The Vermont Climate Council has begun the thorny work of aligning the state’s existing Comprehensive Energy Plan with a new Climate Action Plan that is due at the end of the year.
The plans will “move in parallel” and are “intended ultimately to intersect so that they are consistent with each other and they inform each other,” Vermont Department of Public Service Commissioner and Climate Council member June Tierney said at the latest council meeting March 22.
For decades, Vermont’s energy plan has been based on the principles of least-cost resource planning, which Tierney said considers greenhouse gases and the use of an environmentally sound energy supply.
“Before the Climate Council was founded, [the energy plan] was principally the place where the state dealt with addressing climate change in the energy sector,” she said. The last energy plan was completed in 2016.
Passage of the Global Warming Solutions Act last year established the council and gave it the task of developing Vermont’s first climate plan. The act also altered the statute governing the energy plan to mandate that it is consistent with the climate plan and the new law’s GHG requirements.
The DPS and the council must now decide how to coordinate their respective plans. A major overlapping area between the two is GHG reduction requirements, according to TJ Poor, DPS director of efficiency and energy resources. They also will both provide an energy sector analysis for policy and technology scenarios, ensure stakeholder engagement and consider issues on equity, he said.
Some DPS staff in charge of the energy plan also are council members, and Tierney said aligning their work is a challenge.
“We are struggling a little at the department to maintain clarity about the need for us to achieve the mission that we have been given as the chief planning competency in the state on energy issues, as we also participate in the council’s work that clearly informs if not shapes a lot of what we are now doing,” she said.
Recognizing the significant role the DPS has in helping the council achieve its goals, Tierney has allocated about half of the department’s resources to the council. But she said the department must be responsible for completing the energy plan on time.
With the climate plan due in December, and the next energy plan due in January, there is a sense of urgency growing in their development. That urgency is compounded by the fact that the preparation and release schedules for the plans will not line up again until 2033. The council has been active since November, but much of its work to date has focused on building processes and procedures.
“I am concerned about the amount of work that has to be done in the amount of time that we have,” Tierney said. It can be done, she added, if council members can find areas that will allow for compromise, such as foundational data.
“It does not serve anybody for the state to [have] two voices on how we measure greenhouse gases or emissions,” Tierney said. “We need to have some uniformity there.”
While the energy plan will need to model emissions for the energy sector, the climate plan will be responsible for emissions in all non-energy sectors. The low emissions analysis platform that the department is using already for energy sector sources could also support the council’s work, Poor said.
The council expects to issue a draft climate plan for public comment on Oct. 1.
In the absence of clear national policies and strategies, action for transitioning to a net-zero economy is being mobilized through investors and financial markets, financial institutions, insurance companies, regulators and courts, Maryam Golnaraghi said at a Cornell University webinar Monday.
“This was mobilized not because the world realized that climate change was the biggest problem but … with the 2007-2008 financial crisis … which compromised the financial stability of governments and financial institutions,” said Golnaraghi, director of climate change and emerging environmental topics at the Geneva Association, an international think tank of the insurance industry. A Cornell alumna, she has worked for more than 25 years in senior advisory positions in industry, government and the U.N., and was the lead author of the Geneva Association’s February 2021 report on climate risk assessment.
Central banks, she said, started thinking about whether there were other factors that could lead to similar economic instability.
NASA’s Terra satellite was able to capture the huge swath of smoke generated by the California wildfires and dispersed by the winds surrounding those fires on Aug. 20, 2020. | NASA
Despite the science becoming more widely available through the U.N.’s Intergovernmental Panel on Climate Change, “only in the last five years has the debate about climate change shifted from skepticism about the science … to a real foundation for socioeconomic development; to a real topic around financial stability, about innovation around labor and trade,” Golnaraghi said.
Among the most prominent risks the World Economic Forum has identified are climate change and its associated financial and socioeconomic risks. Transitioning will affect every sector, most importantly the energy sector, she said.
“If we continue to rely on carbon-intensive agriculture, transportation and production of chemicals, ultimately we bring our climate system to a point where the risk, particularly from increasing severity and frequency of extreme events, becomes so high that it becomes an existential risk to the society,” Golnaraghi said.
She said it is “very important” to reform the financial system to transition to a net-zero economy and encourage investors to think long-term. The No. 1 priority is to be able to quantify the risks and then map out a way to go from experience to forward-looking climate risk modeling.
Material Risk
The key to government and industry collaboration on climate change is accessibility to risk information, Golnaraghi said. For emerging economies, the insurance industry has pulled in the U.N. and World Bank Group to avail these kinds of risk analytics and development of risk information in developing economies.
Maryam Golnaraghi, Geneva Association | Cornell University
Canada, through the engagement of the banking and insurance sectors and the government, is reforming its post-disaster aid and is thinking about reforming its risk management, she said.
“I’m also facilitating these discussions in the United States and similarly in England, Australia and Germany, just as examples,” Golnaraghi said. “Now, when you see five major, mature economies start through ever-stronger industry-government collaboration to address these issues, other economies will follow.”
Building capacities to withstand extreme risk is becoming the norm, she said. While international businesses have incorporated climate change into their core planning, she added, the U.S. still does not have a carbon tax or a clear policy around climate change.
Three-quarters of economists who study climate issues say “immediate and drastic action” is needed to address climate change, according to a new survey, a 50% increase over a similar survey in 2015.
The biggest reason for the increase: “extreme weather events attributed to climate change.”
The economists also predicted climate change will hurt the economy and worsen income inequality, and said efforts to mitigate change would be cheaper than dealing with the effects of it.
The New York University School of Law’s Institute for Policy Integrity heard from 738 economists out of the 2,169 invited to participate — all of whom had published articles on climate in 45 top-rated economics, environmental economics and development economics journals — for a response rate of 34%.
| Institute for Policy Integrity
In IPI’s 2015 survey, involving 365 economists, only 50% thought immediate and drastic action was needed.
The new survey found 74% favoring immediate action and another 24% agreeing “some action should be taken now,” with 2% calling for more research before taking action and 1% saying climate change is “not a serious problem.”
“People who spend their careers studying our economy are in widespread agreement that climate change will be expensive, potentially devastatingly so,” said Peter Howard, economics director at the institute, who co-authored the study. “These findings show a clear economic case for urgent climate action.”
About 41% of respondents said their concern over climate change had “strongly increased” over the past five years, with another 38% saying it had “somewhat increased.”
Asked to identify up to three factors that most affected their views on climate change in recent years, the most common answer, selected by 52% of respondents, was “observed extreme weather events attributed to climate change.”
New findings in climate science (31%) and new findings in climate economics and the social sciences (29%) also were widely cited.
| Institute for Policy Integrity
“These empirical observations of climate impacts appear to have had an outsize role in shaping economists’ views, perhaps due to the high level of damage caused by recent extreme weather events (such as wildfires in Australia and the Western United States, heat waves in Europe and historically large numbers of hurricanes),” wrote Howard and Derek Sylvan, the institute’s strategy director. “Such events may also have stood out to economists because many projections anticipated that the current levels of temperature increase and climate-linked extreme weather would take longer to manifest than they have. … Extreme weather events also frequently elevate the general public’s level of concern about climate change.”
There also was consensus that climate change will hurt economic growth (42% calling it “extremely likely” and 36% calling it “likely”) and that it was likely to increase income inequality between the richest and poorest countries (89%). Seven in 10 said it was also likely to increase inequality within countries.
The good news? Almost two-thirds expect emerging zero-emission and negative-emission technologies to experience the kinds of cost declines seen in wind and solar generation.
Asked what percentage of the global energy mix will be zero-emission technologies (e.g., solar, wind, nuclear, green hydrogen, bioenergy, and carbon capture and storage) by 2050, the median response was 50.5%. Zero-emission sources are currently 10% of the energy mix, according to the International Energy Agency.
About half of the economists said they expected net-negative greenhouse gas emission technologies, such as direct air capture and carbon capture/utilization/storage to become reliable and cost competitive for large-scale adoption by 2060, with about 12% expecting a role by 2080. More than 5% said the technology will never work at scale, and “roughly 25% of respondents chose the ‘No Opinion’ option, suggesting a high level of uncertainty for this question,” the authors wrote.
| Institute for Policy Integrity
Most scenarios for limiting temperatures to 1.5 degrees Celsius above preindustrial levels assume wide use of negative-emissions technologies by midcentury, the authors noted.
But they said the optimism of the economists “should be tempered somewhat, as engineers and other categories of experts may have equally (or more) relevant insights on these issues than economists, and their views may differ. Many researchers who focus on the energy transition advise a ‘precautionary approach’ with respect to negative-emissions technologies, given that they are unproven and overreliance on these technologies could deter necessary emissions reductions in the near term.”
The median of the economists’ projections predicted that economic damages from climate change will hit $1.7 trillion annually by 2025 (with a 1.2-C increase over pre-industrial levels) and about $30 trillion per year — at least 5% of GDP — by 2075 (+3 C).
Two-thirds of the respondents said the benefits of reaching net-zero GHG targets by 2050 is likely (35%) or very likely (31%) to outweigh the expected costs. Almost one in five said the cost-benefit was unclear, while 12% said benefits were unlikely to outweigh costs.
The 15-question survey did not ask the economists about potential policy solutions, such as spending on research or imposing carbon fees. But the authors said the “consensus views of economists with expertise on climate change can provide valuable insights for policymakers who must weigh the benefits and costs of various climate strategies.”
The authors cited criticism of integrated assessment models (IAMs) used to estimate the social cost of carbon (SCC), which is used in federal government cost-benefit analyses.
“IAMs and the results derived from them, including the SCC, are highly sensitive to modelers’ assumptions, which do not necessarily reflect the consensus views of experts,” the authors wrote. “Research based on our 2015 survey shows that when an IAM is recalibrated to use the discount rate and damage function preferred by respondents to an expert survey, the SCC value increases more than tenfold. …
“The Biden administration is currently conducting a review of the climate impact modeling used by the U.S. government, and these survey results could be used to help recalibrate some key model parameters.”
The New Jersey Board of Public Utilities (BPU) is in the final stages of rulemaking to ensure the state has enough publicly accessible electric vehicle charging sites to support Gov. Phil Murphy’s goal of putting 330,000 light duty EVs and plug-in hybrids on the road by 2025.
The board last week took public comments on rules that flesh out a plan outlined last year that defines who should build the chargers, how accessible they must be to the public and when the electric distributions companies (EDCs) should develop locations to ensure even distribution of chargers across the state.
The proposal seeks to foster infrastructure development through “shared responsibility” — shared costs — between stakeholders, including electricity distribution companies and private companies looking to develop charging sites. The plan seeks to ensure that charging stations are developed not only in areas where relatively high usage is expected, but also in more isolated areas with an expected lower use, and in low-income and disadvantaged communities.
With speakers including charging site developers, electricity companies, environmentalists and the auto retailers trade group, the hour-long hearing underlined the complexity of the task. While speakers were generally supportive of the rule’s basic framework, they also expressed a range of concerns, for example, about whether the proposed application process could be streamlined and how flexible it would be.
| Shutterstock
Ezra D. Hausman, an independent consultant representing the state’s consumer advocate division, suggested the BPU require a reporting process for stakeholders to provide information such as where chargers are installed and whether they are “serving all the communities that they are supposed to be serving.” He suggested the BPU encourage the use of “smart chargers,” which can automatically collect data that could be used to track charging patterns to see if efforts to encourage off-peak charging are working.
“This kind of information will all be crucial to assess programs to guide policy developments,” Hausman said.
At the heart of the discussion was ta chicken-and-egg dilemma: Drivers are reluctant to buy EVs if they don’t believe charging points are widely available. Yet a key obstacle to increasing the number of charging locations is that too few electric vehicles are on the road to make the needed build-out economically viable. That dynamic is heightened by the higher price tag of EVs compared to gas-fueled vehicles.
“It’s not the availability of EVs in the marketplace, or the lack of desirable EV options that are keeping consumers from buying an EV,” said Jim Appleton, president of the New Jersey Coalition of Automotive Retailers (NJCAR), adding that about 40 battery-fueled and hybrid vehicle models are currently on sale in New Jersey. “It’s price, and it’s charging infrastructure.”
Slow EV Uptake
Behind the focus on increasing EV charging numbers is the state’s 100% clean energy target by 2050, a goal that will require a reduction in carbon emissions of 80% from 2006 levels. The transportation sector is critical to the effort because officials estimate it generates 43% of the state’s greenhouse gas emissions.
The state wants at least 400 DC fast chargers at 200 or more locations by December 2025 and at least 1,000 Level 2 chargers — those with a 240-V electricity source — by the same date.
States are scrambling to get more EV charging stations up and running as they strive for aggressive carbon emission reductions that rely on a dramatic uptick in EV adoption. Researchers told the California Energy Commission last summer that the state would need to install millions of chargers to meet its goal of having 5 million EVs on the road by 2030. New York Public Service Commission in July approved about $700 million to be spent in the next five years on installing more than 50,000 light-duty electric vehicle charging stations.
New Jersey appears to be on track to reach or exceed its charger goals. The state has 434 DC fast chargers at 104 locations, and 996 Level 2 chargers at 489 locations, according to the State Department of Environmental Protection (DEP). That growth has been driven in large part by state incentives, such as the “It Pay$ to Plug In” program, which awards up to $200,000 in funds from the state’s Volkswagen settlement to projects that install two or more DC fast chargers.
But, even with this growing charger network, the state’s EV count is well short of the goals. New Jersey has only 40,000 plug-in vehicles on the road, according to NJCAR. And that figure is held down by the relatively short range of electric vehicle batteries and the paucity of charging stations, said Doug O’Malley, director of Environment New Jersey.
“Inevitably, people will say, can I afford it and where will I plug in?” O’Malley said. “There are not enough places to plug in right now. Range anxiety is real for every EV driver in the state.”
The BPU on Feb. 17 approved a package of electric vehicle programs submitted by Atlantic City Electric. The package includes incentives to cover the installation costs for 1,100 privately owned charging stations, and for chargers set up in multifamily buildings, employee parking lots and facilities for company vehicle fleets.
A few weeks earlier, the board approved an agreement that will enable PSE&G to spend $166 million over six years to continue building New Jersey’s electric vehicle infrastructure. The utility will offer rebates to 40,000 residential customers who install home EV chargers. It will also provide incentives to make multifamily buildings, government facilities and publicly accessible parking lots charger ready and will provide funding and upgrades to make high-traffic corridors ready for DC fast chargers.
The public comment period on the draft rule ends on April 12. A final decision by the board expected some time after.
Stimulating Charging Station Development
A central element of the BPU’s charging infrastructure project is ensuring the stations are accessible and evenly distributed around the state. DEP has identified areas that need EV charging stations to address range anxiety and travel needs. The BPU’s plan would require utilities to provide private developers with maps that show locations well suited to charging stations because of underutilization of the grid.
Under the shared responsibility framework, utilities would be responsible for installing wiring and backbone infrastructure for what the BPU proposal calls “make-ready locations,” funded with ratepayer dollars. Private site developers would pick up the tab for the charging station equipment, such as power outlets, enclosures and point-of-sale equipment.
Locations that do not attract the interest of private developers would be designated as “areas of last resort,” with special rules to ensure that charging points are developed there. If no private developer is interested after a period of 12 to 18 months, utilities could offer incentives to cover half the installation cost to attract developers. In some circumstances, a utility could develop a charging site itself, providing the location is more than 25 miles from another charging station.
Josh Cohen, director of policy at Greenlots, a D.C.-based provider of charging software and services, urged the board to “streamline” the last resort process to speed up development of these projects, which, he said, have a built-in delay of 12 to 18 months because of the waiting period.
Several speakers backed the BPU’s plan, but suggested the rules be put in place as BPU orders, which could be rewritten easily to accommodate shifting circumstances, rather than codified as state rules
“EV charging policy, and its development, is in the very early days,” said Michael Krauthamer, a senior advisor to the Alliance for Transportation Electrification. “Many changes are expected. We have seen this happen in other states … Not because the initial plans weren’t well thought[-out] but simply because of the evolutions that are happening in the marketplace.”
PJM stakeholders rejected a compromise proposal on the controversial black start unit testing issue in a final vote at Monday’s Members Committee meeting.
In a sector-weighted vote of 3.17 (63.4%), the proposal addressing black start unit involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level failed to reach the necessary 66% threshold for endorsement.
The same proposal, which was originally offered by PJM at the Operating Committee and was later presented by stakeholders at the Markets and Reliability Committee, was endorsed at February’s MRC meeting in a sector-weighted vote of 3.35 (67%). (See PJM Black Start Rules Inch Closer to Final Approval.)
The black start issue remained in limbo for a month when PJM’s alternative Option 1 proposal failed with a sector-weighted vote of 2.48 (49.6%), while Dominion Energy’s alternate proposal also failed with 2.47 (49.4%) at the January MRC meeting. Several stakeholders searched for a compromise, leading to the updated proposal that ultimately fell short of endorsement. (See “Black Start Packages Rejected,” PJM MRC/MC Briefs: Jan. 27, 2021.)
| PJM
Members pointed to the CRF issue as the most contentious portion of the black start unit discussions throughout the stakeholder process, which dates back as far as 2018. Stakeholders voted to amend the issue charge at the OC in December to align with language in the problem statement after it was discovered the two documents did not match, leading to heated debates. (See Vote on PJM Black Start Compensation Deferred.)
The Independent Market Monitor’s package, which received only 7% support at the December OC meeting, called for updated CRF rates and commitment periods to apply to new and existing black start units.
Market Monitor Joe Bowring pointed out at the OC meeting that the CRF table was originally created in 2007 as part of the Reliability Pricing Model capacity market design and currently includes incorrect assumptions. Bowring said the CRF values are higher than they should be under the lower corporate tax rate from changes in the 2017 tax law, leading to overcompensation for units.
A new black start diesel engine was installed in the Carroll County Energy Center in Ohio in 2019 with the ability to provide 15.6 MW of energy in a 24-hour period. | Burns & McDonnell
Adrien Ford of Old Dominion Electric Cooperative said she was “both pleased and not pleased” that the black start proposal failed to be endorsed on Monday. Ford said the compromise proposal’s lack of addressing the CRF table was ODEC’s reasoning for voting against it, saying the CRF has “been in error” and needs to be corrected “prospectively.”
She said there were many important issues regarding reliability concerns that the proposal addressed and should be considered by stakeholders.
“We just were not able to support it without addressing the rate error,” Ford said.
Compromise Proposal
Susan Bruce, counsel to the PJM Industrial Customer Coalition, and Sharon Midgley of Exelon, presented the compromise proposal of PJM’s original proposal. Bruce said the compromise proposal had a different “term of commitment” for black start resources — the “life of unit.”
PJM’s Option 1 had a commitment period of 20 years or greater if the unit offers more in the request-for-proposal process. The Dominion proposal had a commitment of the capital recovery period plus three years of a 5-, 10-, 15- and 20-year period based on unit age at the time it entered black start service.
Bruce said the content of the compromise proposal was largely consistent with the other proposals that had already been reviewed in the stakeholder process. She said she viewed the proposal as a true compromise and supported the measure.
“It was designed to show the opportunity for consensus-building and stakeholder process successes,” Bruce said.
Midgley echoed Bruce’s comments, saying the proposal represented a real compromise between stakeholders. She said it had “important enhancements” to black start testing and replacement rules and included an important change to the term of commitment.
“It’s been a little bit of a long and winding road to get this proposal in front of the Members Committee,” Midgley said.
Future Moves
Ford asked about PJM’s plan in light of the proposal’s failure to be endorsed.
Mike Bryson of PJM said that, from the beginning of the black start unit stakeholder process, the RTO has “been on the record” that it believed the CRF issue must go to FERC for a decision. Bryson said the next step will be a consultation with the PJM Board of Managers, “hopefully this week,” about the direction the RTO will take on black start and an update on any decisions by the board at the Market Implementation Committee meeting April 7.
Paul Sotkiewicz of E-Cubed Policy Associates asked if the PJM board will look at the CRF issue on a “forward-going basis” and not retroactive based on past comments by the RTO.
Bryson said PJM’s discussion with the board will be “representative of all our positions” up to the present, and the RTO will also bring forward the stakeholder discussions over the last few months.
ERCOT’s Technical Advisory Committee last week conducted its first regular meeting since the February winter storm, with its aftereffects unsurprisingly dominating the discussion.
Liz Jones, Oncor | Texas RE
Liz Jones, vice president of regulatory affairs for Oncor Electric Delivery, addressed the committee regarding a recent ERCOT market notice alerting participants to an application for critical-load designation.
The notice is meant to allow gas facilities that provide fuel to generators to request designation as a “critical load-serving electric generation and cogeneration.”
Almost half of ERCOT’s natural gas-fired generation was lost during the February extreme weather because power was cut to gas infrastructure not listed as critical load. With compressor stations out of service and pipelines frozen, drilling companies had to burn off, or flare, so much gas flowing out of the ground that the flames could be seen from space.
Jones said the application, housed on ERCOT’s website but also linked from the Texas Railroad Commission’s website, is intended to identify the “entire natural gas supply chain.” The form also makes clear it does not guarantee an uninterrupted supply, she said.
“It asks for specific information about backup generation and restoration times,” Jones said. “This is a way that we will become better informed.”
The completed forms should be sent to the local transmission and distribution service providers responsible for the gas facilities.
Asked how the response has been, Jones said, “They haven’t come pouring in, but it’s early, yet. I’m hopeful that by providing it to industry trade organizations and the RRC letter, participation will increase.”
TAC also discussed its working list of potential solutions to the events preceding and following last month’s storms, which numbers more than 110 issues. Many of the issues are listed as awaiting legislative action or being long-term stakeholder items, but others are being parceled out to various subcommittees. (See “TAC Takes up Ideas for Solutions,” Texas PUC Won’t Reprice $16B Error.)
Reliant Energy Retail Services’ Bill Barnes urged his fellow members to be prepared to help policymakers as they consider legislation during the current session, which ends May 31.
“For the next two, two-and-a-half months, our priority will be waiting on the legislature,” he said. “I would encourage us to engage as much as possible, and prioritize those activities, to assist the legislature and work with the [Public Utility Commission]. We should assist where we can and be ready for efforts we’ll need to undertake in helping the commission and the legislature implement changes.”
Passport Program Faces Staffing Constraints
Staff said the Passport Program, which bundles several high-profile initiatives, remains on schedule despite staffing constraints from winter storm-related activities.
That has led ERCOT to evaluate staff resources for an upgrade to the energy management system (EMS) that will house the Passport’s programs, and its business requirements, said the ISO’s Matt Mereness.
ERCOT’s Passport Program currently remains on schedule for completion in 2024. | ERCOT
“There’s some knowns and still some unknowns, given everything that’s going on,” Mereness said.
Passport’s 2021 objectives, which Mereness described as a “heavy lift,” include the EMS upgrade and developing and integrating the EMS, market management system (MMS), and settlements and billing business requirements. The MMS project began three months late, further squeezing available IT resources, but remains on schedule.
Passport is scheduled to be delivered in late 2024. It is comprised of implementing revision requests produced by the Real-Time Co-optimization (RTC) and Battery Energy Storage (BES) task forces along with the EMS upgrade. Passport will also integrate a 10-minute contingency reserve ancillary service product and improve distributed generation resources’ mapping.
The Passport Program budget | ERCOT
Mereness put off a decision to sunset the RTC task force, but said staff wants to work with TAC leadership to develop a Passport implementation working group. TAC did sunset the BES task force.
Should the Passport’s work be delayed, Mereness said, a go/no-go decision point will be reached. “EMS would be put on its own path,” he said. “It can’t be delayed past 2024.”
The program has an $85.5 million budget, with $51.6 million allocated to the RTC effort and $27.1 million to the EMS upgrade.
$6.1M Price Correction
Staff also added further details to the recent software error that occurred after the February outages began, requiring a price correction by the Board of Directors. (See Software Error Could Mean ERCOT Price Revisions.)
Dave Maggio, ERCOT’s director of market design and analytics, said staff discovered that the MMS software contained programming errors that resulted in incorrect megawatt amounts being used for the estimated deployed emergency response service (ERS) component of the real-time price adders for certain dispatch intervals on Feb. 15. The grid operator had already entered its highest level of energy emergency alert at that time, requiring prices at the $9,000/MWh cap.
The result was weather-sensitive (WS) ERS megawatts being included in the price-adder calculations for some SCED intervals when there was no WS ERS deployment obligations. Staff have since rerun the affected intervals to determine the correct prices.
The resettled prices amount to an additional $6.1 million in invoices due to ERCOT. The largest change to any single counterparty is more than $868,000 due to the ISO.
The price corrections are within the parameters for after-the-fact corrections. They will be taken to the board for its consideration during its scheduled April 13 meeting.
Demand Control 2’s Hendrix Joins TAC
The TAC welcomed Demand Control 2’s Chris Hendrix to the committee as an independent retail electric provider segment representative. He replaces Shannon McClendon, also with Demand Control 2, who recently took a seat on the Board of Directors as the retail sector’s representative.
Members approved a nodal protocol revision request (NPRR) and an other binding document revision request (OBDRR) related to emergency response service (ERS). Both measures were opposed by Morgan Stanley’s Clayton Greer, who has made a point of voting against anything related to ERS.
NPRR1060 makes a number of revisions pertaining to ERS, including: modifying and adding language related to ERS resource testing, sites that participate in more than one ERS resource, and availability determinations; simplifying the process for notifying ERCOT of planned maintenance and self-testing for ERS generators; clarifying metering requirements for ERS generators and the performance of co-located ERS generators; and addressing how ERCOT will treat ERS resources with missing meter data.
OBDRR027 clarifies OBDRR023’s implementation timeline to align ERS procurement methodology with previous Protocol changes. The latter change will be implemented over two separate dates: partial implementation that occurred Feb. 1 and the remaining language’s addition on Oct. 1.
The combination ballot, which included seven NPRRs, an OBDRR and a change to the Nodal Operating Guide (NOGRR), passed unanimously, 29-0:
NPRR1023: establishes a process for liquidating a repossessed congestion revenue rights (CRR) portfolio through the use of financial security held by ERCOT for the defaulting CRR account holder for settlement purposes. The NPRR also modifies the process for forfeiture of CRRs resulting from the account holder’s non-payment or late payment of an invoice.
NPRR1045: moves and revises the definition of transmission operator from the Nodal Operating Guide to the Protocols and adds a new section that clarifies the designation process and basic qualifications for TOs.
NPRR1057: applies the hub LMP formulas to the Panhandle 345-kV hub and the Lower Rio Grande Valley 138/345-kV hub and eliminates portions of hub real-time settlement point prices formulas designed to address all buses within a hub being de-energized.
NPRR1059: sends interval readings for non-interval data recorder meters, such as residential accounts with consumption under 700 kW, to settle on actual usage/generation instead of the load profile.
NPRR1065: replaces a sentence describing a settlement-only generator’s (SOG) energy volumes subject to nodal versus zonal pricing with a formula; revises the name and definition of a related billing determinant to more accurately describe the data it represents; and adjusts the default uplift settlement to combine SOG generation with the counterparty’s other generation.
NPRR1066: grants ERCOT the discretion to apply existing standards for grandfathered generation resources to an existing unit owned by a municipally owned utility or electric cooperative that is transferring load into ERCOT and seeks to interconnect the existing generation unit to the ISO’s system.
NPRR1069: clarifies settlement billing determinants to ensure that an energy storage resource’s capacity is not counted in the off-line reserve imbalance of the real-time ancillary service imbalance payment or charge.
NOGRR219: removes the definition of transmission operator from the Nodal Operating Guide because it is being moved to the ERCOT Protocols by NPRR1045. This NOGRR also clarifies existing language relating to load shed obligations and removes the Load Shed Table from the Nodal Operating Guide. Instead, the Load Shed Table will be posted on the ERCOT website
OBDRR028: clarifies that ESR capacity will not be accounted for in operating reserve’s off-line portion.
State energy officials in New England have recently pressed their case for reforms at ISO-NE with a series of online technical forums during the last three months focused on the RTO’s wholesale electricity market design, transmission system planning process and governance. There is also a recognition that significant equity and environmental justice considerations exist within those core reform areas.
On March 18, the officials explored the links between the reforms they seek from ISO-NE and equity and environmental justice during a virtual meeting with a heavy focus on public engagement.
Maine Public Utilities Commission Chairman Phillip Bartlett said ISO-NE’s market design has resulted in high electricity costs in New England, disproportionately burdening low-income consumers and communities of color.
Judy Chang, undersecretary of energy for the Massachusetts Executive Office of Energy and Environmental Affairs, added that siting of transmission lines and substations in low-income communities needs to be considered more carefully.
| Central Maine Power
Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes said that ISO-NE has limited transparency and public accessibility in its governance, which does not provide an opportunity for environmental justice communities in New England — unless they participate in the nonpublic NEPOOL stakeholder process — to be part of energy planning conversations and decisions that directly impact them.
Engaging the Public
The officials heard from several residents during the forum.
Ross Conrad, a beekeeper from Middlebury, Vt., said he appreciated the focus on environmental justice and equity issues related to fossil fuels and their air pollution but that he also has concerns around renewable resource siting. Conrad singled out Hydro-Québec, which he said has never compensated Five Nations communities for dams on their lands before 1996, and ISO-NE for importing electricity from it.
“So, I’m wondering why we don’t reduce our reliance on Hydro-Québec energy, instead of increasing it, until such point they may actually agree to compensate the Five Nations people for the dams and the flooding that has occurred on their land?” he said.
Eugenia Gibbons, Massachusetts director of climate policy for Health Care Without Harm, a nonprofit that works to reduce the health care sector’s environmental footprint, said that having a Spanish translation for the forum was an essential step in the right direction.
“Multilingual communication is a cornerstone of any meaningful engagement and more inclusive process,” Gibbons said.
Energy policy can be “wonky, but it doesn’t have to be,” she said.
“I would say that community members are very conversant in energy policy because they’re living with the consequences of bad decision-making, day in and day out, and have a lot of good recommendations and insight to offer when we’re thinking bigger picture.”
Gibbons added that while the states want more transparency and accountability from ISO-NE, they, in turn, need to continue to think about how to meaningfully engage the community in a process that is “not necessarily very welcoming or exciting.”
Shaina Kasper, Vermont and New Hampshire state director for Community Action Works, a regional nonprofit based in Boston that works with environmental justice communities, said her organization has been asking for a platform like this “for too long.”
In November and December, Kasper said, several organizations sent letters to the New England States Committee on Electricity asking for a regional public process with after-work-hours meetings to discuss updates to the grid in “layman’s terms.”
“Months later, after dozens of calls and emails, we’ve got this one meeting, and we just got the agenda for it, two days ago, and so you just want to get members of the public engaged on what the grid should look like, but it just seems like you’re trying to check the box of offering public participation but not doing anything substantial to make that happen,” Kasper said.
New England deserves a grid operator responsive to the needs of ratepayers “and the people living with climate catastrophe and pollution, not fossil fuel executives and utilities,” Kasper said. She called on ISO-NE to work with states and communities and not “prop up” fossil fuel energy infrastructure in New England.
Chairman Bartlett said the forum is intended to serve as a kickoff to a conversation.
“We will certainly look for ways to keep this dialogue going, so it is important that all of us participate in finding solutions that will work for all of us as we make a very important transition to a cleaner energy future,” Bartlett said.
A bill working its way through the Connecticut General Assembly seeks an increased review of siting proposals for solar facilities on certain farmlands and forests with more than 1 MW of generating capacity.
The Environment Committee listened to public testimony on the potential legislation as part of a 15-hour marathon hearing that addressed several bills on March 19.
One of the entities opposed to the siting legislation is the Connecticut Siting Council (CSC).
Melanie Bachman, executive director of the CSC, said she opposes the bill for the same reasons that the council opposed a similar measure passed four years ago. If passed, the proposed legislation’s language would repeal and replace a part of the statute from the 2017 version.
Bachman said CSC has exclusive authority over the siting of energy facilities with more than 1 MW of generating capacity. The proposed scope of the new bill, according to Bachman, would erode CSC discretion, increase project costs, thwart state clean energy goals and impact private property rights.
She added that regardless of the generating capacity of a proposed solar facility, the review process is the same. CSC must consult with 12 state agencies, including Energy and Environmental Protection (DEEP), Agriculture and Public Health.
“Naturally, competing interests exist among the state agency policies,” Bachman said. “CSC must strike a balance among these competing interests. The effect of this bill would tip the scale.”
The bill also seeks a decommissioning bond for approved solar facilities. Bachman said the required bond would not apply equally to all facilities and does not specify the bondholder. Most solar facilities are sited on private property and then leased by solar developers. The property owner, as opposed to the developer or state, has the legal rights to control decommissioning and the amount of any bond for associated costs.
DEEP Commissioner Katie Dykes said plans to imminently launch “a robust stakeholder engagement process” will ensure that the process for siting and permitting solar facilities is “transparent, efficient and predictable.” Dykes said potential policy conflicts and challenges could be “addressed, minimized and planned for” via the stakeholder process.
The bill, if enacted, would also increase the number of docket proceedings the CSC will need to manage and process with an expanding siting scope.
Dykes said because CSC already requires a decommissioning plan as an element of any facility approval and specifies a timeframe following the end of operations, requiring a bond of 25-30 years would be “an expensive and speculative requirement” that could influence the demand for renewable energy projects in Connecticut.
Reaction from Advocates, Trade Groups
Nathan Frohling, director of external affairs for The Nature Conservancy, offered conditional support for the bill based on the assurance that the decommissioning bond “does not unreasonably and differentially treat solar development relative to other forms of possible development on the same sensitive land.”
Frohling said a more substantial effort needs to be made to find and pursue plans providing guidance and incentives for siting grid-scale solar, so that development proceeds at the pace needed to meet climate goals while assuring the protection of critical lands environmental resources.
Mike Trahan, executive director of Solar Connecticut, said his group opposes the bill because “the facts show there is no need” for it.
“The fact is solar developers, and solar development, are not threats to farmland,” Trahan said. “Certainly, there’s no reason we can’t work together to achieve common ground.”
Frank DeFelice, chair of the Durham Planning and Zoning Commission and Regional Planning Commission for the Lower Connecticut River Valley Council of Governments, said renewable energy projections are vital with Connecticut’s retail electricity prices being the highest in the nation outside of Hawaii and Alaska. He added that solar installations are a lifeline to farmers, especially lease payments from solar developers.
Francis Pullaro, executive director of RENEW Northeast, had the last word at the end of a 15-hour hearing. Pullaro said he supports the proposed stakeholder engagement process.
“We think it’d be really helpful to bring farmland interests and renewable energy interests together,” he said.
Less than 9 miles square and on average 5 feet above sea level, Ocracoke Island in North Carolina’s Outer Banks was almost custom-made for one of the state’s first microgrids. The island is regularly hit by hurricanes and storm surges, and its only connection to the main electric grid is 6 miles of undersea cable.
“The vulnerability of the island’s connectivity to the main grid is always in question in hurricane season,” said Paul Spruill, CEO of Tideland EMC, the electric cooperative that provides power for the island’s 1,400 meters.
Ocracoke has relied on diesel generation since the early 2000s, but in 2015 the North Carolina Electric Membership Corp. (NCEMC), an umbrella group of the state’s 26 co-ops, in a partnership with Tideland, began exploring the possibility of using the island as a test site for a battery storage project. By 2017, the island was home to the NCEMC’s first microgrid, incorporating solar, energy storage and smart thermostats and water heaters to supply emergency power to Ocracoke’s homes, businesses and campsites.
The system’s 62 solar panels provide 15 kW of electricity, backed up with 1 MWh of battery storage, and can disconnect from the main grid to keep the power on in extreme weather or other emergency situations.
Ocracoke is just one example of how North Carolina’s electric cooperatives are outdistancing the state’s investor-owned utilities on microgrid deployment, as well as developing the advanced control systems for leveraging such distributed energy resources to improve overall grid reliability.
The island’s microgrid is one of three systems NCEMC has put online in recent years in partnership with its member co-ops. The group has also launched a new distribution operator (DO) system that serves as a single point of connection and coordination for the microgrids and other grid-edge DERs.
Located on the south coast of North Carolina, the Heron’s Nest microgrid is the state’s first residential project, with each of 30 homes equipped with a 3-kW solar system, smart thermostat and a water heater that can be used for demand response. Butler Farms, a hog farm, hosts the state’s first agricultural microgrid, combining solar and storage with a biogas facility that converts methane from hog waste into electricity.
Heron’s Nest is North Carolina’s first residential microgrid, with rooftop solar on each of the development’s 30 houses, along with community solar and storage. | NCEMC
The Ocracoke and Heron’s Nest microgrids have played a key role in the development of the DO system. NCEMC has partnered with North Carolina’s IOUs — Duke Energy and Dominion Energy — to test how the platform interacts with the grid during peak demand or in emergency situations. The tests demonstrated that using a platform with a single, coordinated contact point could optimize grid-edge resources such as microgrids to generate emergency power and alter load.
“As more microgrids and distributed energy resources are added throughout the grid, the key for electric cooperatives in North Carolina will be to coordinate those resources to work together smartly to meet the needs of the grid and of consumers,” said Lee Ragsdale, NCEMC’s senior vice president of energy delivery.
“The more you connect, the more reliable service is going to be,” said Badrul Chowdhury, a professor at the University of North Carolina, Charlotte, who is heading up a three-year, federally funded project to help develop an advanced microgrid control system.
One of 10 projects nationwide recently awarded grants from the Department of Energy, the project will build a digital “twin” of a microgrid under construction by Duke and use it to develop and test an outage prediction algorithm and simulate emergency situations.
“This project will be a national model for organizing a resilient grid in a state with climate challenges like North Carolina,” said Michael Mazzola, executive director of UNC Charlotte’s Energy Production and Infrastructure Center. With $3.6 million in funding from the DOE, the project is slated to kick off May 1.
Linking Grid-edge Resources
Like many states, North Carolina has become increasingly vulnerable to extreme weather, often intensified by climate change. Data from the North Carolina Department of Environmental Quality show that in the past decade, the state has sustained five extreme weather events each causing more than $1 billion in damages.
Hurricane Florence in 2018 resulted in $17 billion in damages statewide, including extensive damage to North Carolina’s multibillion-dollar agriculture industry. To respond to the ongoing threats of climate change, Gov. Roy Cooper has committed the state to cut carbon emissions from its electric power sector 70% below 2005 levels by 2030 and to be carbon neutral by 2050.
While often under the radar, North Carolina’s electric cooperatives are taking a leading role in the state’s energy transition. The co-ops serve 2.5 million members, and their combined service territories cover 45% of the state.
They are also nimble: smaller than IOUs, unregulated and able to tap into sources of low-interest financing. Across the country, co-ops are experimenting with new business models and new technologies.
The Butler Farm microgrid is a prime example of this small-scale innovation. Tom Butler, the owner, has been a hog farmer since 1995 and realized early on that managing the animals’ waste and the accompanying odors was going to be a challenge. With 8,000 hogs producing 6,000 tons of methane a year, Butler built a 185-kW biogas facility, completed in 2011.
The Butler Farm microgrid includes a biogas facility that turns methane from the farm’s 8,000 hogs into electricity. | NCEMC
He then began working with his local electric cooperative, South River EMC, and NCEMC to add 20 kW of solar panels to the farm, which, he said, made it a “perfect fit” when the co-op decided to build a microgrid. The system has 735 kWh of battery storage but could be expanded, Butler said.
Twenty-eight co-op members are connected to the microgrid, but the co-op plans to have 160 members connected once pandemic restrictions lift, he said. “South River is going to have as many members on the microgrid as they can,” Butler said. “We can add people as we add battery storage.”
The microgrids have also helped NCEMC test its new DO technology. Working with Dominion, NCEMC used the Ocracoke microgrid to either charge the battery to reduce power from the main grid or discharge the battery and adjust home thermostats and energy use to maintain balance in the system. The thermostats and water heaters at Ocracoke are managed over Wi-Fi by a central controller, so demand and load can be adjusted across the island.
“The microgrid has better enabled us to deliver emergency power and provide better delivery for when we need it,” Spruill said.
Additional demonstrations of the DO system involved a test with Duke and the Heron’s Nest microgrid and another using DERs at Blue Ridge Energy, a co-op in the northwest corner of the state, to test real-time system response to changing weather conditions. In addition to the residential solar systems, the Heron’s Nest microgrid also has a 75kW community solar array and 255 kWh of battery storage.
NCEMC has two more microgrids in development. Eagle Chase, another residential project located north of Raleigh, will be online by the end of March, bringing together propane generators, smart water heaters and 500kW, 1MWh of battery storage. A fifth microgrid with 2 MW of solar and 5 MWh of storage will be commissioned later this year on Rose Acre Farms, an egg production business.
Each project’s development is time-intensive, but Ragsdale expects the number of systems will rise as the price of solar and battery storage drops. “They can and will be part of the transition to clean energy in the state.”
The Critical Role of DER Networking
Coordinating those systems will be critical for grid resilience, said UNC’s Chowdhury, who is preparing to launch the DOE-funded project in partnership with the DEQ and Duke.
The project will test how well the algorithms the team creates can function on a networked microgrid system using a digital twin, a lab-created replica of conditions at Duke’s microgrid under construction in the town of Hot Springs.
A network of microgrids, seamlessly connected to balance generation and load, can strengthen grid resilience in cities after extreme storms, Chowdhury said.
Pockets of rooftop solar, battery storage or other DERs scattered across a city might not generate enough power individually, or depending on the weather, generate none at all, he said. Networking these resources could provide power to critical services such as a hospital, shelter or food bank and more equitably distribute electricity among residents.
“It’s usually the wealthy neighborhoods that have rooftop solar. Other parts [of a city] may be less affluent with not enough generation resource, even though there might be a critical load there,” Chowdhury said. “One of the ways we can address this is [to] bring in generation from an outside microgrid.”
The team will also develop an outage prediction test using an algorithm incorporating 10 years of Duke outage data to pinpoint vulnerable areas of the grid.
The outage prediction algorithm and other tests will be simulated in real-life scenarios using the digital twin system. Inputting weather and generation data from the real Hot Springs microgrid, the team will be able to simulate the exact situation at Hot Springs in the lab to see how the algorithms and networks respond.
Looking ahead, Chowdhury said that the research on microgrid networking is just beginning. “Now we are seeing microgrids for resilience purposes, but I think later it could be for just about anything.”
The Biden administration announced Monday it will open a new area between Long Island and New Jersey to offshore wind development and pledged to speed reviews of projects to meet a goal of 30 GW by 2030.
The new area and the 2030 target were among a flurry of announcements at an Offshore Wind Roundtable featuring Interior Secretary Deb Haaland, Energy Secretary Jennifer Granholm, Commerce Secretary Gina Raimondo, Transportation Secretary Pete Buttigieg, National Climate Adviser Gina McCarthy, and state officials from New York, New Jersey, Maryland, North Carolina, California and New England.
The new priority wind energy area is in the New York Bight, an area of shallow waters between Long Island and New Jersey. The Bureau of Ocean Energy Management will issue a proposed sale notice for the area, which will be followed by a formal public comment period and an auction late this year or early 2022.
The administration’s 30-GW goal is slightly above the total of East Coast state OSW targets, although the states’ timelines extend beyond 2030. In February, BloombergNEF predicted that the U.S. will become the third largest OSW market in the world by 2030, with a cumulative 23 GW. The administration said the U.S. could have 110 GW by 2050.
BOEM pledged to complete its review of at least 16 construction and operations plans (COPs) totaling 19 GW by 2025 and announced its intent to prepare an environmental impact statement for Ocean Wind, Ørsted’s 1,100-MW project 15 miles off Atlantic City, N.J. (See Developer to Use Union Labor for NJ OSW Project.)
The agency completed its final EIS for the 800-MW Vineyard Wind project off Massachusetts earlier this month. The 800-MW project, a joint venture of Copenhagen Infrastructure Partners and Avangrid Renewables, is on track to become the first large-scale OSW farm in the U.S., following the 30-MW Block Island Wind project. (See BOEM Releases Final Vineyard Wind Impact Statement.)
It also held public hearings in February following the release of its draft EIS for the South Fork project off Long Island, a 132-MW wind farm by a joint venture between Ørsted and Eversource Energy. (See BOEM Hears Public Support for South Fork OSW.)
Economic Benefits Cited
Although OSW is seen as central to meeting decarbonization goals, state officials and the Biden administration have primarily touted the projects for their economic development potential.
The administration said the economic gains won’t be limited to coastal states, noting that workers in Alabama and West Virginia are supplying 10,000 tons of domestic steel to a Texas shipyard that is building the nation’s first Jones Act-compliant wind turbine installation vessel for Dominion Energy.
The administration says the 30-GW target would generate more than $12 billion in annual capital spending and result in more than 44,000 workers directly employed in OSW by 2030 and nearly 33,000 additional spinoff jobs in communities supported by OSW.
The Department of Energy “is going to marshal every resource we have to get as many American companies, using as many sheets of American steel, employing as many American workers as possible in offshore wind energy,” Granholm said.
“This commitment to a new, untapped industry will create pathways to the middle class for people from all backgrounds and communities,” McCarthy said.
Other Announcements
Also Monday, the Department of Transportation’s Maritime Administration invited port authorities and others to apply for $230 million in grants for port and intermodal infrastructure-related projects. The funding could be used to strengthen and modernize port infrastructure and create storage areas and docks for wind energy vessels.
For its part, DOE said it will offer $3 billion in loans to OSW and offshore transmission developers and suppliers. The department has already loaned $1.6 billion for OSW projects totaling about 1,000 MW.
The National Offshore Wind Research and Development Consortium (NOWRDC), created by DOE and the New York State Energy Research and Development Authority (NYSERDA) announced $8 million in awards to 15 OSW research-and-development projects selected in a competitive process. The projects will focus on offshore support structure innovation, supply chain development, electrical systems innovation and mitigation of use conflicts. Created in 2018 with $20.5 million from DOE and matching funds from NYSERDA, the fund has raised a total of $47 million following contributions from Maryland, Virginia, Massachusetts and Maine.
The National Oceanic and Atmospheric Administration announced $1 million in grant funding for research proposals to increase understanding of the effects of OSW on the ocean and local communities and economies.
NOAA also said it has an agreement with Ørsted to share physical and biological data in waters leased by the company. The agency said it hopes to reach similar agreements with other leaseholders to fill gaps in the science regarding ocean mapping and observing.
