Distributed energy resources, electrification and equitable wholesale compensation for both dominated two panels during the virtual North America Smart Energy Week.
Karen Olesky, an economist for Nevada’s Public Utilities Commission, said she’s both riddled with anxiety and invigorated over how quickly new distributed resource technology is being developed.
“It’s very exciting to see vehicle-to-grid charging and the electric company being able to access behind-the meter storage in someone’s home to use it as a demand response unit,” Olesky said during a Sept. 28 panel on electrification. “I think these are great DER technologies, and I love seeing them in pilot programs and proliferate, but I’m also scared about how quickly that technology is changing. Some of these technologies that utilities invest in might end up being obsolete well before the end of their useful lives.”
Olesky said ratepayers could be stuck paying for electric vehicle charging stations that are quickly replaced by newer models. She called the speed of adoption and its implications on long-term resource planning “exciting and kind of terrifying.”
Regulators and utilities are okay to “pivot” on incentive programs when they realize they’re unpopular or ineffective, she said.
Keith Dennis, vice president of the National Rural Electric Cooperative Association, said electrification stands to improve people’s quality of life.
“It wasn’t more than a hundred years ago when people were washing dishes and clothes by hand, and electricity really improved our lives and it can do it again,” he told attendees.
Dennis said electrification can save customers money, lessen environmental impacts, bolster grid reliability and lengthen the lifespan of heavy machinery and construction equipment. He added that he doesn’t want electrification to become politicized.
Oncor Electric Delivery’s David Treichler said the conversion to electrification is one of the most consequential changes the nation will undertake. Electrification will fundamentally change how we “move goods, people, things.”
Flying into the Dallas Fort Worth airport one night, Treichler said he concentrated on a bird’s eye view of the airport’s logistics warehouses. He said when thinking about how to electrify the airport’s freight services, he realized the centers were packed so tightly together that he couldn’t see where new substations could be squeezed in to handle charging.
Treichler said Oncor has developed a green fleet analytics tool that evaluates a customer’s load requirements for electrification and available nearby capacity to gauge the need for new electric facilities.
“The longer you wait to talk to us, the harder it is,” he said, urging companies interested in fleet electrification to act sooner rather than later.
National Grid’s Kristin Munsch said electrification’s growth is uncertain now because the changeover hinges on customer adoption.
“It’s talking about people’s cars, people’s home heating systems,” Munsch said. She said investments need to be made thoughtfully so that all customers can electrify their homes, not just those that can afford it.
“Like everywhere in the country, we’ve got very affluent communities, and we’ve got more challenged communities,” she said.
Panelists during a wholesale pricing session said appropriate compensation is necessary for a more active demand-side market.
“We have a generational problem of how we count it. How do we know what a megawatt is anymore?” OhmConnect’s Cisco DeVries said. “Ultimately, I think we just need to agree on some methodologies, and I think it’s really critical for the wholesale market that we get there quickly.”
“We have historically underestimated the potential of distributed clean energy in terms of serving our wholesale markets,” SunPower’s Suzanne Leta said. “A key question in my mind is: how do we ensure the right policies are in place to enable consumers to offer that value to the wholesale market and get paid for it? That’s really the question we need to focus on answering.”
Leta said the industry often ignores that just 3% of residential customers currently have rooftop solar. She said rooftop solar is poised for a “massive” growth trajectory. “We are just at the tip of iceberg,” she said.
In SunPower’s nationwide surveys, Leta said residents cite concern over outages as the primary reason for installing their own solar and storage.
“This is real-time for consumers, whether it’s an ice storm in Texas, or flooding in Louisiana or a hurricane in New York. … That’s what people are concerned about. Are power outages happening on a much more frequent basis?”
Leta said in addition to wholesale pricing, state commissions and utilities need to think differently about resource procurement. She said commissions’ resource planning is rooted in one-way transactions sourced from fossil fuels or nuclear power.
“That’s just not how our grid works today, and it’s not going to be how it works in the future,” Leta said.
Jill Powers, CAISO’s infrastructure and regulatory policy manager, said dynamic rates and demand-side management will feature more prominently in wholesale pricing.
“The duck curve is about 10 years old, and he’s been progressing quickly,” Powers said, noting that CAISO underestimated rooftop solar’s contributions. She said CAISO contends with oversupply and dramatic ramping needs in any given day.
DeVries commended CAISO for being among the first to allow bids on a 15-minutes basis from aggregated DERs.
“The wholesale market is the place where this transaction takes place,” he said. “It is not a place the customer understands at all. They are never going to understand it. They’re still incredibly confused as to why we might pay them to save energy. That makes no sense [to them].”
He said the aggregator’s role is to simplify and translate DER use into the wholesale market.
“We can’t say to customers, ‘You can’t turn your air conditioning on right now.’ Right? That’s a no-go,” DeVries said. “The utilities have tried that forever. It just doesn’t work.”
Kicking off the Texas Reliability Entity’s annual winter weatherization workshop last week, CEO Jim Albright noted a “renewed focus by all of us on winter weather.”
That’s no surprise, given the February winter storm that drove the ERCOT grid to the brink of collapse and led to human and financial suffering across Texas. A joint inquiry by FERC and NERC has since pinpointed a lack of winter weatherization of generator facilities and natural gas infrastructure as the leading cause of the power outages that left some Texans in the dark and cold for almost four days. (See FERC, NERC Share Findings on February Winter Storm.)
State lawmakers and regulators responded to the storm by taking a more aggressive response to weatherization, requiring generators and transmission service providers (TSPs) to comply with mandatory reliability standards for winter weather and imposing financial penalties if they don’t. (See “Weatherization Rule Published,” PUC Workshop Takes First Stab at Market Changes.)
FERC Chair Richard Glick, in discussing the joint inquiry with NERC last month, noted that the two regulators proposed similar requirements after a previous winter event in 2011. However, “that recommendation was watered down to guidelines that few generators followed,” he said.
This time, it will be different, Jeff Billo, ERCOT’s director of forecasting and ancillary services, said during Thursday’s virtual workshop.
“Previously, we really didn’t have any mandatory reliability standards from a weatherization standpoint,” he said, adding that there will be “substantial fines.” Penalties can range as high as $1 million/day.
“Future inspections will be very different than they have been in the past,” Billo said.
The Public Utility Commission’s draft rule directs generators and TSPs to file compliance statements, signed by a senior-level officer, attesting to their actions. ERCOT staff will follow up with on-site inspections. With about 800 resource units to inspect, Billo said ERCOT is taking a “risk-based” approach and will focus on those generators that failed during the winter storm. That will likely include wind farms and solar fields, Billo said.
The grid operator’s staff are currently developing an online compliance form that will be distributed before the Dec. 1 response deadline. ERCOT is required to file a report with the PUC by Dec. 10.
“If we have 800, 900 units to look at, we don’t want [response] emails in formats we’ll have to sort through in eight or 10 days,” Billo said.
ERCOT used to inspect about 80 units a year, Billo said. The increase has forced the grid operator to create a weatherization director’s position and hire additional staff to meet the load. In the meantime, staff will rely on support from contractors to meet a Dec. 24 inspection deadline.
The commission will add temperature requirements to its reliability standards next year, following a detailed weather report due early next year.
ERCOT meteorologist Chris Coleman told his virtual audience that the La Nina ocean patterns are similar to last year’s and that a majority of forecasts are pointing to a colder-than-normal winter. While much of the cold air may be concentrated in the Midwest, he said, “The potential is there for a polar vortex for ERCOT a time or two.”
Winter is coming, but despite the forecasts, this winter is statistically likely to have less extreme weather than last year. | Texas REColeman said this winter will likely be a dry one, welcome news to those who remember February’s ice and snow. He said his preliminary data indicate the coming season will be similar to the mild winter of 1999-2000, pointing out that extreme winters are historically followed by milder ones.
“Statistically, when you have a cold, extreme winter, at least some, if not more, of those winters were followed by some extreme cold, though not as extreme” as the previous winter, Coleman said.
The meteorologist’s final forecast will be released in November.
Generation Owners Share Tips
Andrew Valencia, Lower Colorado River Authority’s (LCRA) senior vice president of generation and the man who will sign the utility’s compliance statement, was among several market participants and industry experts who shared their insight during the workshop.
He said a power plant is only as good as its weakest link, noting subsystems and major equipment are typically designed for specific minimum temperatures that may or may not be consistent. The highest temperature rating sets the entire plant’s rating, but that can be a moot point when sub-zero temperatures hit.
El Paso Electric’s performance during the winter storm led to a social media meme. | LordOfTheBrohirrim via iFunny.com“There’s no way to test freeze protection until you have cold weather,” Valencia said. “Until you can experience those temperatures, there’s no way to functionally test it.”
He said activating temporary heat sources, frequently checking equipment and adding staff are among hundreds of procedure provisions necessary required to maintain operations.
LCRA begins its winter preparations in the fall with meetings to review written procedures and checklists for each site. Supply inventories and equipment are checked and senior leaders tour each site to verify preparations.
“That’s the best time to work on it. You don’t need the preparation measures, and you have time to work on the protection,” Valencia said.
El Paso Electric’s Kyle Olson said the utility invested $4.5 million in freeze protection systems after losing generation, much of it built before 1980, during the 2011 winter event. The utility also added a gas unit designed to withstand ‑10 degrees Fahrenheit, chose simple cycle turbines over combined cycle, and installed dual-fuel capability on new additions.
The utility wound up meeting demand that was almost 37% above normal. Being part of WECC and separated from ERCOT helped, as one social media meme was quick to notice.
“The heat tracing money paid off,” Olson said, citing $19 million in customer savings during the February storm. “In a city where summer temperatures reach 105 [to] 110, people aren’t constantly thinking about winter protections.”
Members Endorse Changes from Winter Storm’s Emergency List
ERCOT’s Technical Advisory Committee last week endorsed several protocol revision requests and associated changes related to the use of emergency response service and load-resource participation in non-spinning reserves, a result of members’ work on the committee’s emergency conditions list following the February winter storm.
The committee approved the three ERS-related measures on a single ballot during Wednesday’s meeting, with only Morgan Stanley casting an opposing vote. The independent power marketer was among several from its segment that voted against the measures as they wound their way through the stakeholder process.
The key nodal protocol revision request (NPRR1090) clarifies that ERCOT has the flexibility to declare when exhausted ERS service types will be renewed for some or all of the ERS time periods and extends the deployment limit of weather-sensitive resources.
The measure revises several ERS processes, including modifying and clarifying language related to the beginning and end of contract periods for ERS renewals; removing the limit on the maximum number of deployments per contract period; and revising the cumulative deployment obligation time requirement for weather-sensitive resources.
Staff said NPRR1087 will ensure any critical load in ERS programs can continue to support critical operations if they are deployed by requiring an attestation that the resource is not located behind an electric service identifier (ESI ID) for a critical load. The NPRR also requires a qualified scheduling entity representing an ERS resource to ensure and attest that it is not located behind an ESI ID for a critical load or itself is not the critical load.
The final ERS measure (NPRR1082) changes the testing criteria for ERS load with obligations less than 100 kW co-located with an ERCOT generator.
The TAC also separately approved NPRR1093, which allows ERCOT to explore temporary workarounds for non-controllable load resources to participate in non-spinning reserves and provide additional capacity for the grid operator in the coming winter and summer seasons. The non-controllable resources will be deployed after offline units participating in non-spin.
The change request reinstates protocol requirements that were in place during the nodal market’s first five years and were then subsequently changed to enable controllable load resources to be economically dispatched and to participate in non-spin. It also incorporates market design changes that have been made for the operating reserve demand curve (ORDC) and reliability deployment price adder (RDPA) process when deploying ancillary services from non-controllable load resources.
The measure passed by a 22-6 margin with two abstentions. All four cooperatives and two independent generators opposed the NPRR over concerns that a “resulting flood” of participation in the non-spin market “will artificially suppress” the service’s value. Non-spin can clear as low as 1 cent/MWh, they said, with “bleed-over” effects into the day-ahead and real-time markets.
An earlier proposal to table the change request for a month failed 8-17, with five abstentions. Staff said any delays would close the window for making the additional non-spin available to their operators before next summer.
The measure carries a price tag between $450,000 and $650,000 and will take about a year to complete.
“This is a complex addition to the ancillary service-clearing engine,” explained Kenan Ögelman, ERCOT’s vice president of commercial operation. “That’s why it’s both expensive and time-consuming. But with so many items going on, it’s a matter of reserving resources so they can work on this too.”
The vote on NPRR1082 also included two other binding document revision requests (OBDRRs) and a change to the nodal operating guide (NOGRR):
OBDRR032: aligns the non-spinning reserve deployment and recall procedure NPRR1093’s revisions.
OBDRR033: matches the methodology for using the ORDC to calculate the RDPA with NPRR1093’s revisions.
NOGRR232: squares the guide with NPRR1093’s revisions.
Load Project Threshold Approved
The TAC approved ERCOT’s request to increase the boundary threshold used in load forecasting from 5% to 7.5% for all eight weather zones. Staff said increasing the threshold will provide the transmission service providers (TSPs) more flexibility in handling the fast-growing areas on their systems, but they also noted the Public Utility Commission directed ERCOT to pursue the increase during its Sept. 23 open meeting.
The need has become more acute with large consumers, such as data centers, proposing new facilities with accelerated development timelines in addition to the state’s explosive population growth. According to 2020’s U.S. Census Bureau data, Texas’ 29.4 million residents account for 8.9% of the country’s population, but 32.4% of the total growth between 2019 and 2020.
The Far West zone’s boundary threshold already stands at 7.5%, having been raised in 2018 because of the additional transmission necessary to address oil and gas development in the Permian Basin.
ERCOT compares its load forecast, a top-down system-level approach, with the TSPs’ ground-up projections, aggregated by weather zones. If staff’s projections are higher in a particular zone, ERCOT uses its forecast and distributes load to each substation according to the TSPs’ allocations.
In zones where the TSP forecast is higher than ERCOT’s but below the grid operator’s boundary threshold, the TSP’s projections are used. If the TSP forecast exceeds ERCOT’s boundary threshold, it is reduced to match the ERCOT forecast plus the threshold.
ERCOT’s 2021 regional transmission plan (RTP) found that demand forecasts for six of the weather zones were limited by the boundary threshold. The TSP-developed forecasts for those zones ranged from 6.8 to 11.2% above ERCOT’s projections in the RTP’s final year (2027), resulting in a demand reduction of about 2.8 GW.
“I don’t think we’re in perfect lock-step all the time, but there’s not necessarily a disconnect between the two processes,” said ERCOT’s John Bernecker, manager of transmission planning assessment. “We’re also seeing significant changes in demand-side behavior. That certainly warrants further discussion in investigating why we’re seeing some of these things we see, as well as evaluating how we approach appropriate load-forecast studies.”
“Raising this [threshold] to 7.5% is just hand-waving,” Morgan Stanley’s Clayton Greer said, calling for a subcommittee assignment. “We need to get to the root-cause analysis of what’s happening here.”
Members Endorse $101M Tx Project
Members endorsed staff’s recommendation for a $101.5 million transmission project that addresses reliability and aging infrastructure needs in the Port Lavaca area on the Gulf Coast by placing it on the combination ballot.
Staff reclassified American Electric Power’s (NASDAQ:AEP) original $97.8 million proposal to a Tier 1 project when its review found reliability planning-criteria violations that elevated the project’s costs over a $100 million threshold. Tier 1 projects must be approved by the Board of Directors.
The project involves rebuilding and adding a second 138-kV circuit to 10 miles of an existing line; upgrading 24 miles of 69-kV line to 138 kV or capable; constructing two 138-kV substation and one 138/69-kV substation and installing two 138/69-kV transformers to replace 69-kV facilities; and retiring 20.3 miles of 69-kV line.
About 40 miles of the area’s 69-kV lines date back to 1949 to 1953. AEP expects to complete the project by December 2024.
Slim Combination Ballot Passes
The TAC pulled NOGRR223 off the combination ballot to allow Luminant (NYSE:VST) to vote against it. The measure, which requires phasor measurement recording equipment at existing facilities with an aggregated capacity above 20 MVA at a single site before entering the interconnection queue or change-request process, passed 27-1, with two abstentions.
Luminant said there is no “clear justification” for ERCOT to require phasor measurement unit capability, as most of the burden is on owners with the 20-MVA requirement for new generation resources.
The remainder of the combo ballot included two revisions to the planning guide (PGRR) and a change to the resource registration glossary (RRGRR):
PGRR093: reinserts three requirements into the board-approved graybox language for PGRR082 that were inadvertently removed in its revisions.
PGRR094: aligns the guide with current practices by grayboxing language requiring project construction start and completion date submittals until system implementation in the resource integration and ongoing operations-integration services system.
RRGRR030: removes certain transformer data’s hard coding of voltage levels for certain resource registration information, allowing resources connected to other voltage levels to submit their registration data without receiving validation errors.
FERC on Friday gave CAISO and NYISO 30 days to explain some details of the treatment of distributed energy resource aggregations described in their Order 2222 compliance filings (ER21-2455, ER21-2460).
Most of the commission’s questions to the ISOs concerned the market participation model for DERs and the coordination between the ISO, aggregator and distribution utility, particularly the role of the utility.
The commission asked NYISO to “explain how the DER aggregation rules accommodate the physical and operational characteristics of heterogeneous aggregations and, in particular, heterogeneous aggregations that include mostly one resource type. For example, please explain how NYISO’s DER aggregation rules accommodate the physical and operational characteristics of an aggregation comprised primarily of solar resources with some storage.”
FERC said NYISO outlined the resource adequacy problems that could arise from “modeling an aggregation of solar intermittent power resources as a DER aggregation” and asked “why similar concerns would not arise with a DER aggregation that is composed largely, but not exclusively, of solar resources.”
Continuing in the same vein with CAISO, the commission referred to the ISO’s proposals to require that a DER aggregation have at least one DER capable of injecting energy and to maintain its existing demand response models for homogeneous aggregations that include DR resources only.
“If a heterogeneous aggregation containing injecting resources and distributed curtailment resources fails to inject energy over a certain interval — i.e., if the aggregation only provides demand response to CAISO — would CAISO require the aggregation to register in one of CAISO’s demand response models in order to participate in the CAISO markets?” the commission asked. “If so, please explain when CAISO would require this change in registration and indicate where this process is documented.”
CAISO in September answered its stakeholders in the FERC docket by clarifying several aspects of its compliance filing, but it dismissed many comments as related to issues outside the scope of Order 2222.
“The commission plainly could have ordered RTO/ISOs to collapse their demand response models into a single [DER aggregation] model as NYISO did, but Order No. 2222 did not,” CAISO said. “Instead, it required RTO/ISOs to allow DERs to aggregate with demand response resources as heterogeneous aggregations, the plain language of which requires a mix: both energy-injecting DERs and demand response resources.”
Other comments are based on “improbable hypotheticals involving multiple-use applications” and retail tariffs. DER aggregations and dual wholesale/retail participation are nascent fields, especially when addressed simultaneously, CAISO said.
The New York ISO last month rejected most comments and protests on its treatment of DERs and aggregations, urging FERC to accept its Order 2222-related tariff revisions with minor adjustments. (See NYISO Rejects Most Comments on DER Treatment.)
FERC issued “incredibly detailed” questions to NYISO and CAISO, and the questions “to NYISO are especially interesting, as they get at central issues that will determine if rooftop solar plus storage, [electric vehicles], etc. can participate,” tweeted Jeff Dennis, managing director and general counsel for Advanced Energy Economy.
Role of Distribution Utilities
FERC also asked NYISO to provide the criteria by which distribution utilities would determine whether a DER is capable of participating in an aggregation, including any specific metrics.
“Will the aggregator attestation requirements proposed in NYISO’s answer with respect to double counting be sufficient for distribution utilities and NYISO to determine whether a DER is capable of participating in an aggregation?” the commission asked.
In addition, the commission asked NYISO to explain what showing is required from the distribution utility to support the decision that the resource presents significant risks to the reliable and safe operation of the distribution system, and to explain what the ISO means by “appropriate measures to mitigate reliability and/or safety concerns.”
The commission also wanted to know how NYISO intends for its tariff provisions to satisfy the commission’s requirement to include dispute resolution procedures and what other avenues, if any, are available to aggregators or distribution utilities to resolve disputes.
“For example, what avenues are available to aggregators to dispute a distribution utility’s determination regarding whether a proposed DER is capable of participation in an aggregation and will not pose significant risks to the reliable and safe operation of the distribution system?” the commission asked.
The Tehachapi Energy Storage Project is a lithium-ion battery energy storage system at the Monolith Substation of Southern California Edison in Tehachapi, Calif. | Sandia National LaboratoriesMeanwhile, FERC asked CAISO to explain whether — and if so, how — the ISO allows for voluntary relevant electric retail regulatory authority (RERRA) involvement in coordinating the participation of DER aggregations in its markets.
It also directed CAISO to specify whether RERRAs will have a role in coordinating the participation of DER aggregations in its markets by developing interconnection agreements and rules.
Finally, the commission asked CAISO whether RERRAs would have a role in developing local rules to ensure distribution system safety and reliability, data sharing and/or metering and telemetry requirements; overseeing utility distribution company review of DER participation in DER aggregations; establishing rules for multiuse applications; or resolving disputes between DER aggregators and utility distribution companies over issues such as access to individual DER data.
In its Sept. 3 answer, CAISO said it recognized that resource adequacy eligibility incentivizes resources in its footprint to participate as standalone wholesale resources or DR resources.
“California regulatory authorities, most notably the California Public Utilities Commission, have not adopted qualifying capacity counting rules for [DER aggregations] to provide resource adequacy capacity, which leaves developers without the revenue streams from retail tariffs, capacity contracts or power purchase agreements,” CAISO said.
Finding ways for long-duration storage to play a greater role in the clean energy transition was a key topic Wednesday at the North America Smart Energy Week summit hosted by the Solar Energy Industries Association and the Smart Electric Power Alliance (SEPA).
“The topic of long-duration storage has been top of mind for many of us in the industry lately, and there does seem to be a growing recognition of the role long-duration energy storage can and should play in the electric grid of the future,” moderator Robert Tucker, SEPA director of industry strategy, said as he introduced the panel.
“Most recently this focus was evidenced by the U.S. Department of Energy’s announced goal to reduce the cost of grid-scale long-duration energy storage by 90% within the decade,” Tucker said. “This goal, which is part of DOE’s Energy Earthshot Initiative, was discussed at its recent Long Duration Storage Shot summit that was held just last week. I attended that summit, which included presentations from members of Congress who all spoke to the importance of energy storage and long-duration energy storage, specifically to achieving our national carbon reduction goals.” (See DOE Targets 90% Cut in Cost of Long-duration Storage.)
Tucker continued the discussion Wednesday with Jaya Bajpai, principal with consultant Gamma Advisory; Erin Childs, senior manager at client advisory firm Strategen; and Frank Jakob, technology manager for energy storage at engineering firm Black & Veatch.
The first question, Tucker said, was how to define long-duration storage. DOE defines it as 10 hours, he said, but should it be defined in longer terms to handle significant power-outages such as Hurricane Ida in New Orleans, last winter’s Texas deep freeze and California’s summer heat storms, all of which typically last days?
Jakob said lithium-ion batteries are limited to four or five hours. Flow batteries are good for intermediate time frames. Pumped hydropower can last 12 hours, but building it is difficult. So newer technologies for long-duration storage will be needed and are starting to be developed, he said.
Bajpai agreed. “What you see now is a tip of the iceberg. There’s a lot more coming,” he said. Utilties understand that two to four hours of battery storage “is just not getting it done.”
Systems with a lot of wind and solar, such as SPP and CAISO, may need storage that can last 10-12 hours; multi-day and multi-week options will come along later this decade or in the early 2030s, he said.
“From a procurement perspective I think you’ll see the hours get longer,” he said.
Incentivizing Storage
Childs said long-duration storage is currently a broad, vague term that covers resources that might last from six hours to 150 hours. Such resources will play very different roles on the grid and need more precise language to describe them, she said. Are they meant to supply power in the evening when the sun goes down in California, or during systemwide crises lasting days or weeks during severe winter or summer weather?
“The overnight versus seasonal is really part of this issue,” she said.
Clockwise from top left: Robert Tucker, SEPA; Erin Childs, Strategen; Jaya Bajpai, Gamma Advisory; Frank Jakob, Black & Veatch | SPI, ESI, and Smart Energy Week
Tucker next asked Childs to give an overview of regulatory and policy issues related to long-duration storage.
Integrated resource planning will be key, she responded. “This is where [public utility] commissions are making decisions about what’s going to be brought onto the grid and the first question is, ‘Is long duration storage even on the list?’”
The California Public Utilities Commission has led the way by ordering investor-owned utilities to procure 1 GW of long-duration storage by 2026, she noted. (See CPUC Orders Additional 11.5 GW but No Gas.)
Bajpai said long-duration storage hasn’t traditionally been part of utilities’ IRP process because it’s expensive and doesn’t necessarily fit conventional supply-and-demand models.
“When you step out of the box of the conventional model, you begin to see that there is actually a much bigger role for flexible, long-duration storage,” he said. “What if I was to give you an 8-, 12- or 16-hour resource that can move power over one, two, three days and that can suddenly flex between applications? That’s something that’s very valuable from a reliability perspective to the utility.”
“I think the biggest issue here is monetizing storage,” Bajpai said. “The reality is that the transition is going to be expensive one way or another … and so I think we need vehicles and instruments that essentially reward long duration storage” as flexible, bidirectional resources, he said.
“The idea that you are compensating folks to be there, to go at a moment’s notice, and to provide a full range of flex options — I think that is powerful, and I think it needs to be compensated,” he said.
‘Time Machines’
Tucker asked the panelists if government policies are more of a roadblock to the adoption of long-duration storage “or is it more about the abilities of the technology that’s available in the marketplace?”
Jakob answered: “The greatest roadblock is the true availability of product in the marketplace that’s been proven [to work].”
Would-be adopters don’t want to be the first to try out an unproven technology, he said.
“I have many clients who want to be first to be third in line to buy new technologies,” Jakob said, prompting smiles from the other panelists.
The largest utilities are likely to be early adopters, he said.
“There are big names in the industry that have been experimenting with all sorts of technologies for decades now, but the run-of-the-mill utilities, those here in the Midwest and in Kansas and Missouri,” aren’t eager to embrace new technologies, he said.
He likened it to the situation 10 years ago when large utilities started to experiment with grid-scale lithium-ion batteries. Now, he said, the bigger utilities will need to experiment with longer-term storage technologies that act as “time machines” for moving energy from when it’s produced to when it’s needed.
Jakob and other panelists cited emerging technologies such using solar mirror arrays to melt aluminum and producing hydrogen from renewable energy. The Los Angeles Department of Water and Power, they noted, is investing in green hydrogen production and storage in the Utah desert. (See NARUC Panel: ‘Green’ Hydrogen Could Lower GHGs.)
“I think we’re going to see a lot more of that because it’s part of the energy storage grand challenge,” Jakob said. “If you want long-duration storage, you need to build a 25 MW or 50 MW 12-hour or 24-hour demonstration unit.”
“There’s going to be major steps with the new driver, that’s now very much in our face, of low-carbon generation,” he said.
Stakeholders from across the energy industry met Thursday at FERC’s annual Reliability Technical Conference to discuss the most pressing issues affecting the reliability of the electric grid.
“It’s not an overstatement to say lives [are] literally at stake. All you have to do is look at what happened in Texas this past February … and then more recently in Louisiana in the aftermath of Hurricane Ida,” FERC Chairman Richard Glick said in his opening remarks. “People literally can die when the power goes out, especially for an extended period.”
Slow Pace of Standards Process Criticized
The day’s first panel focused on NERC, with participants debating the adequacy of the organization’s reliability standards to address the “two major threats to grid reliability” that Glick identified: climate change and cybersecurity. While many participants praised NERC and its staff for their efforts to enhance reliability, they warned that the organization’s current approach may need to change to keep up with the evolving threat landscape.
Cheryl LaFleur, Center on Global Energy Policy | FERCThe current standards process “has a built-in bias toward conservatism” because of the influence of “the very industry members who will be … potentially subject to substantial penalties” if the standards are violated, said former FERC Commissioner Cheryl LaFleur, now a senior research scholar and board member at the Center on Global Energy Policy.
“Those entities have a natural fear of enforcement, which can lead to standards attainable by the dreaded lowest common denominator,” LaFleur continued. “And the process favors those who want to move slowly, with numerous opportunities for further study, further discussion, delay, and repeat voting cycles.”
LaFleur offered four suggestions for stakeholders to “meet the urgency of the moment.”
First, NERC should aim to develop standards that focus on risks to be mitigated, rather than requiring specific actions that might become outdated quickly. Second, decisions about focus areas should be based on NERC’s analysis of emerging threats rather than “the commercial interests of specific registered entities,” though those stakeholders deserve a place at the table.
NERC CEO Jim Robb | FERCNext, LaFleur reminded Glick and his colleagues that FERC “should be strongly involved” in the standards process, with commissioners attending meetings of NERC’s Member Representatives Committee and Board of Trustees, using “soft power” to help keep the process moving, and ordering development of standards on specific timelines where necessary. Finally, the commission and NERC should be willing to “take the foot off the enforcement accelerator in the case of new, unproven standards.”
The panel also touched on resource adequacy, with Commissioner Allison Clements asking NERC CEO Jim Robb for his thoughts on the ongoing need for natural gas as a balancing resource. Robb replied that he expects gas to be part of the grid for the foreseeable future, even as utilities, regulators and policy makers work to shift to a system fueled primarily by renewable resources.
Jennifer Sterling, Exelon | FERC“We can all agree that gas is a bridge resource to the future that we want to get to,” Robb said. “The question is, how long is that bridge? We’d love for it to be a creek crossing … but it’s not going to be because of the technology limitations on other flexible resources and the scale at which they would need to be deployed.”
“The thing that concerns me the most going forward is whether we’re reinforcing the gas system adequately in order to provide the balancing that’s needed for the renewable resources that we’re adding,” he added, referring to concerns he has raised in other forums about the suitability of the nation’s natural gas infrastructure to serve the bulk power system during crises like February’s winter storms in Texas. (See Senators Grill Robb, Asthana over Texas Outages.)
Jennifer Sterling, vice president of NERC compliance and security at Exelon, reminded commissioners that regulators should not be the only voice in the conversation, and urged FERC to make sure industry is included.
“I don’t think that the … resource adequacy issue can be solved by NERC and FERC alone, and it certainly cannot be solved just with NERC standards,” Sterling said. “We need a holistic conversation with state regulators and market operators, RTOs, etc. I don’t think that … reliability standards [alone] are going to fix this issue.”
Probabilistic Planning Needed to Account for Extreme Weather
The second panel focused on the recent uptick in extreme weather events, including the February winter storm, the wildfires and heat waves in the West, and the impact of Hurricane Ida.
Peter Brandien, ISO-NE | FERCMuch of the discussion covered old ground, such as the need for better gas-electric coordination and transmission planning. This apparently frustrated Peter Brandien, vice president of system operations and market administration at ISO-NE.
“I feel a sense of urgency,” he said. “I feel like I’m on a train track at the end of the tunnel, and the light is getting bigger and bigger, ready to run me over. We’ve heard a lot of talk here today about ‘we need to do; we need to investigate; we need to spend some time.’ I think we should enhance the standards that require people to perform these types of analyses, identify their risks and have plans to address them. I think the time to be talking and investigating and all these buzzwords that we heard today is past us. I think we actually have to mandate people to do this.”
Brandien said ISO-NE is seeking to develop probabilistic tools, which incorporate elements of randomness, to plan its system, as opposed to deterministic models, which are dependent on initial conditions and static parameters. The need for probabilistic models came up frequently throughout the discussion.
Aubrey Johnson, MISO | FERC“I truly believe that the old methods of deterministic planning are too archaic to address some of the challenges we have going forward,” said Branden Sudduth, vice president of reliability planning and performance analysis at WECC. “We have to be able to adapt to these probabilistic processes. … There are just too many unknowns, too many variables in the equation … not just the changes in how generating resources might behave in the future, but also the changes in seasonal demand that we’re starting to see over the last year or so.”
“What we have to do is provide our operators with the ability to handle greater uncertainty,” said Aubrey Johnson, executive director of system planning and competitive transmission at MISO. “So they don’t need data; they need information upon which to act.”
Mark Hegerle, director of FERC’s Division of Operations and Planning Standards, asked the panel how FERC could drive grid planners toward a probabilistic approach, specifically whether NERC’s mandatory reliability standards were the appropriate method.
Michelle Cathcart, BPA | FERC“I hesitate a little on [using standards] because I think there is still some maturity in those tools that needs to be accomplished before we can reasonably enforce that on the utilities,” said Michelle Cathcart, vice president of transmission system operations at the Bonneville Power Administration. “I can see it in the future, but it may be premature at this point.”
Brandien recalled that he testified before FERC about a decade ago and was asked whether a cold-weather standard was needed. “I didn’t think so at that time because I thought it was … our bread and butter as an industry. We should be able to do it; we didn’t need a standard that required us to do it.”
He noted previous recommendations to reconsider load-shedding procedures and underfrequency protection. “Those were things I didn’t think we needed standards on. But it’s obvious that time and time and time again, we can’t get out of our own way as an industry and repeat these problems. I do think we need standards around things that are critically important.”
Supply Chain Attacks Keep Cyber Experts Awake
Attention shifted to cybersecurity in the third panel, with attendees mainly discussing the implications of supply chain attacks like last year’s compromise of SolarWinds’ Orion network management software. The SolarWinds attack, in which hackers managed to gain access to the platform’s update server and use it to push espionage malware to thousands of users worldwide, sent shockwaves through the security community.
“The competent, savvy defender [used to] say, ‘I’m building my cybersecurity infrastructure [with] the assumption that the adversary is already in it,” said Mark Fabro, president and chief security scientist at technology security firm Lofty Perch. “We’ve actually since migrated to the assumption that the adversary has built the system.”
The idea that software and hardware could be tainted at the source led Glick to ask participants whether a government-issued cybersecurity whitelist or blacklist might be needed, to identify suppliers that utilities should or should not purchase from, respectively. But Manny Cancel, CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), spoke for many when he expressed skepticism about the ability of any such registry to keep pace with the rapidly evolving threat landscape.
“As products change, and their reliance on other third parties [grows], tracking that … gets very difficult to sustain and maintain,” Cancel said. “There may be a place for a whitelist or blacklist; I’m of the opinion that it really is the application of the correct cybersecurity risk mitigation program that you put in place that protects any assets.”
Matthew Halvorsen, strategic program manager for the supply chain and cyber directorate at the National Counterintelligence and Security Center, was more blunt in his assessment of the downsides of such a program.
“There’s a couple of reasons that it’s problematic. First of all, each organization is going to have [its] own risk appetite, so a whitelist or blacklist is not going to affect that,” Halverson said. “Another thing is … it’s out of date 10 minutes after you make the list, and the adversaries know that they’re going to see the list because [it’s] going to be public, so they’ll change their company name, or slap a different label on the product. So it’s really hard to keep up. And then the last problem … is the concept of due process for the companies. … How did I get on the list? How do I get off the list? How do I refute what you’re saying [or] sue because my competitor is on the whitelist and I’m on a blacklist?”
Changing Resource Mix Challenge
The final panel of the day focused on how to maintain grid reliability as the fast-changing resource mix includes more variable generation and inverter-based resources (IBRs) such as wind, solar and storage.
FERC Chairman Richard Glick | FERCGiven some of the issues with inverter-based resources and the differences between them and synchronous generation, Glick asked whether existing NERC standards might need to be modified to maintain reliability.
The industry does not need new standards or technical guidelines, though some of them have to be reinterpreted for the different characteristics of inverters because they’re very different from synchronous machines, said Mark Ahlstrom, vice president for renewable energy policy at NextEra Energy Resources and NextEra Analytics.
“The intent of the standards was clear, so we just have to make sure that that intent is then interpreted in the analogous way for inverters, and it might be implemented quite differently, but they can certainly accomplish all the same things,” Ahlstrom said.
The Institute of Electrical and Electronics Engineers (IEEE) is currently developing the P2800 standard for the interconnection and operability of inverter-based resources, which is going to help address issues like momentary cessation of output as well as other functionalities, said Debbie Lew, associate director at Energy Systems Integration Group, an independent non-profit focused on decarbonization of energy systems.
Mark Ahlstrom, NextEra Energy Resources | FERCThe IEEE P2800 interconnection standards being developed comprise uniform technical requirements for interconnection capability and lifetime performance of inverter-based resources connected to transmission and sub-transmission systems, said Aleksi Paaso, director of distribution planning, smart grid and innovation at ComEd, speaking on behalf of the IEEE.
The new standard “is going to provide some flexibility to transmission owners on how they want to specify requirements, while also providing capability from these resources so that in the future as you need new capabilities you’ll be able to turn those on,” Lew said.
FERC and NERC “need to go further” and adopt modified standards like PRC-24,” said CAISO COO Mark Rothleder.
Lacking a standard entails a risk that there will be individual applications to address some of these reliability matters, and there may be inconsistent applications, Rothleder said.
“I think we’re at a point now in the transition curve that we need some consistent standards that are applicable to the new inverter-based resources, and I think we have enough learning that we’ve achieved to apply those efficiently,” Rothleder said.
Aleksi Paaso, ComEd and IEEE | FERC
FERC’s Clements asked about the use of grid-enhancing technologies such as dynamic line ratings or adjusted ambient ratings in the West, and also inquired about developments in the Western resource adequacy effort.
“I feel like the neighbors of neighbors concept is the reality of the situation,” said Idaho Public Utilities Commissioner Kristine Raper, speaking on behalf of the Western Interconnection Regional Advisory Body. “We had the heat dome, and sharing of the energy from the coast to the inland Northwest states couldn’t occur because everyone was using energy, but transmission lines would assist us further in using neighbors of neighbors’ energy to try and balance that out.”
The Western Resource Adequacy Program provided by the Northwest Power Pool this week secured funding from its participants to move forward with implementing the non-binding phase of the program, NWPP President Frank Afranji said. “This is a monumental accomplishment by the public-spending NWPP representatives.”
“We need to take the comments that we received today, talk amongst ourselves talk with NERC and other stakeholders as well, and get a better sense of what we need to do next,” Glick said in closing. “This important responsibility is not just about making sure rates are just and reasonable … we’re literally talking about people’s lives here and making sure that they have access to what’s an essential resource, which is electricity and natural gas and other energy resources.”
Back in 2012, when D.C. launched its first program to bring solar to its low-income neighborhoods — concentrated in three of its eight wards — most of the rooftop solar, more than 800 installations, were in the upscale Ward 3.
Today, almost 10 years later, one of those low-income wards, Ward 7, has more solar than Ward 3, said Ted Trabue, managing director of the D.C. Sustainable Energy Utility (DCSEU), which manages the current iteration of the district’s low-income solar program, now called Solar for All. About 1,000 low-income, single-family homes have rooftop installations, and by year-end, 6,000 low-income residents will be receiving credits on their utility bills from community solar projects, Trabue told the audience at Tuesday’s inaugural D.C. Clean Energy Summit.
The nation’s capital made headlines in 2018 when it set an ambitious renewable energy target: 100% clean power by 2032. The half-day summit, which was both in-person and virtual, provided an overview of the programs, projects, businesses and jobs that the mandate has helped to create so far, as well as the opportunities and challenges that lie ahead.
DCSEU was established in 2011 specifically to promote energy efficiency and clean power in the district, with 20% of its funds going to projects that benefit low-income residents, a figure recently raised to 30%. An early program it is now looking to expand helps low-income residents replace old fossil fuel-fired heating systems and other appliances with new, more efficient electric ones, Trabue said. To support the district’s new building energy performance standards, the utility also offers a range of training courses for local developers and contractors to expand their skills in green building, energy efficiency and solar.
On the commercial front, New Columbia Solar, a local installer, has grown from the handful of employees who started the company in 2016 to about 100 today, CEO Mike Healy said. The company has developed 25 MW of solar projects in the district, including several Solar for All projects, he said.
Getting D.C., and the U.S., to 100% clean energy will mean accelerating solar deployment and going to “the built environment,” such as roofs and parking structures, Healy said. The district doesn’t “have enough transmission capacity to be able to take power into the [urban] pockets,” he said. “What New Columbia has really tried to focus on is, how do we do that? How do we capture that power that essentially needs to be built in the population center to be able to actually power our city here with solar?”
Volt Energy, a minority-owned solar developer, has expanded its business with a focus on “making sure that young people, and particularly young people of color, are thinking about clean energy as a career path,” co-founder and CEO Gilbert Campbell said. One of the company’s early projects was a 227-kW installation at a D.C. charter school, coupled with a STEM awareness program for students.
Volt is also developing a project with Howard University — Campbell’s alma mater — that he said, will be one of the largest at a historically black college or university. Though not in D.C., a new spinoff, Volt Energy Utility, inked an “environmental justice power purchase” agreement with Microsoft in July to develop 250 MW of solar, with part of the revenue from the project going to fund renewable energy projects in inner city and other disadvantaged communities, Campbell said.
The SREC Paradox
Looking ahead, what was less clear at the summit was exactly how D.C. will get to 100% clean energy in the coming decade. The district’s mandate requires its retail electricity suppliers to increase the amount of clean power they provide by 6.25% a year through 2032, starting from 20% in 2020. The mandate also has a solar carveout, calling for at least 5% of the district’s power to come from solar projects built in the city by 2032, rising to 10% in 2041.
The catch is that the economics of D.C.’s solar market, and the Solar for All program itself, are rooted in a very competitive market for solar renewable energy credits (SRECs), which the majority of the district’s 47 retail electricity providers buy to satisfy their annual clean energy requirements. The current price for D.C.’s SRECs, as listed on the SRECTrade website, is $392, and according to a recent report from the D.C. Public Service Commission, most of the retail suppliers in 2020 bought and submitted close to 2 million SRECs to avoid paying further compliance fees.
Further, PEPCO, the district’s major power supplier, still produces close to 60% of its power from coal and natural gas versus 6% for renewables, with nuclear at about 34%, according to its most recent report on its generation mix. Speaking on a panel on electrification and equity, Calvin Butler, CEO of Exelon Utilities (NASDAQ:EXC), PEPCO’s parent company, focused primarily on the utility’s commitment to electrifying its own fleets and to programs aimed at improving energy efficiency and lowering electric bills for low-income customers.
Exelon and its six utilities have “committed that we will electrify our transportation fleet by 32% in 2025, and 50% by 2030,” Butler said. “But we have to partner with government, commercial and other partners to make sure electrification happens on a broad scale. That means ensuring individual consumers in Washington, D.C., will have access to electric transportation options, including but not limited to public transportation, taxis and ride sharing, as well as charging infrastructure.”
In an email responding to questions from RTO Insider, Ben Armstrong, PEPCO’s director of operations communications, said that the utility’s current energy mix “reflects the overall electricity mix of the region’s power system.”
PEPCO purchases power through a “multiphase competitive bidding process,” Armstrong said. “By 2032, 100% of the power included in these bids must come from renewable sources. Renewable energy credits and solar renewable energy credits will be an important part of meeting these requirements, along with advancing local solar.”
Tommy Wells, director of the D.C. Department of Energy & Environment, acknowledged that the district’s current reliance on RECs would make it possible to get to a 100% carbon-neutral system “tomorrow,” without actually putting new renewable energy projects on the grid.
But Wells believes that D.C.’s REC market is bringing “some additionality to the grid by creating a market or financial incentives for creating more renewables. … We are getting solar deployed in the city because you can make so much money off of it,” he said. “It’s not one-for-one creating additionality of renewables to the grid, but it’s working.”
Regulators Discuss the ‘Boss’ of Energy Goals
In the first panel of the conference on Tuesday, “Who’s the Boss? Navigating the Federal and Regional Context to Meet State Clean Energy Goals,” state regulators and officials were asked what is the driving the transition to clean energy.
PJMCEO Manu Asthana answered that the so-called “bosses” are consumers “voting with their wallets,” state policymakers,FERC in its attempt to be “forward looking” with its rules and NERC as the arbiter to maintain reliability.
“This is a really exciting time for our industry,” Asthana said. “I believe RTOs can be an important tool to help achieve policy objectives.”
New York Public Service Commissioner Diane Burman said the process needs to be about “getting under the hood” on how to achieve renewable goals efficiently and an “uncompromising need” to focus on safety, reliability and resilience.
“States need to be cognizant of the risks of making abrupt decisions that could result in catastrophes like California and Texas have experienced,” Burman said.
Jason Stanek, chairman of the Maryland Public Service Commission, said that what’s driving policy is “every individual, every utility executive, every voter in this country.” He said he deals with individuals who see the cost of investing in updating and upgrading the transmission as being too expensive an endeavor to tackle. Stanek said his regular response is, “What is the alternative?”
“Transmission policy is in desperate need of reform, and it has been for some time,” Stanek said. “I think it’s fair to say that business as usual, whether it be with respect to transmission planning, cost allocation or generator queue reform, is long overdue.”
A divided Connecticut Supreme Court on Tuesday upheld a lower court decision to approve a new gas-fired power plant in the northeastern part of the state, dismissing a local environmental group’s complaint that the state’s siting body did not account for potential environmental damage from a needed expansion of a pipeline to deliver fuel.
The decision was a legal victory for NTE Energy, builder and developer of the 650-MW plant proposed for the town of Killingly, and Eversource Energy, which is expected to rebuild an existing pipeline to deliver gas to the facility.
Killingly-based group Not Another Power Plant contended that the Connecticut Siting Council (CSC) acted “improperly” in its siting decision when it “failed to consider the environmental impact of a gas pipeline that would have to be installed in the future to provide fuel to the facility.” Because the plant cannot operate without the pipeline, CSC should have considered the plant and pipeline concurrently.
Chief Justice Richard Robinson wrote that the lower court “correctly determined” that the CSC did not inappropriately “segment the project” because CSC must consider the environmental impact of the gas pipeline in a future proceeding and “NTE alone would bear the cost and risk if the pipeline is not approved.”
Concurrences and a Dissent
Justice Andrew McDonald wrote that while he concurred with the majority decision, he was not persuaded by its ultimate conclusion that the CSC was precluded “from considering an interdependent facility that does not yet exist when balancing the public benefit that will be provided by a proposed facility against the harm that it will cause to the environment.”
“Applications filed with the [CSC] are unusually technical and remarkably detailed, and the majority does not explain how the [CSC] should evaluate the probable environmental impacts of facilities for which it does not have that detailed information,” McDonald wrote.
McDonald added that, under Connecticut law, “it is improper” to consider nonexistent facilities “that may or may not be the subject of future applications … by completely separate applicants.”
“The majority opinion undermines the legislature’s choice by extending the authority of the council to permit consideration of nonexistent, hypothetical facilities when evaluating a proposed facility,” McDonald said.
McDonald concluded that “segmentation of applications for interrelated facility projects … are policy decisions for the legislature to make, not this court.”
Justices Steven Ecker and Gregory D’Auria concurred with part of the ruling but also dissented with another portion. They said the lower court decision should be reversed with the direction that the CSC reconsider its approval of NTE’s application and consider the potential environmental impact of the future Eversource gas pipeline.
Reaction
NTE Managing Partner for Development Tim Eves told RTO Insider the company “has adhered to Connecticut’s stringent development and regulatory process” since it gained certification from the CSC in 2019.
“The court’s decision reaffirmed the rigorous environmental regulatory review process the facility passed in order to receive CSC certification, and we look forward to supporting Connecticut’s transition to a renewable energy future,” Eves said.
When asked for a reaction to the ruling, a spokesperson for the Department of Energy and Environmental Protection (DEEP) said that the agency issued a final decision on Jan. 20 for the permit to discharge to the sewer, which authorized NTE to submit final construction plans and specifications of the wastewater facility. The permit will be issued after the approval of those plans. DEEP added that the comment period has closed on Eversource’s Water Quality Certification application for the pipeline. DEEP is in the process of reviewing the comments.
The Connecticut Attorney General’s office, through its spokesperson, said it “defers to the written record.” ISO-NE did not have any comment on the ruling.
SEEM as planned by its proponents: The utilities and cooperatives participating in SEEM, which include Southern Co. (NYSE:SO), Duke Energy (NYSE:DUK) and the Tennessee Valley Authority, claim that expanding bilateral trading in 11 Southeastern states will reduce trading friction while promoting the integration of renewable resources.
An energy imbalance market (EIM) set up to optimize capacity expansion through the least expensive combination of thermal and renewable energy generation, storage and transmission. Balancing authorities are required to meet their planning reserves within their footprints but can use energy transfers between regions for their planning reserve requirements.
An RTO in which “every balancing region undergoes optimal capacity expansion, ensuring the footprint as a whole meets their planning reserve requirements on their coincident load.”
An RTO with the same assumptions as the previous model, but in which utilities also set a common goal to reduce electricity sector carbon emissions by 98.5% by 2040.
All four scenarios were run over the same time frame, starting in 2020 and ending in 2040. VCE compared the four scenarios on the basis of cost savings, as well as reductions in carbon emissions, using its Weather-Informed energy Systems: for design, operations and markets-Planning (WIS:dom-P) software to model the outcomes.
All Scenarios Outperform SEEM
While all scenarios showed positive results in both categories, changes under SEEM were more modest than any of the others. In VCE’s model, adopting SEEM caused total resource costs to drop from $64.7 billion in 2020 to $53.1 billion in 2040. Meanwhile, carbon emissions in 2040 were 30% below 2020 levels under SEEM; carbon dioxide emissions from the electric sector for the studied period were slightly below 3.4 million metric tons.
Inter-region bulk transmission and county-level transmission topology for the SEEM region | ACORE
By comparison, all the other scenarios projected significantly more aggressive cost reductions than the SEEM proposal. The EIM performed best in terms of total resource costs, which fell to $42.1 billion by 2040 under VCE’s model. Resource costs for the RTO were around the same level, while the RTO with decarbonization (RTO+Decarb) was just under $50 billion. The RTO showed the greatest cumulative savings with $119 billion saved over 20 years compared to SEEM; EIM saved $111 billion over SEEM; and RTO+Decarb saved $103 billion.
According to VCE, the EIM scenario saw the greatest reduction in resource cost because of performing “optimal capacity expansion and [counting] the energy transfers between the balancing areas towards the planning reserve.” This is despite EIM actually trailing the two RTO scenarios in the first 10 years of the model because it “retires the fossil generation slower than the ‘RTO’ [scenarios] and therefore results in higher system costs.”
Becuase the RTO outperforms the EIM for the first 10 years, it has a slight edge in cumulative savings. The RTO+Decarb scenario displays similar resource cost reductions to the base RTO until 2034, when large investments in variable renewable generation are needed to reach decarbonization goals.
RTO+Decarb Clear Emissions Winner
While the EIM scenario delays full retirement of fossil fuels compared to the RTO scenarios, SEEM does not do so at all: VCE’s model shows more than 100 GW of installed coal and natural gas capacity by 2040 under SEEM, compared to around 70 GW of natural gas for EIM and base RTO — without any coal — and around 20 GW of gas generation under RTO+Decarb. The EIM, RTO and RTO+Decarb scenarios all see significant expansion of renewable generation as well, especially the latter with nearly 400 GW of renewables in 2040, compared to around 200 GW each for the other two.
Investments in storage under the non-SEEM scenarios also dwarf that under SEEM, with about 10,000 MW of storage capacity installed in 2040 under SEEM (about double 2020 levels). By the same year, EIM and RTO have about 90,000 and 100,000 MW of storage capacity installed, respectively, while RTO+Decarb has about 65,000 MW.
This replacement of fossil fuel generation with renewables and storage means that the non-SEEM scenarios see substantial reductions in emissions over the 20 years of the study. Compared to SEEM’s 3,362 million metric tons (mmT) emitted by 2040, the EIM shows 2,614 mmT emitted over the same time frame and the RTO shows 2,560.Cumulative electric sector carbon emissions in the scenarios modeled | ACORE
The RTO+Decarb scenario shows the greatest reduction in carbon dioxide emissions, as might be expected from its explicit focus on decarbonization. Under this template, cumulative emissions fall to 2,389 mmT, representing the end of virtually all carbon emissions. VCE’s model only accounts for existing techniques for carbon reduction, so new technologies such as carbon sequestration could see the atmospheric carbon reduced even further.
RTO+Decarb is also notable for nearly eliminating all other air pollutants tracked by VCE’s model, including sulfur dioxide, nitrogen oxides, and carbon hexafluoride, all of which are still present in significant amounts by 2040 under SEEM. While the EIM and RTO both see all pollutants except nitrogen oxides reduced to near zero, RTO+Decarb is the only scenario where NOx is also almost completely gone.
ACORE’s report could lend ammunition to critics of SEEM that have warned FERC to exercise skepticism about the promises of the proposal’s supporters (ER21-1111, et al.). Most recently a group of Democratic lawmakers in North Carolina wrote the commission calling for a technical conference to investigate other Southeast market organization proposals, including an RTO or EIM. (See NC Legislators Join Call for Southeast Technical Conference.)
The historic shift away from carbon-based fuels to clean energy sources such as solar — which the industry now asserts can supply 30% of the nation’s electricity by 2030 — is encountering significant resistance from some unexpected corners.
Whether they’re farmers, Native Americans or residents living in economically depressed neighborhoods, people who will live near utility-scale solar arrays are increasingly opposed.
The issue received a brief airing Wednesday in a virtual panel during the North American Smart Energy Week sponsored by Solar Energy Industries Association (SEIA) and the Smart Electric Power Alliance.
“This session on land use is very timely, as we see more solar being developed and installed in more places. We are seeing more and a wider variety of land use conflicts,” said Sean Gallagher, vice president of state and regulatory affairs for SEIA, and moderator of the discussion.
Citing a Department of Energy study, Gallagher said the industry could supply 45% of the nation’s electricity using just 0.5% of the land in the lower 48 states by 2035. He stressed that equity and environmental issues must be considered in the planning process of any new solar development.
Chris Carr, an attorney focused on infrastructure development at a San Francisco law firm Paul Hastings LLP, said enhanced tribal consultation and environmental justice policies at both federal and state levels are now integral to any solar project developed in California and other Western states. Climate change and the impact of that on protected species are also significant considerations included in winning approval for solar projects, he said.
NIMBY
Representatives from two solar developers related new “not in my backyard” (NIMBY) issues their companies are encountering.
Jessica Robertson, director of policy and business development for Borrego Solar Systems, addressed resistance her company has encountered in Massachusetts.
“Massachusetts has the classic New England problem of really small parcels and small municipalities. They all have different zoning regulations and permitting processes and so that is definitely a challenge. But we also have rampant NIMBY-ism from people who are accustomed to their view being a certain way and they don’t want that to change,” Robertson said.
“And then we also have a very organized conservation movement, which normally I am fully on board with and really want to partner with in many, many ways. But there’s sometimes a really black-and-white view of land use, and the idea of cutting down a single tree in order for solar [development] becomes a nonstarter,” she said.
Robertson said a new state distributed generation incentive program that factors current land use when calculating a state incentive for a particular project has made solar development much more difficult if not impossible. “I think there’s a need to have a little bit more of a nuanced conversation about costs and benefits,” she concluded.
From a social justice point of view, Robertson reasoned that renewable energy has flipped the scenario from the past when power plants were built in regions distant from neighborhoods where the power would be used.
“I think we need to be upfront about that conversation and acknowledge that certain communities have really borne the brunt of our energy system for a really long time, and it’s time to spread that burden around a little bit more broadly and at the same time recognize that it’s a very different burden and shouldn’t hopefully be quite so big a deal as trying to locate a new coal plant,” she said.
Tyler Kanczuzewski, vice president of sustainability and marketing with Ind.-based Inovateus Solar, said NIMBY-ism and concerns about losing farmland are issues he encounters.
Regarding the first issue, Kanczuzewski said he has encountered rural residents who are accustomed to looking out at farmland with a first cup of coffee and just “don’t want to stare at a big solar array.” That issue is stronger for them than switching some land from farming crops to solar, he said. But there are real concerns among others about losing farmland.
“I think there is a little bit of uncertainty with some of the farm communities. They’re potentially losing potential crops to solar. They’re farming solar renewable energy instead of crops, and as you can tell, a lot of them are interested, but they’re a little bit insecure about the future.
“But the good thing is that we’re learning that you can do things like [include a] pollinator habitat with the solar arrays and actually improve the soil health,” he said, in reference to planting regional wildflowers and in some cases regional grasses for sheep to graze in between the rows of solar arrays.
The plantings “help with water management, become a habitat for birds, bees and other species, and improve the soil health. And let’s say 20 or 25 years down the road when you decommission that solar array, you can actually have better soil there and you can farm on it again.
Kanczuzewski said the pollinator habitat movement is “gaining traction” in the Midwest, and particularly in Randolph County, Ind., where Inovateus is based.
“The county did a solar energy ordinance that includes pollinator friendly provision, so that was exciting for the state of Indiana, and more counties are doing that, I think, across the Midwest,” he said.
Who Benefits?
Colette Pichon Battle, founder and executive director of the Gulf Coast Center for Law & Policy, addressed environmental, equity and social justice involved when solar developers arrive in a neighborhood or region.
Battle said the development and siting of any industrial project, including a large solar project, comes down to democracy itself.
The idea of “some people having more gravity and value than others in these decisions is really a question about our democracy,” she said. “We have many processes that are supposed to be rooted in democracy that [instead] are leaning toward those who have privilege and access and the ability to challenge power.”
Regarding brownfield sites and environmental justice spaces, Battle noted, “We have to be careful that finding the cheapest, most available land does not give to black and brown and poor communities what privileged … communities don’t want.
“The truth is that these things benefit everybody, including the planet, so we need to scale this renewable energy up. For that reason, not because those victims over there really need our help. But because the planet is in trouble and we need to shift our entire infrastructure,” she said.
Battle said she agreed with Robertson’s notion of having “nuanced” conversations, “We have to have those kinds of conversations, and we have to shift this narrative around who’s benefiting.”
“I think the narrative of the benefit has to be a much more collective one around what the transformation required to address this climate crisis is really calling all of us to do and to bear equally as much as possible.”
