The California Air Resources Board is getting close to finalizing details of its electric bicycle incentive program, a $13 million initiative expected to launch in early 2023.
The program will be geared toward low-income participants. CARB is considering an eligibility cap of 300% of the federal poverty level (FPL). In 2022, 300% of the FPL is $40,770 for a one-person household, $54,930 for a family of two, or $83,250 for a family of four.
The amount of the e-bike purchase incentive has yet to be decided, CARB staff said during a workshop on the program last week. Participants in previous workshops said a rebate of $750 to $1,000 would be enough to encourage an e-bike purchase.
Larger incentives might be offered to residents of disadvantaged communities or those whose income is less than 225% of the federal poverty level. Bigger rebates might also be available to buyers of specialized bikes, such as cargo bikes or adaptive bicycles for special-needs riders.
CARB is looking at setting aside half the program’s funding for people whose income is less than 225% of the FPL and those living in disadvantaged communities. Applications from those groups would be processed first.
The agency expects to start offering incentives in the first quarter of 2023.
Despite limiting the incentive to low-income applicants, CARB staff said they’re expecting strong demand.
“We already know this program is going to be super successful,” said Aria Berliner from CARB’s Advanced Transportation Incentive Strategies Section. “There is so much interest.”
An Alternative to Cars
E-bikes are viewed as an ideal alternative to cars for trips around town. By encouraging e-bike adoption, CARB aims to support active transportation, reduce miles traveled by car and cut greenhouse gas emissions.
California’s e-bike incentive program received a $10 million allocation from the 2021/22 state budget. (See Calif. Program to Provide $10M in E-bike Incentives.) Last month, the CARB board voted to increase program funding to $13 million.
Following a competitive solicitation, CARB selected San Diego-based Pedal Ahead to administer the e-bike incentive program. The nonprofit started work on the project on Dec. 1.
CARB has held a series of workshops to help decide program details. The agency discarded an earlier proposal to exclude Class 3 e-bikes from the incentive program. CARB’s concern was that the Class 3 bikes, which reach speeds of 28 mph, could be a danger to pedestrians or other cyclists.
But Class 3 has become the most popular type of e-bike, workshop participants said, and the bikes are useful to riders making longer trips.
Another issue that’s been debated is whether incentives can be used at online retailers, or brick-and-mortar stores only. Under CARB’s current proposal, eligible purchase locations would include local bike shops and online retailers with a presence in California — either a physical store, company headquarters or a manufacturing site.
CARB is also looking at requiring eligible bikes to come with a two-year warranty at no additional cost. Another idea is to offer incentives for safety equipment such as bike locks, lights, helmets and safety vests. Some workshop participants said eligible bikes should come equipped with front and back lights.
Other workshop participants said CARB should also offer financing for e-bike purchases. According to the California Bicycle Coalition (CalBike), e-bikes that are safe and have “respectable durability” cost $2,000 and up.
CARB plans to hold another workshop on the e-bike program early next year, with discussion focused on incentive amounts, safety gear subsidies and e-bike cost limits.
Other Incentives
In crafting its e-bike incentive program, CARB is looking at e-bike incentives available in areas such as San Mateo County, Calif., Denver and British Columbia.
The city of Denver this year started an e-bike rebate program with a standard rebate of $400 and a $1,200 rebate for low-income residents. E-cargo bikes are eligible for an extra $500.
As of late October, 4,401 e-bike vouchers had been redeemed, the city said. The program was paused because funding ran out, but it’s expected to return next year.
Pedal Ahead runs an e-bike program in San Diego County that prioritizes low-income applicants. The program loans e-bikes to participants, who are asked to ride at least 150 miles per month and use an app to collect trip data. Participants who meet the requirements for two years may then keep the bike.
This year, Pedal Ahead announced a partnership with the San Diego Association of Governments to bring the program to another 125 participants.
FERC on Thursday approved NYISO’s request for up to three more years to implement tariff revisions that will allow distributed energy resources in aggregations to provide all ancillary services they are capable of, in compliance with Order 2222 (ER21-2460).
NYISO last month proposed to extend the revisions’ effective date from the fourth quarter this year to a “flexible” date of no later than Dec. 31, 2026, because of unexpected delays in developing and implementing the necessary software modifications.
The ISO said it will not necessarily need all of that time to complete the necessary work. It noted that it is still on track to implement the DER aggregation and participation models accepted by the commission in 2020 by the third quarter of 2023 and, as a result, may be able to start having aggregations participating in its markets far in advance of 2026.
It also said that in 2024 it will start deploying software that will automate much of the work that will at first be done manually by staff.
NYISO had earlier this year requested for more time to submit its Order 2222 compliance filing; as part of compliance with the order, each RTO and ISO was required to propose a date by which it could complete the necessary work integrating DERs into their markets. (See NYISO Requests Extension, Clarification on Order 2222 Compliance.)
In its brief order, FERC noted that no answers were filed in response to NYISO’s request, approving it without further comment.
RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved tariff revisions on credit rules for virtual transactions, the deliverability of “internal controllable” lines and transmission owners’ right of first refusal. The committee also received briefings on the ISO’s winter supply outlook and its updated Strategic Plan.
Credit Requirements on Virtual Transactions
The MC approved the first changes since 2009 to the ISO’s credit requirements for virtual transactions — bets on the price spread between the day-ahead-market (DAM) and the real-time market.
The 2009 changes distinguished for the first time between virtual load — offers to acquire energy in the DAM — and virtual supply, offers to provide energy. The rules varied credit requirements based on seasonal, time of day and zonal groupings to reflect their risk characteristics, using data from April 2005 forward.
The current rules break supply and demand credit requirements into four periods for weekday peak hours (HB7-22), and one each for nights and weekends/holidays. Under the proposed changes, virtual demand bids will have different requirements for summer, winter and shoulder months, with 28 distinct groupings. Virtual supply bids will be broken into 33 groupings, also reflecting the seasonal differences.
Virtual supply and virtual demand positions show lookback comparisons | NYISO
The proposal also would change the lookback period, giving one-third weight to data from the last year and two-thirds to the last five years.
NYISO said expected changes to its transmission system and resource mix over the next decade “provide support for shift to a shorter lookback period so that changes in real-time price variability are reflected in credit requirements without a long delay.”
The ISO settled on the weighting to balance accuracy with responsiveness, said John Jucha, senior credit risk analyst. Longer lookback periods provide more data points and more accurate estimates but result in slower changes to credit requirements when system conditions and price volatility are changing rapidly. Shorter lookback periods allow quicker adjustments to credit requirements but can also result in dramatic changes not warranted by underlying conditions.
The proposed rules also would treat the ISO’s transmission zones and proxy buses individually rather than the current practice, which sets one requirement for zones A to F and another for zones G to I. The ISO said it expected “significant benefits” immediately for zones A and F, with potential benefits for other zones in the future.
Also changed was the threshold for virtual supply positions, which will increase to the 98th percentile. The threshold remains unchanged at the 97th percentile for virtual demand positions.
The new rules will also apply to external transactions.
Pending approval by the Board of Directors, the ISO hopes to file the changes with FERC by April 2023 and deploy them in June.
NYISO Strategic Plan
NYISO shared its 2022 Strategic Plan, which highlighted its responsibilities, accomplishments and future goals, as well as how state and federal policies help drive the ISO’s strategic objectives.
Executive Vice President Emilie Nelson said offshore wind represents the largest potential shift in New York’s resource mix and that the state Climate Action Council’s forthcoming final scoping plan will inform much of the ISO’s future work. Energy security has become a growing concern as geopolitics impact global supplies, she added.
Nelson told stakeholders that NYISO has taken on more responsibilities, such as developing a reliability needs assessment, increasing stakeholder communications and tackling multifaceted issues like cybersecurity.
Bruce Bleiweis of DC Energy asked Nelson what letter grade the ISO would give itself as a “leader in the application of technology.”
Nelson responded that NYISO performs at an “A” level.
Bleiweis disagreed, saying he and other stakeholders focused on the financial markets have been frustrated with their inability to win ISO backing for “relatively minor changes” to the transmission congestion contracts (TCC) market.
“We’ve been asking for certain changes to the TCC markets for six or eight years,” he said, saying a “simple posting of data” calculated by the ISO “seems to become a [$500,000] project.”
Bleiweis said his company doesn’t face such “roadblocks” in the other organized markets. “Once a project is approved by stakeholders and the ISO, they seem to move forward relatively quickly.”
Nelson said the ISO must make “difficult” tradeoffs between competing budget priorities.
Deliverability Rules
The MC approved proposed tariff language governing the deliverability of internal controllable lines (ICLs) such as Clean Path New York.
The rules would require a class year transmission project requesting capacity resource interconnection service for unforced capacity (UCAP) deliverability rights to be deliverable throughout the capacity region to which it proposes to inject energy and throughout the capacity region from which it proposes to withdraw energy.
Amanda Myott, NYISO market design specialist, said the ISO was proceeding with tariff revisions on the deliverability of ICLs before the rest of the ICL market design to ensure the changes apply to the class year 2023 deliverability analyses. (See “Ramp Limits on ‘Internal Controllable’ Lines,” NYISO Installed Capacity Working Group/Market Issues Working Group Briefs: Sept. 30, 2022.)
The changes approved by the MC also affect tariff Attachment S regarding the calculation of UCAP deration factors in the class year deliverability studies and expedited studies.
Pending board approval, the ISO intends to submit the revisions to FERC in January.
The March order only addressed upgrades that are part of a developer’s proposed PPT project. The new proposal, presented by Stuart Caplan of Troutman Pepper, would extend the ROFR provisions to “network upgrade facilities” that are required as a result of the transmission interconnection process. (See NY TOs Seek Clarification on ROFR for Upgrades.)
Without the changes, TOs must engage in case-by-case bilateral negotiations and FERC filings, resulting in a more time consuming and less transparent process, Caplan said.
Subject to board and FERC approval, the changes would be effective for the Long Island offshore wind transmission project.
Winter Capacity Assessment
Natural gas storage levels are higher than anticipated thanks to a mild fall, but they are still lower than previous years, according to the ISO’s winter capacity assessment.
Winter natural gas underground storage levels | NYISO
Distillate fuel inventories are well below the five-year average capacity, but generating units are still receiving deliveries, and inventories are approximately 95% of last year’s capacity, according to NYISO Vice President of Operations Aaron Markham.
Markham also shared that both the Sprainbrook-East Garden City Y49 line in Long Island and the Moses-Willis MW1 line would be taken out service this season for repairs.
A new report by the Massachusetts Commission on Clean Heat lays out a detailed roadmap for reducing buildings’ carbon footprint but stops short of recommending a ban on the installation of new fossil fuel-burning appliances.
The task force convened by Gov. Charlie Baker in January had a diverse membership holding strong and varied opinions on scheduling such a ban and could not reach a consensus on the issue. The report cited counterbalancing factors: Waiting to schedule a ban on new gas installations puts the state at risk of missing its climate protection goals; enacting a ban too quickly would create significant risks if the electrical grid, supply chain and workforce were not ready to support it.
The report also noted that rushing to ban gas appliances in an effort to reduce greenhouse gas emissions might actually boost them if clean electricity-generating resources were not yet online and fossil-fired power plants had to boost their output to run additional electric appliances.
The 66-page report issued Wednesday is only an advisory document, and the governor who commissioned it is a lame duck.
However, Baker will soon be succeeded by two-term state Attorney General Maura Healey, a Democrat whose campaign statements indicated strong support for climate protection measures. She has said she supports steps toward decarbonizing buildings, including authorizing individual municipalities to ban gas use in new construction.
The report says achieving the state’s building emission-reduction goals will be a “monumental undertaking” at great cost and lays out a potential framework through which to proceed.
Infrastructure
The report argues that the state should should move forward with policies based on the commercialized technologies available now and incorporate future advances as they become available. A joint energy system plan should lay out strategies to speed electrification and strategically retire or reduce the natural gas system.
Investments in new or expanded natural gas infrastructure should be redirected to support net-zero efforts, except for safety and reliability, in which case they also should be made “within the context of the shift toward electrification,” the report says. The governor should direct relevant state agencies to report on the potential risks and benefits of an enforceable phaseout of new fossil fuel heating systems.
The report argues that progress toward building decarbonization depends on progress toward increased electrical supply. Human infrastructure also is important: Significantly more funding is needed for workforce training.
And Massachusetts should immediately start to create a Clean Heat Standard, it says. The state should also create a climate bank to help provide affordable capital for projects, as traditional private-sector lenders are reluctant to invest in building decarbonization at this stage.
Equity
Environmental justice (EJ) and low- to middle-income (LMI) communities should be first in line for the transition to clean energy, the report says.
These communities — as well as the Black, indigenous and people of color population and frontline communities — should have a robust role in every stage of planning, implementation and evaluation of a program and should be compensated for their input. Information generated at all stages of the process should be made available in at least the five most common languages in the subregion.
LMI households must not bear the rising costs of remaining gas infrastructure as the transition progresses, the report says. Means-tested subsidies, carveouts and packaging of multiple incentives should be used to increase the equitable impact of energy transition programs.
LMI housing stock should also receive additional funding for necessary improvements not directly connected to decarbonization, such as roof repairs, basement waterproofing and hazardous material mitigation, the report says. Hiring and procurement processes should prioritize minority- and women-owned business enterprises and other disadvantaged participants.
Angst
The report list hurdles to clear that include inflation; a potential economic recession; diverse housing stock; high housing costs; a labor force with limited experience in the work that needs to be done; socioeconomic and racial inequities; the complexity of a multilayered government; the real and perceived cost of electricity and fossil fuels; and the tendency to not replace heating systems until they fail.
The transition will carry “very real burdens,” particularly for businesses, consumers and workers for whom there is no good alternative to fossil fuels, the report says. But it will also bring “significant benefits and opportunities,” including better health, climate protection and an enormous opportunity to invest in the state economy and workforce.
Public outreach and awareness are needed to show the state’s commitment to clean heat, and to highlight success stories. The state should evaluate ways to mitigate the cost of electric heat in the near- and intermediate-term, so that it is less expensive than gas, the report argues.
Substantial incentives will be needed, perhaps for a long time, as a signal of support to both consumers and suppliers, it says. Stakeholders reliant on fossil fuel must have clear and consistent market signals about the need to make the transition, and they will require resources to carry it out.
Massachusetts needs to focus more on its goals and the people those goals will benefit than on the programs it uses to accomplish these things, according to the report. The governor and legislature should create a new Building Decarbonization Clearinghouse as an umbrella for incentives, funding sources and technical assistance.
Delay and inaction will push back, but not cancel, the transition and make it more costly.
Goal
The Massachusetts Clean Energy and Climate Plan sets goals of a 28% reduction in building greenhouse gas emissions over 1990 levels by 2025 and a 47% reduction by 2030; the ultimate goal is net zero by 2050.
To reach this, an estimated 500,000 homes and 300 million square feet of commercial space will need to be using energy-efficient electric heat by 2030, and 100,000 homes would need to be converted per year after 2030.
Beyond the actual heating systems, 1.5 million Massachusetts homes will require weatherization and other structural efficiency upgrades by 2050 to achieve the desired reduction in GHG emissions.
The commission took no position on how to apportion the cost of clean heat infrastructure among ratepayers, taxpayers, regulated suppliers and markets.
It did say that cost and benefit of proposals should be evaluated not in terms of cost-effectiveness but for their societal impact.
CARMEL, Ind. — MISO said Tuesday that it will add an informational study on near-term transmission congestion to its 2023 transmission-planning cycle.
However, the study is unlikely to result in any cost-shared projects.
Speaking during a Planning Advisory Committee meeting Tuesday, MISO engineering adviser Ben Stearney said the RTO will use near-term economic models to examine congestion up to five years out. MISO typically studies congestion in 10- to 15-year-out modeling, but stakeholders have said congestion is increasing and deserves attention and relief projects.
“I do want to emphasize that MISO will not be proposing any new cost-allocation mechanisms or project types in concert with this analysis,” Stearney said, adding that any identified projects will be taken up and funded only by market participants.
He said staff used production cost models to determine that a new study for the 2023 Transmission Expansion Plan (MTEP 23) “could provide valuable insight into current system congestion as well as inform parallel study efforts.”
“We’ve done some investigation work, but we’ve never really done a study like this,” Stearney said. A near-term congestion study could help inform MISO’s other MTEP modeling work, he said.
Stearney said the RTO’s models were able to recreate some of the footprint’s top binding constraints.
Energy consultant Kavita Maini said in her home base of Wisconsin, congestion is a persistent problem. She said it would be helpful for MISO to pinpoint projects that can mitigate congestion.
“Congestion is very real, and the Independent Market Monitor has spoken about it as well,” Maini said.
Clean Grid Alliance’s Natalie McIntire asked that the grid operator explore pathways beyond participant funding for possible projects emerging from the study. She asked staff not to foreclose the possibility that MISO could land on a project that fits the criteria of a market efficiency project.
“We’re talking about congestion here that’s costing consumers a lot of money,” McIntire said.
MISO said last spring that it was mulling adding a class of smaller, congestion-relieving projects under its annual transmission planning cycle, inspired by its targeted market efficiency projects with PJM. (See MISO Considers Adding Smaller Congestion Relief Projects.)
The RTO later said it encountered modeling obstacles to adding a new study focused on solving near-term congestion. Staff said they had difficulty recreating some historical congestion in its planning models.
In October, Stearney said MISO needs to improve on how real-time congestion is captured in its modeling to identify worthwhile upgrades.
“MISO regional models are not tailored toward this type of analysis, so additional complications are expected,” the grid operator said at the time.
While Russia’s war on Ukraine has triggered a global “dash to natural gas” to replace lost Russian supplies, it has also created a bull market for electric heat pumps, with sales in Europe up 35% in 2021 and Poland doubling sales in the first half of 2022, according to new reports on global energy efficiency from the International Energy Agency (IEA).
“Energy efficiency is now at the center of policy agendas [as] governments and citizens around the world urgently look to save energy, secure supply and reduce energy bills,” said Nicholas Howarth, IEA energy policy analyst and lead author of the Energy Efficiency 2022 report, released on Friday. “We’re seeing strong signs of governments turning to efficiency, as they did in the 1970s, as it is the best way to simultaneously meet energy, affordability, security and climate goals.”
The central question, Howarth said at a media briefing on the report Thursday, is whether 2022 will “be a turning point for energy efficiency” to take a leading role in the global response to the current energy and climate crises.
The signs are encouraging, according to the IEA report. First, energy intensity — the amount of energy needed to produce one unit of gross domestic product — is expected to rise 2% in 2022, a four-fold increase over the previous two years, when the COVID-19 pandemic slowed both energy demand and efficiency measures, Howarth said.
In addition, global spending on energy efficiency could hit $560 billion this year, a new record, according to the report. Efficiency also represents about two-thirds of all clean energy and economic recovery spending since 2020. The report calls out the Inflation Reduction Act in the U.S., Europe’s REPowerEU Plan and Japan’s Green Transformation Initiative as examples of national efforts that are “driving this progress on efficiency.”
At an IEA conference on energy efficiency in Denmark in June, 26 countries, including the U.S., issued a joint statement underlining the importance of efficiency and calling for stronger action on national initiatives.
The report also points to the electrification of transportation and heating, which, it says, have reached a tipping point. “One in every eight cars sold globally is now electric, while almost 3 million heat pumps were sold in 2022 in Europe alone as they become the preferred heating option,” the report says.
Public campaigns are raising awareness of energy-saving technologies, which, in turn, are raising consumer perceptions of their value, the report says. “While energy cost-of-living pressures have risen considerably, efficiency actions implemented over the last 20 years are now saving consumers in IEA countries $680 billion off their energy bills this year at current prices,” the report says.
IEA has 31 member countries, including the U.S., and 11 “association” countries, which include China and Ukraine.
The savings for individual homeowners can be significant. In the U.K., for example, efficient homes can cut their energy bills by 40%, Howarth said. “[U.K.] families with the least efficient homes will be paying up to three times more for the same level of comfort … and the same story is true in every country.”
Switching to an electric vehicle provides similar savings: 40% over the most efficient gas-powered car, the report says.
Fuel bills for different personal vehicle types in Europe, June 2021-2022. Gas powered vehicles have become more efficient, but electric vehicles are still more efficient and less expensive to run. | IEA
In a separate report on heat pumps released Wednesday, the IEA projected that if all countries fulfilled their current pledges to cut greenhouse gas emissions, the global capacity for heat pumps could jump from 1,000 GW in 2021 to 2,600 GW by 2030, cutting fossil fuel use for heating in buildings almost in half.
The Energy Efficiency report also noted that a growing number of countries and “subnational governments” — cities, states and provinces — are banning or phasing out natural gas in new construction. Germany is planning a ban on fossil fuel heating in new construction beginning in 2024, while France is banning new gas connections in 2023. The Netherlands will require heat pumps in buildings beginning in 2026.
The issue has become a political flashpoint in the U.S., with 20 states prohibiting bans on natural gas hookups, while a growing number of cities and counties have passed bans on gas hookups in new construction. Montgomery County, Md., became the latest jurisdiction to take action, with the County Council on Tuesday passing legislation that requires all new construction to be all electric, with new regulations to be issued by the end of 2026 and 2027. (See Montgomery County, Md., Passes Building Electrification Law.)
Waiting for IRA Rebates
Energy conservation efforts in the U.S. and Europe date back to the OPEC oil embargo of 1973-1974. In the U.S., the embargo is associated with long lines at gas stations nationwide, a 55-mph speed limit and the first fuel economy standards. IEA itself grew out of international efforts to secure oil supplies at that time.
Steven Nadel, executive director of the American Council for an Energy-Efficient Economy (ACEEE), agrees with IEA framing of the war in Ukraine as a major factor for a ramp-up of energy-efficiency measures globally.
The war is “also affecting the U.S. because we are exporting a lot more LNG to Europe. Our prices have gone up quite a bit, and that’s been a major contributor to inflation but also a major contributor to consumers’ interest in trying to use efficiency,” he said.
The most recent Short-Term Energy Outlook from the U.S. Energy Information Administration projects that homes using heating oil for space heating will be spending 45% more than last year.
“When you have these types of prices — yes, consumers will care a lot more about efficiency,” he said.
The IRA has both tax credits and a range of rebates for energy efficiency home improvements, but Nadel does not expect the law to have a major impact this winter.
“All the IRA programs, they’ve passed, but the money’s not yet reaching the states, let alone consumers,” he said. The Department of Energy, Internal Revenue Service and other agencies still have to translate the law’s “fairly vague pronouncements” into regulations and guidelines. But, he said, the $3.5 billion in funds for low-income home weatherization in the Infrastructure Investment and Jobs Act is starting to flow.
“The demand for this program is greater than the supply,” he said. “This money will help, but it will not meet all of the demand.”
ACEEE on Thursday launched a new initiative, Residential Retrofits for Energy Equity, with $2.5 million from the Rockefeller Foundation and $250,000 each from JPMorgan Chase and the Wells Fargo Foundation. The initiative aims to “jump-start” energy-efficient upgrades for affordable housing.
US Energy Inflation is Low
Increased spending and action on energy efficiency also face major hurdles, first and foremost, the $550 billion that IEA estimates governments worldwide have allocated thus far to shield consumers from high energy prices. In developing countries, government support for consumers ”now exceeds that provided for clean energy investments since 2020,” Horwath said.
“Energy-related cost-of-living pressures are a major concern this year, driven by high fossil fuel prices,” Howarth said. “Increased energy costs being the single biggest contributor to inflation experienced this year in most countries, pushing up the cost of living for families worldwide and setting back progress on energy access in emerging and developing countries.”
Year-on-year change in energy price inflation, October 2022. The U.S. has one of the lower inflation rates, while Mexico is at the bottom of the list. | IEA
The U.S. is one of a small number of nations with relatively low energy cost inflation, according to the Energy Efficiency report: about 18% compared to some European countries. The Netherlands has seen a 100% jump in energy costs, while in the U.K., energy prices are up 59% year over year.
IEA cautions that short-term consumer support should “not weaken incentives to reduce energy waste or slow the switch to low-carbon supply. The least efficient interventions are those that lower market prices for energy through direct fossil fuel consumption subsidies, indiscriminately applied to all customers. Such subsidies risk removing the incentives to improve efficiency and disproportionately benefit wealthier consumers who are large energy consumers.”
The heat pump report looks at more practical barriers: the still-high upfront costs of some efficiency technologies and a shortage of qualified installers. According to the report, financial incentives for heat pumps are now available in 30 countries, “covering more than 70% of today’s heating demand.” The IRA offers rebates of $2,000 to $8,000 for installing a heat pump, depending on household income.
IEA sees the global demand for full-time heat pump installers quadrupling by 2030 and suggests “incorporating heat pumps into existing certifications for heating technicians, plumbers and electric engineers, who have similar skills,” and offering financial incentives to “attract new workers to specialized training programs.”
The California Public Utilities Commission on Thursday allowed Pacific Gas & Electric to exit an enhanced oversight and enforcement process the CPUC created two years ago to prevent the utility from starting catastrophic wildfires, but commissioners warned they would use the process again if needed.
Before the unanimous vote on a resolution freeing the utility from enhanced oversight, commissioners emphasized that PG&E had entered the first step of the six-step process because of particular problems with its vegetation management practices, and that it was being released because it had met specific goals imposed by the CPUC.
“This is an illustration of how the enhanced oversight and enforcement process can be effectively used,” Commissioner Clifford Rechtschaffen said. “It worked here. It’s of course not a panacea. No one is suggesting it is, but it did work. It did address an important problem. So, we should not be bashful about using it again.”
“PG&E’s operational practices remain a serious concern for us, despite everything that’s been done, so we should continue to utilize this tool,” Rechtschaffen added.
Commissioner Genevieve Shiroma said she would vote for the resolution, but “I do want to be very clear about the limited scope of this resolution and my continued concerns with PG&E’s operations.”
Other speakers noted that a number of CPUC actions targeting PG&E remain in place. They include an independent safety monitor that reports every six months on the utility operations; specific metrics to evaluate PG&E’s safety performance and to implement the enhanced oversight and enforcement (EOE) process; and continuing investigations of PG&E intended to rein in unsafe practices.
The CPUC required PG&E to accept the EOE process as a condition of it approving PG&E’s bankruptcy organization plan in June 2020.
In September of that year, a leaning gray pine fell onto a PG&E line and started the Zogg Fire in rural Northern California, killing four people and leading to additional scrutiny of PG&E’s tree clearing efforts by the CPUC and the federal judge who oversaw PG&E’s criminal probation from the 2010 San Bruno gas explosion.
The CPUC used the process for the first and only time against PG&E in April 2021, passing a resolution that said the utility was not “sufficiently prioritizing its enhanced vegetation management based on risk.”
PG&E had ranked its power lines based on wildfire risk but failed to perform the majority of its enhanced vegetation management “or even a significant portion of work” on its highest risk lines, the CPUC said at the time. The commission ordered PG&E to submit a corrective action plan and to report every 90 days on its progress clearing high-risk lines of trees and overhanging branches.
Trees and branches falling onto PG&E power lines caused devastating fires over the past five years, including last year’s nearly 1 million-acre Dixie Fire, many of the Wine Country fires of 2017 and the Zogg Fire.
The Utility Reform Network and the CPUC’s Public Advocate’s (Cal Advocates) office argued in a joint filing that the Dixie Fire and other activities warranted placing PG&E into a higher step of the EOE process, with escalating oversight and penalties.
The Dixie Fire burned for more than three months in the northern Sierra Nevada and southern Cascade ranges of California. | U.S. Forest Service
“Of particular note was PG&E’s failure to identify and remove the damaged and decayed tree” that started the Dixie Fire,” TURN and Cal Advocates said.
“When the tree fell and contacted PG&E lines, the utility demonstrated no sense of urgency despite the history of extreme fire danger and poor access in the surrounding region,” they said, citing the findings of the California Department of Forestry and Fire Protection. “PG&E’s delayed response allowed the tree to remain in contact with energized lines for approximately 10 hours and was a direct and negligent factor in the ignition of the fire.”
The CPUC decided those concerns and others were outside the bounds of the current proceeding. They found that PG&E had met the requirements of its corrective action plan and shown that it had prioritized work on high-risk lines.
“PG&E’s goal was to perform more than 80% of its [enhanced vegetation management] work in the top 20% highest risk circuit protection zones in 2021,” Thursday’s resolution said. The utility exceeded that goal by completing 98% of its tree clearing in 2021 on its highest risk lines and met other CPUC criteria, allowing to leave the EOE process, it said.
A study recently published by NERC pours cold water on the idea that utilities can safely leave some distributed energy resources (DER) out of their interconnection studies without affecting the accuracy of their models.
The DER Modeling Study: Investigating Modeling Thresholds, released last month, was intended to respond to industry stakeholders’ comments on various documents on DER modeling produced by NERC’s System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG). While the group has consistently argued for a threshold of 0 MVA for gathering data to populate system models, some industry participants have pushed for non-zero thresholds to reduce the resources needed for data collection.
NERC defines DER as “any source of electric power located on the distribution system” — facilities located behind a transmission-distribution transformer that serve end-use customers, such as rooftop solar panels and energy storage in homes and businesses.
Because they sit behind the meter, DER have traditionally been viewed as a part of the distribution system only, with little or no impact on the broader bulk power system, SPIDERWG has previously noted. (See NERC’s SPIDER Group Warns of Modeling Difficulties for DERs.)
Total DER output during delayed clearing bus fault | NERC
But with the number of DER on the distribution system growing rapidly and potentially affecting customers’ energy usage patterns, the group said in November that transmission planners and planning coordinators can no longer ignore their impacts. (See NERC’s DER Strategy Focuses on Industry Education, Collaboration.)
The study used a base case provided by WECC, modified to simulate the effects of not modeling various amounts of DER depending on their size. NERC believed this approach would simulate the effect of using thresholds other than 0 in modeling data. The team chose a scenario representing a heavy load condition for spring 2023, which assumed 8.41% of load served by DER — the highest level in the Western Interconnection of all base cases considered.
NERC set thresholds for the study using various measures. Aside from the base case, which includes all 12.7 GW of DER that would normally be accounted for in the model, seven cases were considered:
The same as the base case but ignoring generators with a rating of less than 75 MVA under NERC’s DER_A model developed by SPIDERWG;
Similar to the above, with a threshold of 20 MVA;
Threshold of 5 MVA;
Similar to the above cases, but DER are ignored when they account for 10% or less of the “load record” (an aggregate representation of end-use load in the base case); DER modeling adds an offset or a separate generator record to the load record to represent DER generation;
Similar to previous, but with a 25% threshold;
50% threshold; and
Same as the base case, but only including DER that backfeed energy into the bulk electric system.
The study simulated the loss of two large conventional generation facilities, along with the loss of the major HVDC intertie between California and the Pacific Northwest to determine the impact on frequency stability. Report authors also used a transmission fault simulation to study the dynamic response of the system under a variety of conditions.
Results showed notable differences in behavior when the simulated faults were applied. In the cases other than the 10%, excluding DER led to an increase or decrease in the frequency nadir for the system under the resource loss scenarios. NERC noted that the 10% threshold performed most like the base case, perhaps because this change reduced the level of DER the least, with only 390 MW of generation excluded from the model. This left almost 97% of DER still modeled.
The team called this finding “a testament to having proper data collection and data verification procedures in place,” saying accurate study results can still be achieved, even if some generation data is excluded, because “the data verification can fine tune capacity and control parameters to ensure accurate study results over time.”
However, NERC concluded that changing the modeling threshold beyond the 10% case “did have a significant difference in simulated system level performance,” which contradicted stakeholders’ suggestion that they could plan the system safely with different thresholds. Authors recommended that grid planners gather the total DER capacity for their footprints, though they allowed that different modeling thresholds could be set if appropriate for local systems.
The report also called for future studies to “target different aspects of simulated DER output” that did not fall in this study’s purpose. Such studies could include investigations of the effect of modeling lower thresholds of DER, or using different assumptions for the faults studied.
SPP on Wednesday released a final proposal detailing the proposed governance structure, basic market design and other key features for the RTO’s day-ahead market offering in the Western Interconnection.
The RTO will now spend the next few months engaging with parties that have already expressed interest in committing to Markets+, a conceptual bundle of services that centralizes day-ahead and real-time unit commitment and dispatch. SPP says the market and its “hurdle-free transmission service” will help integrate the region’s rapidly growing fleet of renewable generation.
SPP has held several in-person meetings and webinars over the past year to gather input and reach agreement with potential stakeholders on the service offering. CEO Barbara Sugg said in a press release that collaborating with Western stakeholders on the Markets+ design has been a “tremendous effort.” (See Governance, Resource Adequacy Key to SPP’s Markets+.)
“Thanks to the dedication and engagement of these entities over the past year, I’m confident we can design and deliver a market that addresses challenges unique to the region and provides value to western customers,” she said.
SPP’s final Markets+ service offering | SPP
The service offering anticipates a two-phase process for continued development of Markets+. Potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents in the first phase. A second phase begins after FERC’s approval of the tariff; SPP will acquire the necessary software and hardware while participating entities fully commit to fund and are integrated into the system.
Parties interested in committing to financing further development of the market must sign a funding agreement by April 1 that will cover SPP staff’s involvement.
Load and/or generation entities that sign the agreement would get a vote on the Markets+ Participants Executive Committee (MPEC) in the first phase, and their representatives would be eligible for appointment to working groups and task forces. Those without load or generation would sign a participation agreement and make a one-time $5,000 payment or obtain a waiver in order to vote on tariff and protocol recommendations.
The MPEC is akin to SPP’s Markets and Operations Policy Committee in the Eastern Interconnection. It will provide a forum for market participants, stakeholders and non-voting stakeholders to discuss issues and to review system or process-improvement proposals recommended by SPP, the Markets+ State Committee and members and stakeholders.
The committee will report to the Markets+ Independent Panel (MIP), the highest level of authority for decisions related to the market, but with the SPP Board of Directors providing independent oversight. SPP said the board will “give significant recognition and deference to the [MIP’s] decision-making role.”
Because the RTO does not expect the MIP to be established during phase one, a three-person subcommittee of the SPP board will perform the decision-making functions until the MIP can be formed.
CARMEL, Ind. — MISO sparked strong reactions from stakeholders Tuesday when it fired up the second phase of its long-range transmission plan (LRTP) by debuting a theoretical map of projects.
In a presentation to MISO’s Planning Advisory Committee, the RTO’s Senior Director of Transmission Planning Laura Rauch revealed a “conceptual map” of possible projects that may arise from a second attempt at a long-range analysis.
Some members were startled by the potential scope of the RTO’s ambitions.
The possibilities for MISO Midwest include a crisscrossing system of new 345-kV lines, a network of 765-kV lines, a handful of 138-kV lines and even one HVDC line across Lake Michigan and another spanning North Dakota and Minnesota.
MISO’s first $10 billion LRTP portfolio was also confined to MISO Midwest. The RTO doesn’t plan to address MISO South needs until the third leg of its long-range transmission planning. (See MISO Board Approves $10B in Long-range Tx Projects.)
Rauch cautioned that MISO’s conceptual map does not represent what a final portfolio would look like.
All line ideas considered under MISO’s 2nd LRTP portfolio | MISO
“This is a starting point, not an ending point,” she said, adding that the line routes are educated guesses because MISO doesn’t yet know how siting will play out.
“I’m sure there are things on this map that we will not want to analyze. I’m sure there are some substations that cannot handle … the magnitude of transmission,” she said.
Rauch said it’s still an open question whether the second LRTP cycle should include 765-kV and dispatchable HVDC lines.
Some stakeholders said they were taken aback by the scale of MISO’s envisioned second LRTP.
“When you throw this slide up, this is very expensive, what’s on here. Much more expensive than tranche one,” said Jim Dauphinais, an attorney for the Coalition of Midwest Transmission Customers.
Rauch said the map could potentially be the “size of the answer,” but added that the resulting portfolio could be smaller.
WEC Energy Group’s Chris Plante called the map “uncharted territory” and said it was premature for MISO to publish the map before it ran analyses. Plante also said that the map doesn’t include some lines utilities deemed necessary. He cautioned against sharing the map with MISO’s Board of Directors next week at its quarterly meeting in Orlando, Fla.
Other stakeholders said MISO’s release of the map might preclude consideration of other necessary transmission solutions that should be included in the second LRTP.
“I understand where you’re coming from. At the end of the day, the analysis will win out,” Rauch said. “This is going to be a long ride based on analysis. … Our intention was not to say we must do everything.”
While acknowledging that the release of the map may have been a “messy” way of broaching the issue, Rauch said it’s necessary to prepare stakeholders for MISO’s future system needs. She added that stakeholder LRTP workshops in 2023 will cover the RTO’s reasoning behind the hypothetical map of lines.
Rauch said MISO is building models to prepare for the second portfolio recommendation in 2023.
“We’re seeing member plans accelerating. We’ll continue to work through the futures and reflect that,” she told stakeholders.
The RTO is updating the data behind its three, 20-year transmission planning futures in time for more long-range transmission planning and work on the 2023 Transmission Expansion Plan (MTEP 23).
Changes will include revised state and member decarbonization goals, resource retirements, resource additions based on its interconnection queue, accredited capacity amounts, and capital, operating and fuel costs. MISO did not alter the 20-year load forecast behind the three planning futures.
So far, MISO has only shared preliminary information on its moderate, second future. The RTO said it foresees 270 GW of new resources and has 115 GW of resource retirements. It also anticipates a 90% reduction in emissions by 2042, faster than it previously projected.
The grid operator plans to share estimates from its conservative Future 1 and aggressive Future 3 next spring.
The second planning future will serve as the “focal point” for the lines MISO will plan under the second LRTP, Rauch said.
Zeroing in on Cost Allocation
A day before stakeholders got a glimpse of MISO’s controversial planning map, they heard how MISO continues to assess how to develop a more targeted cost sharing methodology for LRTP projects.
Speaking at a stakeholder meeting on Nov. 28, cost allocation specialist Milica Geissler said the RTO will analyze whether it can allocate transmission costs by relying on more granular measures of identifying who benefits — and what the benefits are.
Geissler said MISO will examine the subregional benefits of preventing load shed, meeting NERC criteria, weathering extreme events, furthering state decarbonization goals and increasing transfer capability.
At the local zonal level, the RTO will test the benefits of avoided transmission investment, congestion and fuel savings, improved operating reserves and savings associated with resource adequacy. It will not test for any benefits on a footprint-wide basis because of its Midwest-South transfer constraint.
Some stakeholders argued that there’s too much overlap among the factors being considered to identify standalone benefits.
Plante said projecting some of the benefits into the future is akin “to throwing a dart in a blackened room” because benefits change over time and MISO lacks insight into future resource siting and expansion.
Clean Grid Alliance’s Natalie McIntire said MISO shouldn’t assume that the Midwest and South regions are unable to help each other during extreme events. The RTO’s Director of Cost Allocation and Competitive Transmission Jeremiah Doner said that while such benefits aren’t “zero,” they’re not enough to measure on a footprint-wide basis.
Mississippi Public Service Commission attorney David Carr encouraged MISO to consider that including decarbonization benefits might make it more difficult for some projects to get approval from certain utility commissions.
Geissler said MISO is at this point only pondering the benefits and hasn’t determined which ones will make the final cut. She added that the RTO isn’t willing to apply any proposed changes to projects already in progress, saying it “finds a lot of value” in current allocations.
MISO is using a 100% postage stamp to load rate for the first two cycles of projects coming out of its LRTP studies, with those costs confined to MISO Midwest. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.) But a new cost allocation approach that considers more beneficiaries could be applied to upcoming planning for the South region.
Carr said MISO should re-examine the assumption that load bear the “entirety” of long-range transmission costs. He made the argument in light of Montana-Dakota Utilities’ suggestion that new intermittent generation, in addition to load, should bear a portion of LRTP costs. (See MISO Gathering Stakeholder Input on LRTP Cost Allocation.)
“Transmission costs are a much larger share of customers’ bills. This situation is untenable,” Carr said.
Carr also pointed out that years ago, MISO South didn’t have any input in the postage stamp cost allocation.
Some stakeholders have voiced concerns about disparate treatment between LRTP portfolios, saying a different cost allocation for projects concerning MISO South will violate FERC’s requirement that the same class of projects should not be subject to different allocations.
In October, Geissler said planners were wrestling with how to assign an evolving cost allocation when beneficiaries of a line change over time. Some stakeholders have requested that MISO find a way to identify and mete out costs to new beneficiaries over time.
“I’m very thankful for the 2011 portfolio of projects,” Geissler said, referring to MISO’s Multi-Value Projects approved a decade ago. She said those projects show how benefit-to-cost ratios either increased or decreased over time depending on the transmission pricing zone.
“They change in a pattern that isn’t necessarily obvious,” Geissler said of benefits. She said those fluctuations mean that future beneficiaries might be difficult to predict over time.
However, stakeholders said the zones that over time realized the most benefits from the 2011 portfolio contained the most wind generation.
