumer Liaison Group Coordinating Committee (CLGCC) who lack institutional support are not NEPOOL members.
In December 2022, No Coal No Gas successfully elected a slate of candidates to the CLGCC which included several members of the climate group. (See Climate Activists Take Over Small Piece of ISO-NE.) The group now is pushing for elected CLGCC members to be given governance-only seats at NEPOOL.
Operations Report
The total energy market value in November was up by about 45% compared to October but was more than 40% less than the total value from November of 2022, ISO-NE COO Vamsi Chadalavada told the PC. The monthly increase relative to October was because of higher natural gas prices, Chadalavada said.
The estimated carbon emissions from November were down relative to both October of this year and November of 2022, Chadalavada added.
Regarding this winter, Chadalavada said ISO-NE’s capacity analyses based on the forecasted load indicate “a surplus even after accounting for generation at risk due to gas supply.” (See ISO-NE Says Region Has Enough Resources for Upcoming Winter.)
Chadalavada added that the region’s weather can change quickly and noted that “extended periods of cold weather may rapidly deplete stored fuel inventories and capacity outlook will be adjusted accordingly.”
IMM Report
David Naughton, executive director of ISO-NE’s Internal Market Monitor (IMM), presented to the PC on the IMM’s 2022 Annual Markets Report.
The report notes that weather-normalized load has increased slightly over the past two years following years of decline due to energy efficiency efforts.
“The trend of decreasing load may have reached an inflection point,” the report states, adding that “while it is difficult to attribute this directly to any particular driver, this change is consistent with the ISO forecast that average load will increase each year with the continued adoption of electricity-fueled transportation and electric heating.”
Naughton also noted total energy costs in 2022 nearly doubled compared to 2021 and were the highest since 2008.
In other NEPOOL business, the PC approved the 2024 NEPOOL expense budget and elected a slate of officers to run the PC in 2024, which will by chaired by Sarah Bresolin of ENGIE North America. The PC also voted to support changes to its Financial Assurance Policy regarding the calculation of Forward Capacity Market delivery financial assurance.
Washington state expects to collect $941 million in extra cap-and-trade money in the first half of 2024, bringing the overall income to roughly $3 billion over the system’s first 18 months.
The Washington Legislature already has appropriated $2.1 billion of previously predicted “cap-and-invest” income for its fiscal biennium, which runs from July 1, 2023, to June 30, 2025. Most of that money is going to climate change mitigation projects.
The state is on track to gather roughly $2 billion in calendar 2023. That’s more than $1 billion greater than what the Legislature expected when it originally approved the program in 2021.
The newly predicted $941 million will be added to Gov. Jay Inslee’s 2024 supplemental budget request to the Legislature in January — a tweaking of the approved 2023-2025 biennial budget. It’s up to the Legislature whether it will approve some or all of that request.
Inslee’s request includes:
A one-time $200 credit to the utility bills of roughly 750,000 low- and moderate-income households in Washington.
Speeding up the transition from diesel school buses to electric zero-emission school buses across the state.
Installing electric heat pumps in low-income multiple-family homes, replacing gas heat.
Providing matching funds for competitive federal grants to obtain clean-energy jobs.
Converting a large diesel ferry into to a hybrid fuel-electric ferry.
Washington’s ferries are breaking down in increasing numbers. Inslee said Dec. 11 that future cap-and-invest income could speed up replacing the old ferries with new hybrid ferries.
Legislative Priorities
Also Dec. 11, state officials unveiled Inslee’s top three climate-relate bills for the 2024 session.
The first bill — modeled after a new California entity — would create a division of petroleum market oversight under the Washington Utilities and Transportation Commission. “We’re gonna pass the transparency law so we are not victimized by the oil companies,” Inslee said at his press conference.
Inslee has been heavily criticized because the bid prices on Washington’s allowance have been linked to increased gasoline prices in the state.
The oversight entity would require details on fuel pricing, profit margins and transaction data by fuel suppliers, refinery operations and others in the fuel supply chain. The new office would analyze that information. The bill likely would explore setting up fines for collusion, shutting down fuel chain equipment and other forms of market manipulation, officials said in a press briefing prior to Inslee’s comments.
“This is to simply unpack the black box of how oil companies set their prices. … Who’s selling to whom, at what volume?” asked Becky Kelly, Inslee’s climate change policy adviser.
The Inslee administration contends the five biggest oil corporations made $200 billion in profits in 2022. “We’re not gonna surrender to the oil companies,” Inslee said.
The second bill would have Washington officials explore compatibilities with the cap-and-trade programs in California and Quebec, to try to stabilize carbon prices and shrink the costs of buying allowances. The California-Quebec coalition is the only other cap-and-trade market in the United States or Canada.
The meshing of the two systems would have to be addressed. For example, Washington limits a bidder to try to buy 10% of the available allowances per quarter. The California-Quebec alliance limits that to 25%.
A recent Ecology Department preliminary analysis concluded the proposed linkage likely would improve the cap-and-invest program’s economic durability, longevity and efficacy.
“In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization,” the report said.
The third legislative effort is reviving House Bill 1589 by Rep. Beth Doglio (D) to limit methane emissions from landfills. The bill is aimed at encouraging Washington’s largest utility, Puget Sound Energy — which uses methane in some instances — to switch to other electric sources.
New Jersey’s Senate voted Dec. 11 to allocate $15 million from the current state budget for the first year of the state’s long-awaited electric school bus program, in one of the final steps needed to launch the pilot program that will test the use of electric buses in six districts each year.
The Senate voted 22 -10 to approve the minor changes to S3044that Gov. Phil Murphy (D) recommended in a conditional vetohe issued Nov. 27, when the bill landed on his desk. Specifically, Murphy suggested the funds come from the fiscal year 2024 state budget, which runs from July 1 of this year to June 30, 2024, rather than the FY 2023 budget, as originally planned.
The Senate’s funding approval follows the Nov. 30 release of a report on the benefits of using electric school buses in New Jersey. Compiled by Environment New Jersey, an environmental group, and ChargEVC-NJ, an electric vehicle (EV) advocacy group, the report highlights the “significant potential” electric buses offer but cautions they “remain a nascent segment despite high expectations.”
Senate and Assembly votes are needed on the final bill with Murphy’s changes added before it goes back to the governor for signing. Final approval would start a pilot initiative that environmentalists and EV advocates have long urged the state to embrace more quickly due to its potential impact in cutting emissions.
Transportation is New Jersey’s largest source of greenhouse gas emissions, and very few of the state’s estimated 21,000 school buses — which range from Class 2 buses to heavy-duty Class 8 buses —are electric.
Murphy signed a bill, A1282, creating the three-year, $45 million program on Aug. 4, 2022, expecting the legislature to pay the first year of funding from the state’s 2023 general fund. When that allocation was not made, the program remained unfunded. (See Electric School Bus Pilot Awaits NJ Governor’s Signature.)
A1282 requires the New Jersey Department of Environmental Protection (DEP) to create a pilot program under which six districts or contractors each year would transport students to school in electric buses to assess the reliability and effectiveness of using them in place of diesel-powered vehicles.
The performance of the buses would be evaluated on factors such as cost, maintenance, fuel use and speed, and data would be collected and submitted to the DEP. At least half of the districts or contractors would be in low-income, urban or environmental justice communities.
Comparing Costs
The report, “Electrification of New Jersey’s School Buses,” lays out the opportunities and barriers that could affect the pilot program.
The report says electric buses would cut school bus emissions by 74.7% but would not lower emissions to zero as long as some of the electricity powering the vehicles comes from fossil fuel generators. Fuel and maintenance cost savings from running electric buses would be significant, cutting those expenditures statewide by 61.4% or $202.3 million, the report says.
However, the picture on the total cost of ownership (TCO) — the cost over the entirety of the life of an electric bus —is “challenging,” the report says. The “higher up-front costs” of electric vehicles over diesel- or gasoline-fueled vehicles can be mitigated by operational savings. But whether electric buses can compete overall on costs with internal-combustion-engine (ICE) buses depends on several factors, including whether the bus is used for short or long trips, how costs decline in the future and the availability of incentives, the report says.
At current cost levels, EV school buses can “approach parity” with ICE buses only on longer runs, during which the bus uses more fuel. The higher cost of fossil fuel drives up the cost, the report says.
At current costs, an electric bus used on short runs would need an incentive of $143,000 to achieve total ownership cost parity with a diesel bus, and a subsidy of $192,000 to reach parity with a gasoline bus, the report says. For electric buses used on long runs, the incentive would need to be $39,500 to reach parity with a diesel vehicle and $98,500 to reach parity with a gasoline-fueled bus.
If, as some analysts predict, electric bus purchase costs come down in the future, electric buses will be able to compete on short, average-length and long bus routes, the report says. For example, if battery costs are “reduced in 2030 by as much as 50%”, the up-front cost of an electric school bus could be on a “par” with fossil-fueled vehicles, the report said.
In addition, bus operators could reap income from vehicle-to-grid (V2G) revenue by tapping bus batteries to feed energy back to the grid to help address demand peaks, the report says. Electric school buses are well-placed for such demand management efforts because their use profiles are specific and predictable. School buses sit unused for much of the day and are used minimally during the summer months, the report says.
Researchers found the dollar value of such use is not clear, however, with estimates ranging between $500 and $15,000 a year per bus, the report says.
WASHINGTON — As utilities and regulators face unprecedented growth in power demand — from data centers, chip and other clean tech manufacturing, and building and transportation electrification — figuring out how to plan and finance distribution systems has become a similarly fast-moving target, according to speakers at the GridWise Alliance gridCONNEXT conference.
The industry now faces a “trilemma,” attempting to balance decarbonization, reliability and affordability, said Peter Fox-Penner, partner and chief impact officer at Energy Impact Partners (EIP), a clean tech investment firm funded by utilities.
“There are many related challenges of decarbonizing supply, doubling the size of the grid, while … incorporating AI, severe weather, institutional distrust and other things,” Fox-Penner said during a Dec. 6 panel on how to draw more, and more diverse, investment into grid expansion.
The effects of extreme weather, exacerbated by climate change, also are becoming a major challenge to the economic viability of utilities, he said. Citing figures from a recent analysis from Fitch, Fox-Penner noted that extreme weather events caused close to one quarter of the rating agency’s downgrades for utilities between 2018 and 2023 (year to date) versus none in the previous five-year period.
A shift is needed in the industry’s and consumers’ understanding of affordability, away from cost per kilowatt-hour on electric bills toward “wallet-share,” the amount households spend on electricity “versus everything else,” he said.
While electric rates certainly have been hit by inflation, wallet-share is at 1950s levels and even fell slightly in 2022, he said. “Affordability is a tremendous challenge … because of the macro environment we’re operating in, rather than the fact that electricity remains an incredible value.”
Prices will come down with new and better technologies for electrifying transportation and buildings, he said.
A paradigm shift also is needed in utilities’ approach to distribution planning, which typically runs in two- to five-year cycles, with system upgrades made incrementally, on an as-needed basis, said Jeff Smith, director of transmission and distribution operations and planning at the Electric Power Research Institute (EPRI).
“But if we keep doing that sort of incremental approach, will that lead us to a suboptimal location later down the road? … Is that something we’re going to regret doing by 2040, 2050?” he said.
Working with the Department of Energy and utilities, EPRI is trying to ask different questions, Smith said during a panel on distribution planning. The goal here is to “take that long-term look and identify the grid service needs, the grid design requirements, the operating requirements that are necessary for deep decarbonization,” he said.
Industry stakeholders and their concerns appear endlessly complex, Smith said — how many transformers will be needed, when and how to introduce time-of-use rates, how to integrate storage — “but we can’t let analysis paralysis stop us from moving forward. … The needs of the grid are changing at a pace we’ve never seen before.”
Distribution system design and projections of load growth typically have been based on historical information, Smith said. “We need to start looking to the future. … Our loads are changing, demand is changing, the shapes are changing, the flexibility of resources are changing. How does that change actually [affect] our design?”
Larry Bekkedahl, senior vice president for advanced energy delivery at Portland General Electric (PGE), also called for a closer focus on load, rather than the typical industry focus on generation capacity.
“You’ve really got to move and advance yourself to pick up these loads,” Bekkedahl said, noting the Portland area is producing 15% of all the computer chips manufactured in the U.S., with more chip plants and data centers on the way.
“When I think about our load, we right now have over 2 GW of requests on a 4.5-GW system,” he said. Demand is growing at 4% a year, versus a previous rate of about .5 to 1% a year.
“How do you plan for that? Because there’s a lot of two-way, bidirectional energy that’s going to be happening on the distribution side,” Bekkedahl said. “What we’re trying to do is bring the peaks down and push utilization up. That’s our motivation, and we want to use the system we have as much as possible but drive those peaks down wherever possible.”
Retrofit Everything Everywhere
The speed of change and its impacts on the electric power industry were core themes for both panels.
Fox-Penner sees “two distinct waves of [load] growth that are different in nature.” In the near term, artificial intelligence, cryptocurrency and other high-tech applications will produce “very lumpy” demand curves, while transportation and building electrification will take longer, but drive bigger growth, he said.
“It’s worth keeping those two things in mind, I think, because the policy responses … and the forecasting techniques we want to use are different,” he said.
They also will draw different investors, said Karen Wayland, CEO of the GridWise Alliance, noting that high-tech companies — such as Google and Microsoft — are pouring major investments into clean energy for their data centers. But the cost of building and transportation electrification likely will fall on utilities and their customers.
Wayland also said she believes the industry has the technology to meet anticipated load growth and is “looking in both the right places. We’re looking [at] developing utility scale. We’re looking for local resources.”
Phil Dion, senior vice president for customer solutions at the Edison Electric Institute (EEI), the industry trade group for investor-owned utilities, said he believes utilities will prioritize investments in familiar, low-risk priorities — retrofitting “everything we have as fast as possible,” energy efficiency and demand-side management and flexibility.
“The idea of building transmission lines is imperative, but it’s a way up. It’s a decade away,” Dion said. “So, we need to be investing in technologies, anything we can do to squeeze 10% more [electricity] out, without compromising safety.”
Wallet-share notwithstanding, consumers’ perceptions of power affordability may affect utilities and regulators’ willingness to invest in the infrastructure needed to electrify everything, everywhere, he said.
The cost of expanding distribution will fall primarily on utilities — and require regulatory approval — Dion said, so, “if we don’t start leveraging other piles of capital, this is going to be a problem.”
DOE’s Grid Resilience and Innovation Partnerships program — which recently awarded $3.46 billion for transmission and distribution system upgrades — is a step in the right direction, he said, but more money will be needed, including “leveraging customer capital as well.”
Smith argued for a focus on right-sizing distribution systems, since under- or over-sizing could result in added expense and underused or stranded assets. Right-sizing also means making sure infrastructure is built in the right location, at the right time, he said.
Challenges ahead include figuring out “how do we actually make a substation expandable … sizing them appropriately for the future” and making decisions about primary voltage levels, he said. Voltage levels range from 4 kV to 34.5 kV, with most utility distribution systems in the U.S. working at 15 kV.
“The questions we need to be asking ourselves is, for 2050 [clean energy goals], is 15 kV going to get us there?” Smith said. At 34.5 kV, “you can serve much more customers from a [distributed energy resource] and load perspective, and that’s why so many utilities are looking at maybe dual voltage transformers, recognizing that the voltage they’re using now isn’t something they’re going to use later down the road.”
‘Every Ounce of Flexibility’
As presented by Bekkedahl, PGE is a case study in the challenges utilities face in distribution planning in an extremely fast-changing energy landscape.
The utility was able to ride out Oregon’s asphalt-melting heat wave in the summer of 2021, just barely, he said. “We hit saturation; there was nothing else to turn on. We hit a flat peak … and we were kind of stunned by it, and we survived it, and the next summer, when it’s 95 degrees, we were almost at the same level because everybody went out and bought air conditioners.”
PGE has shifted from a winter-peaking to a summer-peaking system, and it also has been contending with south-to-north, very cheap energy flows from California, requiring quick curtailment of that power at the state border to protect the utility’s distribution system from overload, Bekkedahl said.
“If you’re in a dispatch room and you’ve got this big red screen in front of you that’s saying you’ve got to start curtailing customers, you’ve got to do something,” he said. PGE was able to call on 90 MW of demand response to shave its peak, which “made the difference in that moment. So, I want every ounce of flexibility I can get in the future.”
Looking ahead, Bekkedahl outlined the “big five” must-haves for successful distribution planning, beginning with visibility.
“You’ve got to be able to see into [the system] and think about the influence that you have,” he said. “If you don’t have visibility into your distribution system, none of this works. You’re going to build your plan, it’s going to be for the peak, it’s not going to be something that’s flexible.”
Better forecasting is next, followed by flexibility. In the home of the future, “every device is going to have intelligence,” Bekkedahl said. “How are we using them? How are we interfacing with them?”
Resiliency and redundancy — backup systems — come next, with Bekkedahl pointing to inverter-based systems as one way to keep household electricity running in the event of a power outage, and possibly to provide demand response.
The last must-have is power quality, with a basic paradigm shift that can take into account and monitor the performance of the thousands of devices being turned on and off across the system, he said.
De-risk, Decarbonize, Scale
Looking ahead, Fox-Penner anticipates that distribution upgrades and expansion could be the top draw on utility investments over the next decade. “And that’s where you hit resilience and affordability issues, and so that takes working with [existing] conditions, using every single tool,” he said.
For utilities, part of the challenge is the regulatory limits on their ability to plan and order equipment for the future, Dion said. “Imagine you’re a distribution full-time provider … and you’re sold out through 2026. You have nothing,” he said.
“We need regulatory regimes that allow us to make purchases into the future, not just replace the stuff that’s broken, but … the new stuff that needs to be developed for what we need, almost like a hedging policy,” he said.
“[We] have to be able to invest in things that we need that are facing the biggest barriers,” Fox-Penner agreed, pointing to building electrification as one sector that will be critical for both homeowners and apartment renters. “That’s right at the heart of our existence, and we need to go in there and change the heating and cooling system,” he said.
He sees continuing innovation as key, “particularly in the spaces where the solutions aren’t well developed, which are often called … the supplemental power sources to wind and solar,” such as nuclear, geothermal or carbon capture.
With its funding from utilities and other investors, EIP has developed a model that focuses on investing in technologies that utilities will need and can pilot and then scale, Fox-Penner said. The company has more than 100 businesses in its portfolio and “over $1.4 billion worth of business going on between our portfolio companies and the members of our coalition,” he said.
“I think of the industry as a fast follower,” he said. “Our model is to de-risk decarbonization measures for our incumbent investors. Once it’s de-risked, it can scale.”
After years of low load growth, U.S. grid planners now predict a sharp increase in electric demand, according to a report released Dec. 12 by consulting firm Grid Strategies.
The nationwide forecast for the next five years has nearly doubled to 4.7% from 2.6% last year, Grid Strategies said, citing data compiled from FERC filings.
The increased load growth translates to an additional 38 GW of demand through 2028, which will require new transmission and generation to be met reliably, Grid Strategies said in the report, “The Era of Flat Power Demand is Over.”
“Over the past decade, grid planners have been forecasting a mere 0.5% annual growth rate, as summarized by NERC,” the report said. “Yet in 2023, annual peak demand growth is up to at least 0.9%, driven by data centers, industrial facilities and other near-term investments.”
That is likely to be an underestimate, the report said, noting that since the forecasts were filed with FERC, Puget Sound Energy, Duke Energy, Georgia Power and the Tennessee Valley Authority have stated that their load expectations have grown even higher.
Since 2021, commitments for industrial and manufacturing facilities have totaled about $481 billion, and more than 200 manufacturing facilities have been announced in the past year. Data center growth is forecast to exceed $150 billion through 2028.
The data across the industry are uneven, with some regions like MISO not clearly explaining how large load development will impact peak demand, whereas PJM and Georgia Power’s latest forecasts include higher investment in industrial sites and data centers.
Only some utilities factor in the impacts of higher temperatures and more extreme weather in their projections. As those practices spread to more firms, the load growth figures should go up, according to the report’s authors, John D. Wilson and Zach Zimmerman.
Major new loads can take only one or two years to connect to the grid, compared to at least four years for new generation and even more for new transmission, the report said.
“It’s worrisome that a resurgent American manufacturing sector may face headwinds from the limited ability of the nation’s electricity systems to respond,” the report said. “Electricity systems need to supply new generation, connect that generation to load and — of course — connect new load to the system. There are real risks that some regions may miss out on economic development opportunities because the grid can’t keep up.”
Transmission investments to meet the new demand are a particular challenge, as they will have to be sped up to meet the new demand after seeing declines in overall investment in the last couple of years.
“Transmission takes years to build, and current planning and regulatory practices make interregional transmission particularly difficult to build,” the report said. “Even though investing in transmission could save tens of billions of dollars in bringing on the new 38 GW of electricity demand, changes in policy and practice are required across the country to make this possible.”
The Inflation Reduction Act and Infrastructure Investment and Jobs Act are leading to an increase in industrial demand, while the computing power of artificial intelligence is driving increased demand from data centers. Longer-term electrification of heat and transportation is adding to growth as well.
Other potential sources of demand growth include new hydrogen fuel plants and the impact of more extreme weather.
“If grid planners are not accounting for these drivers, load forecasts will be too conservative, and the system will not be ready to meet growth in electricity demand,” the paper said.
The new sources of load growth are not uniform across the country with new industry favoring the Southeast (especially Georgia and the Carolinas), MISO (especially Michigan and Indiana) and the Southwest (especially Arizona and Nevada).
Data centers currently represent 2.5% of total electricity demand, but it could grow to as much as 7.5% by the end of the year, according to the Boston Consulting Group. That sector’s growth depends on land and power availability, and it can be located in specific regions, with the report highlighting “Data Center Alley” in Loudoun County, Va., outside D.C.
Virginia has the largest data center market in the world, with more than 35% of all known hyperscale data centers worldwide. (See related story, “PJM 2024 Load Forecast Sees Jumps from EVs, Data Centers, Heat Pumps,” PJM PC/TEAC Briefs: Dec. 5, 2023.)
Ten planning areas are home to most of the projected demand increase with 18 GW: ERCOT, PJM, SPP, Duke Energy, Georgia Power, NYISO, Arizona Public Service, TVA, CAISO and Puget.
APS and Puget are expecting demand to grow more than 10% in the next five years, while ERCOT sees the highest growth among organized markets at 6.6%.
“In 2018, ERCOT’s peak load record was 69.5 GW. This has grown by over 16 GW to 85.6 GW this summer,” the paper said. “The record-setting demand has been largely driven by industrial growth and extreme temperatures. While ERCOT continues to forecast most types of loads to remain relatively flat through 2028, its forecast for new large loads spiked up to 7.4 GW over the past year.”
The new large loads are evenly split between new industrial facilities and cryptocurrency miners, the latter of which are only expected to run when ERCOT’s energy market prices make that activity profitable.
The paper focused on summer peak demand because that is most closely related to transmission development, and on average across the country, it is larger than winter peaks. It acknowledged, however, that focusing on summer peak demand “may obscure important planning issues related to winter peak demand and overall energy resources.”
