NYISO’s proposed dynamic reserve requirements could result in significant changes in transmission flows and reduced costs, according to the findings that FTI Consulting presented to the NYISO Installed Capacity Working Group (ICAPWG) last week.
FTI’s Scott Harvey described how each element of the dynamic reserve design, first published in a white paper in December 2021, could result in reduced costs of meeting load, while maintaining reliability and meeting reserve targets.
The ISO’s project was conducted to see if dynamically scheduling reserve requirements or procurements for generators could support New York’s Climate Leadership and Community Protection Act (CLCPA) by allowing more economic clean energy to be imported into the state, which would better align market outcomes with system operations. (See NYISO Exploring Dynamic Reserves.)
Summary of FTI Consulting examination of new dynamic reserve project | FTI Consulting
NYISO’s existing operating reserve requirements are static; the white paper argued that a dynamic approach would “allow for appropriate reserves to be procured to cover the largest contingency,” while also allowing “for more reserves to be scheduled in cost-effective areas to meet the reliability needs,” which has become increasingly important as more intermittent generators are installed.
FTI’s study highlighted how dynamic reserve requirements can save money by replacing imported megawatts during periods of constraint with those directly from generators in load pockets.
Mark Younger, president of Hudson Energy Economics, commented how the proposal “is a pretty significant change from how things are currently done,” as it would “make contingency based on the actual loading of the unit rather than its capacity,” which he believes the ISO should make “very clear to stakeholders.”
FTI plans to return later in the year to share more examples of how dynamic reserve requirements will impact the system, including instances where intermittent resources are in load pockets.
Tariff Revisions on CRIS
NYISO also continues to work on proposed tariff revisions that would modify its rules for deactivated facilities with unexpired capacity resource interconnection service (CRIS).
The ISO’s Juan Sanchez told the ICAPWG that stakeholder feedback received on the tariff revisions discussed at previous meetings were mostly requesting additional “clarification around the rules.” The project is investigating ways to tighten the rules for CRIS retention where it is not fully utilized, while also increasing capacity deliverability headroom and potentially lowering the cost of market entry for future facilities. (See NYISO Proposes Changes to CRIS.)
Summary of proposed tariff revisions for the CRIS expiration evaluation project | NYISO
NYISO wants to modify the rules and processes for deactivated facilities with unexpired CRIS by allowing them to voluntarily relinquish their full CRIS at any point in time simply by notifying the ISO. It would develop a standardized notification form, which, once received, would prompt it to stop including the facilities in future deliverability studies.
The revisions would also expire partial CRIS rights for transmission facilities limited from using their full CRIS because of physical limitations in neighboring control area systems. This provision would apply to transmission facilities that are not meeting ISO procedures because their net megawatt output is not reaching full capability, reducing their CRIS to the maximum monthly amount of energy demonstrated during a consecutive three-year period starting from initial synchronization.
They would also allow for same-location CRIS transfers to have the same flexibility as those between different locations. Units in the process of shutting down, or mothballing, would be allowed to transfer part or all their CRIS to a same-location facility even while the unit is deactivating.
Doreen Saia of Greenberg Traurig raised the point that the revisions need to take physical withholding rules into account because there will be facilities “not necessarily retiring until some future point” but are remaining on the grid for the near future and requesting CRIS transfers.
Saia argued that a challenge will emerge when the ISO “puts their marker in the sand to do a physical withholding assessment” and there will be units whose reliability status is unclear but are requesting an “ex ante determination,” making forecasts unclear for stakeholders.
NYISO will return to a future working group meeting to share any additional feedback it receives from stakeholders concerning the new tariff language. It asks that all comments be emailed to Sanchez (jsanchez@nyiso.com).
The U.S. Department of Energy on Monday granted the Tennessee Valley Authority a voucher from its Gateway for Accelerated Innovation in Nuclear to study future sites for advanced nuclear reactors.
The DOE’s Office of Nuclear Energy’s announcement gives TVA access to the expertise and research resources of the Oak Ridge National Laboratory. TVA and the lab plan to find candidate sites appropriate for future nuclear reactors, using the Oak Ridge Siting Analysis for power Generation Expansion (OR-SAGE) tool to explore suitable locations.
South Carolina-based Elementl Power also received a similar voucher for siting assessment.
“As part of TVA’s ongoing exploration of advanced nuclear technology, we look forward to working with the U.S. Department of Energy Office of Nuclear Energy, Oak Ridge National Laboratory and other partners to help lead the nation toward a decarbonized future,” TVA said in an emailed statement to RTO Insider.
TVA did not elaborate beyond the DOE’s press release on potential sites or their size.
TVA has a goal to reach net-zero emissions by 2050. CEO Jeff Lyash has said decarbonization efforts will require license extensions at its three existing nuclear plants, adding small modular reactors, and considerable investments in energy storage and carbon capture and sequestration. TVA said earlier this year it will add a GE Hitachi small modular reactor by 2032 at the Clinch River Nuclear site near Oak Ridge, Tenn. (See TVA Defends Rates, CO2 Reduction Plans in House Inquiry.)
The New York State Energy Research and Development Agency (NYSERDA) last week selected six real estate partnerships to join a $50 million effort “to help advance a climate-friendly building stock” in the state.
Gov. Kathy Hochul announced the selections, saying the partnerships will improve building efficiency across New York by implementing heating and water decarbonization systems in 5.6 million square feet of existing high-rise stock, part of the $50 million Empire Building Challenge (EBC).
According to a statement, the EBC promises to “usher in a new era for high-rise buildings” by retrofitting 131 buildings that have signed up to be carbon-neutral and publishing playbooks with best practices for other building owners to replicate and retrofit the 70% of state’s buildings constructed prior to existing energy codes to low-carbon standards.
Hochul’s announcement also noted that energy startup accelerator The Clean Fight was selected as administrator for the $10 million dollar Empire Technology Prize program, which will support entrepreneurs developing technologies that disrupt the energy industry and increase the deployment of low-carbon retrofits in tall commercial or multifamily buildings.
The real estate teams were selected through a competitive solicitation that sought developers who will advance eight showcase buildings as part of the EBC.
The six partnerships chosen last week represent the second group of real estate businesses selected for the program, following a first cohort of 10 selected in April 2021 to achieve carbon neutrality in their building stock, with Vornado, Empire State Realty Trust and Rudin Management Company committing their entire portfolios to reaching neutrality.
The program has received strong support since, allowing New York to retrofit older buildings with green technologies instead of demolishing them.
Barriers and Challenges
New York has struggled to weatherize the more than 90% of buildings in the state that are expected to still be standing by 2050.
The state’s Climate Action Council (CAC) recently found that buildings are the largest source of greenhouse gas (GHG) emissions in New York, responsible for one-third of annual emissions statewide.
Furthermore, New York’s building stock tends to be inefficient.
Due to poor insulation and energy efficiency codes, buildings leak heat during winter and cold air in the summer months. It will be particularly difficult to decarbonize sectors of the built environment that are high-rises in cold climates, such those that dominate New York City’s skyline, since they both cover lots of ground and interact with extreme weather significantly more than smaller neighboring structures.
CLCPA estimations of GHG emissions by sector with buildings representing more than 25% | Climate Action Council
These challenges became clear during Superstorm Sandy in 2012, which caused approximately 35,000 housing units to lose power, heat or hot water for extended periods, if not permanently. More recently, a snowstorm in April caused power outages across the state, leaving more than 150,000 utility customers in the cold.
An analysis by rental consultancy RentHop found that the number of winter 311 heat or hot water complaints was 25.6% higher this past winter than last.
These challenges became particularly acute after the three days of heavy rain last week that exposed flaws in many New York buildings.
Specifically, the impact of the rain forced Councilwoman Julie Won from District 26 of Western Queens to join residents of Woodside Houses to demand permanent heating fixes to their development because residents immediately lost heat and hot water in the deluge and are now worried about freezing during what is expected to be a frigid winter with higher average energy costs.
The issue has become so important that Hochul has promised that New York will initiate the nation’s first gas ban in new construction by 2027, while the state Senate has gone a step further and proposed implementing the ban in 2024 for small buildings and 2027 for larger buildings.
But there are significantly fewer new buildings being constructed than the total existing stock within New York, making it critical to weatherize the millions of currently emitting buildings.
Heat Pumps a Priority
One notable method of decarbonizing the building sector would be use of retrofitted heat pumps, heating plants and connected water delivery systems.
Conventional heating and cooling systems account for 37% of energy consumption and 32% of greenhouse gases in New York, but clean heating and cooling systems — such as heat pumps — could significantly reduce the state’s carbon footprint.
Heat pumps are up to four times more efficient than conventional heating systems because they transfer heat rather than generating, making them cleaner, cheaper and healthier. More specifically, heat pumps move heat from the cool outdoors into the building during the heating season and then out of the building to the outdoors during the cooling season.
Air-source heat pumps operate via ducts that connect to an indoor unit that vents compressed outdoor air throughout the house in a controlled manner.
Ground-source — or geothermal — heat pumps extract heat from the ground or a nearby water source into the home during freezing weather through underground piping systems, then reverse the process during warmer months.
Compared to conventional systems, heat pumps have longer life expectancies, supply more consistent and steady outputs, allow for weather adaptability, can connect to intermittent or on-site storage systems, and produce fewer emissions.
New York has invested heavily in heat pumps, as seen in its NYS Clean Heat program, which emphasizes using the devices to increase building energy efficiency and reduce emissions compared with natural gas heating. State assembly members, such as Sandra Galef (D), have been hosting public meetings specifically devoted to heat pumps to promote their energy efficiency to constituents.
Despite the benefits, heat pumps suffer the disadvantage of having high upfront costs, requiring special planning permissions, and being sometimes difficult to install.
However, the CAC estimates that 1 to 2 million efficient homes will need to be electrified with heat pumps by 2030 to achieve CLCPA mandates, which does not consider taller high-rise buildings, the subject of the governor’s recent announcement.
EBC Benefits
The EBC is working to develop long-term capital plans that achieve carbon neutrality, while devising scenarios to scale the solutions within their partners’ portfolios.
A recent analysis from the Urban Green Council estimated that EBC partners could invest more than $250 million, which would bring the total funding to $300 million flowing into the energy-efficiency retrofit market, creating 2,600 high paying jobs, cutting 175,000 tons of carbon from New York’s emissions, and expanding improvements in almost 50,000 NYC buildings.
Furthermore, the CAC’s Just Transition Working Group found that the building sector will account for more than half of the jobs added in the clean energy subsectors from 2019 to 2030, and estimated that building sector employment will rise to roughly 366,000 by 2040, which would double the 2019 total workforce.
The CAC also estimated $9 billion in health benefits from energy efficiency interventions in low- and moderate-income homes, on top of the benefits from reduced fossil fuel combustion. Among those benefits is the reduction in carbon monoxide poisonings; leaking home heating systems are the primary cause of these poisonings the U.S., accounting for 1,500 emergency department visits and 160 hospitalizations in New York alone.
Potential health and cost benefits could be even more vital for disadvantaged communities, which are disproportionately affected by asthma and contain homes that may be more likely to have unvented or piloted gas stoves. The CLCPA has explicit provisions committing to target the electrification of environmental justice communities.
In an email to NetZero Insider, NYSERDA Vice President of Clean and Resilient Buildings Susanne DesRoches said “the Challenge will improve the building façades, increase ventilation, and deploy modern heating systems that will directly benefit the approximately 800 families that currently live in these showcase buildings.”
EBC partners “provide affordable housing to tens of thousands of New Yorkers, so the potential impact of carrying these lessons through their portfolios is huge,” DesRoches said. She added that, given the number of New Yorkers who live in aging structures, “each and every one of these buildings can learn from the solutions being advanced through Empire Building Challenge and, when the time is right, apply these solutions.”
Next Steps
Hochul has committed to achieving two million climate-friendly homes by 2030 and the EBC public-private partnership between NYSERDA and its real estate partners is expected to aid in that endeavor.
DesRoches said the “Empire Building Challenge is about moving from planning to action in addressing harmful emissions from the existing building stock in New York State in support of Gov. Hochul’s commitment.”
NYSERDA said its plans to release a competitive funding opportunity in which the real estate partners can submit proposals for up to $3 million for projects that showcase highly replicable approaches to decarbonize heating and hot water systems in existing buildings. Meanwhile, the first-round cohort have begun implementing their demonstration projects and are sharing updates online, while actively working to develop long-term plans for carbon reduction.
Additionally, NYSERDA said it is working with The Clean Fight to launch the Empire Technology Prize, which it views as a way to bring new technologies to market and accelerate the pace of building decarbonization.
Supply chain delays have hindered Pacific Gas and Electric’s progress replacing aged infrastructure, increasing the risk of equipment failure and wildfires, according to the independent monitor hired to keep tabs on the utility’s fire-prevention efforts.
The global pandemic’s supply chain slowdowns have hit U.S. electric utilities such as PG&E with “lengthened lead-times associated with ordering and receiving various goods,” Denver-based Filsinger Energy Partners said in its first report on the utility, issued Monday. “For example, due to the effects of global supply chain issues, lead times for certain transformers have increased from 38 weeks to approximately 38 months.”
That’s a problem because much of PG&E’s equipment has outlived its useful lifespan, it said.
Across the utility’s transmission, distribution and gas divisions, Filsinger, the independent system monitor (ISM), “has observed numerous PG&E asset ages that are significantly older than the related industry average useful life and the related PG&E average age of asset failure.”
“For example, PG&E reported having certain [substation] equipment with an average age of 60 years and an average industry service life of 40 years (i.e., 20 years older than the industry average),” it said. “Further, PG&E reported an average age of failure for this equipment as 70 years with 47% of this equipment exceeding this average age of failure.”
Two other types of assets have exceeded average service lives and industry standards by years or decades, it said.
“If only utilizing asset age to determine an asset’s useful life, PG&E would have to purchase and install over 2,000 components of the aforementioned equipment in order to bring the asset age of the equipment in these three categories down to the PG&E average age of failure for each equipment type,” it said. “A significantly higher investment would be required to get each asset category reduced to the industry average.”
Global supply chain problems, however, are delaying the utility’s equipment replacement programs.
“The emerging risk relates to the volume of assets that have the potential to fail within close time proximity to one another,” the report said.
The ISM
The California Public Utilities Commission required PG&E to pay for an ISM as a condition of approving its bankruptcy reorganization plan in May 2020. The CPUC selected Filsinger, which started work after PG&E exited probation and the oversight of a federal monitor in January. (See PG&E Ends Probation as a ‘Menace to California,’ Judge Says.)
Filsinger is expected to file reports every six months under its five-year contract. Its first report broadly cataloged the problems and progress of PG&E in trying to prevent its transmission and distribution systems from igniting more wildfires.
Catastrophic blazes blamed on PG&E equipment failures included the 2018 Camp Fire, the state’s deadliest and most destructive wildfire that began when a century-old C hook broke on a high-voltage line, causing the jumper conductor to fall onto the steel tower. The resulting electric arcs rained molten steel and aluminum, which sparked the grass and brush below.
The fire destroyed the town of Paradise in hours, killed 84 people and led to PG&E’s January 2019 bankruptcy filing and its guilty pleas in June 2020 to 84 counts of involuntary manslaughter.
State fire investigators have found that PG&E equipment caused massive and highly destructive fires in 2017, 2019, 2020 and 2021. The utility is now under investigation by the U.S. Forest Service for its possible role in igniting the Mosquito Fire, which started Sept. 6 and burned through 77,000 acres of forestland in the Sierra Nevada foothills east of Sacramento.
“The USFS has indicated to Pacific Gas and Electric [in] an initial assessment that the fire started in the area of the utility’s power line on National Forest System lands and that the USFS is performing a criminal investigation into the 2022 Mosquito fire,” PG&E told the Securities and Exchange Commission Sept. 26. Two days earlier, “the USFS [had] removed and took possession of one of the utility’s transmission poles and attached equipment,” it said.
The utility has made progress in some areas, the monitor’s report said, including its use of “enhanced powerline safety settings,” which increase fault-detection sensitivity and quickly de-energize lines that experience problems such as changes in current. The EPSS protocol also disables the automatic reclosing of circuit breakers.
PG&E said the expansion of EPSS in high-risk fire areas has greatly reduced potential ignitions from lines contacting trees and other fire dangers.
“From the implementation of EPSS in late July 2021 through October 2021, PG&E reports a 40% reduction in ignitions as compared to the past three-year average, and an 80% reduction in the CPUC-reportable ignitions as compared to the past three-year average for the same period,” the report noted.
The downside is that use of EPSS and the intentional blackouts known as public safety power shutoffs have significantly increased the number of outages and affected customers in high-threat fire areas, it said.
In a statement Monday, PG&E said “we welcome the oversight provided by the Independent Safety Monitor team. We agreed to this structure when we emerged from Chapter 11 in 2020, believing it would bring additional transparency to our critical safety work.”
The utility’s revamped “leadership team has intensified its focus on fostering an environment that encourages coworkers to raise concerns on any topic, especially around safety and risk, so that we can address things that need to be fixed or made safe,” it said. “The monitor team helps to build upon this culture and brings an enhanced level of openness and transparency to our efforts to provide safe and reliable energy in the face of evolving climate and wildfire risk.”
The company repeated its intent to underground 10,000 miles of power lines in regions at greatest risk of wildfires. The CPUC’s approval of that effort and billions of dollars in ratepayer funding remain uncertain, however.
ATLANTA — At the first day of the North American Generator Forum’s Annual Compliance Conference, held at NERC’s headquarters, NERC Vice President of Engineering and Standards Howard Gugel jokingly complained that because he worked for the ERO, most attendees probably automatically thought of him as “the standards guy.”
“Unfortunately, [for] a lot of people, when you mention the name NERC, your mind immediately goes to standards and compliance. And of course, that’s what we do,” Gugel said. “But we do things other than standards, right? We do reliability assessments. … We also monitor the bulk electric system. … And so when things occur on the system, when reliability coordinators alert us to things, we’re able to go in and look to see how things are evolving in the system and keep folks appraised of how things are evolving.”
Gugel was at the conference to discuss NERC’s response to what he called “the brave new world of resilience,” which is being brought about by the interconnected trends of “decarbonization, decentralization and digitization.”
The first of these refers to the growth of carbon-free generation sources like wind and solar, whose energy output is dependent on the weather and must be managed in a completely different way than traditional generators. Decentralization, which refers to the spread of behind-the-meter resources, is linked to the growth of rooftop solar panels, as well as battery energy storage systems. Meanwhile, digitization — the reliance on the internet to facilitate the management of these new technologies — underpins each of these developments.
A major challenge in the management of these new resources, Gugel said, is that because they do not belong to the BES, they do not actually fall under NERC’s reliability standards, even though they make up a significant fraction of the asynchronous generation on the bulk power system: 16.2% as of 2021. By comparison, only 3% of synchronous generation connected to the BES did not fall under NERC’s standards last year.
Even renewable resources that are connected to the BES pose major challenges for grid operations because of their very different behavior patterns. Gugel said that unlike inertial generators, whose output declines gradually in the event of a problem, giving operators a bit of time to respond, solar facilities in particular behave more like a “step function” with output falling right away.
“You can see 1,000 [to] 2,000 MW come off immediately, and then five minutes later when that momentary cessation is done, it all comes back at the same time. That causes the operators to really be concerned about how they control that system,” Gugel said.
The theme of digitization creates challenges related to the cutting-edge nature of many new generation resources, which means they need constant internet connectivity to monitor, troubleshoot and deliver software updates that in some cases come from their manufacturers overseas. This makes these facilities an attractive target for hackers, especially because a relatively small amount of companies are responsible for a large proportion of grid-connected hardware. If an intruder can break into one manufacturer’s systems, they could be in a position to conduct a major operation against the North American power grid.
Returning to the topic of standards, Gugel assured the audience that NERC is taking the challenge posed by the grid’s evolution seriously. The organization’s efforts range from standard development projects aimed at revising the facility interconnection requirements, to potential moves to re-evaluate the definition of the BES itself so that NERC’s standards can apply to behind-the-meter resources that they currently don’t cover.
“It’s obvious that we can’t just stay where we’re at; the status quo is just going to make us farther and farther behind [on] this reliability issue,” Gugel said. “The time to act is now, so you’ll hear more about [the] evaluation of the definition of BES and possible changes to registration criteria as we go forward.”
MISO on Monday assured stakeholders that it has the means to study the 170 GW of new generation requests that were added to its interconnection queue in September.
However, stakeholders seemed unsure whether the grid operator is up to the task, bolstered, perhaps, by Berkeley Lab’s analysis showing it’s more expensive than ever for generation to connect to the footprint’s grid.
MISO said last month it must sort through a record 171 GW of proposed generation projects across 956 interconnect requests for the 2022 cycle. The requests could bring the queue to the brink of 300 GW, triple what was there just two years ago. (See MISO: Record 1,000 Interconnection Requests in 2022.)
Phil Van Schaack, manager of resource utilization, said the 2022 cycle almost doubled the requests received in 2021.
“MISO saw nearly 100% growth year over year,” Schaack said during Mondays’ Interconnection Process Working Group (IPWG) teleconference. He said the megawatt value of this year’s queue entrants is “greater than all the installed capacity in the MISO commercial model.”
Van Schaack said solar generation is dominating the queue and a record number of requests came from first-time developers in MISO. If all the interconnection requests are realized, the queue would be composed of more than 95% renewable and storage resources.
“Not all of these projects will make it to the end, but still, record setting-numbers,” he said. “We appreciate everyone working with us as we work through these requests.”
Staff is reviewing the projects to validate whether they have secured site control, Van Shaack said.
Invenergy’s Arash Ghodsian asked whether there’s a plan to handle the technical challenges in studying the huge volume of requests. “Will MISO be able to solve the models with the magnitude of generation in the queue?” he asked.
WEC Energy Group’s Chris Plante suggested the RTO might need to change its study strategies, given the generation additions.
Van Shaack said staff is prepared to solve models with the best available information and bring on additional people to help, if necessary.
“We’re going to do our best to meet the timeline,” he said. “The need to scale and augment the internal process is ongoing … We do anticipate being able to handle this.”
NextEra Energy’s Aaron Bloom asked whether MISO plans to revisit its three 20-year futures used for transmission planning in light of the generation plans. Staff responded they will internally discuss refreshing the futures’ assumptions.
Stakeholders also requested MISO lead workshops for updates on the queue.
Stakeholders Ask About Odds of IC Agreements
As MISO normally sees about 80% of interconnection requests withdrawn from the queue, stakeholders asked whether staff expects a similar result with the 2022 round.
“We don’t know what the dropout rate is going to be. Historically, the number has been a 20% success rate. But two big things happened that drove the numbers we saw,” Andy Witmeier, director of resource utilization said, pointing to the Inflation Reduction Act’s renewable energy tax credits and the 18 new 345-kV lines from MISO’s long-range transmission plan (LRTP).
The grid operator’s board of directors approved a $10 billion LRTP portfolio of projects in MISO Midwest this summer, partly to integrate more renewable energy. It also intends to stand up $1 billion in projects on its western seam through its Joint Targeted Interconnection Queue study with SPP.
“Those could affect the dropout … But this is still a historic amount of generation,” Witmeier said. “You could see a lot of upgrades coming out of these. First off, there’s just not enough people to buy this capacity.”
Van Schaack said staff could still find prohibitively expensive network upgrade assignments among the latest generation hopefuls.
“That economic trend has definitely continued into 2022,” he said, referencing projects from earlier queue cycles that were unviable because they were paired with pricey upgrades.
Berkeley Lab Focuses on Snowballing Upgrade Costs
Lawrence Berkeley National Laboratory observed last week that MISO’s interconnection environment has led to “rapidly growing” interconnection costs over the past four years.
The national laboratory said in an Oct. 7 study that RTO’s average network upgrade cost of $102/kW for recently completed projects is nearly double that of historical costs from 2000 through 2018. The lab also said that projects still actively moving through the queue faced estimated interconnection costs that have tripled in just four years to about $156/kW.
The cost analysis was funded in part through the U.S. Department of Energy’s Interconnection Innovation e-Xchange.
“The capacity associated with [new] requests is more than twice as large as MISO’s peak load in recent years — about 120 GW — and, if substantial amounts are built, will likely exert competitive pressure on existing generation,” Berkeley said. “However, most projects have historically withdrawn their applications, often in response to high interconnection costs: only 24% of all projects requesting interconnection between 2000 and 2016 have ultimately achieved commercial operation at the end of 2021.”
The lab said 366 GW of projects have left the queue, while just 62 GW have been interconnected. It said the most recently withdrawn interconnection requests confronted the highest average upgrade costs of about $452/kW.
Berkeley also said that the potential interconnection costs on recent submittals for storage, wind and solar generation are more expensive than for natural gas-fired generation. It found that wind generation has $399/kW in network upgrade costs, storage $248/kW and solar $209/kW; natural gas is expected to pay a more modest $108/kW.
MISO Adamant on Narrower DFAX Cutoff
MISO still plans to reduce congestion by instituting a lower system-impact threshold on interconnecting generation that will likely prompt more network upgrades.
The RTO’s proposal might dim the prospects for some of the new interconnection requests.
The RTO suggested this summer to halve new generation’s allotted distribution factor (DFAX) impact on transmission from 20% to 10% for its basic and unguaranteed level of interconnection service, called energy resource interconnection service (ERIS). (See MISO Recommends Lower Distribution Factor to Address Congestion.)
At the behest of some MISO South members, the grid operator studied a DFAX limit down to 5% but decided that the threshold would be too drastic. Staff said 10% provides a good balance without being too aggressive.
Generation developers maintain that a tighter DFAX threshold would be punitive and place even more responsibility for system planning on interconnection customers, who are trying to get sorely needed generation on the system.
Sustainable FERC Project’s Lauren Azar said during the IPWG’s Monday meeting that lowering the threshold will “exacerbate and result in more transfer of costs to generators.”
Some stakeholders argued that MISO was conflating transmission reliability with real-time congestion costs.
“Interconnection is about reliability and not addressing congestion. What’s resulting is congestion in real-time, which is an economic issue. ERIS generators are energy-only and should expect to be curtailed,” Clean Grid Alliance’s Natalie McIntire argued.
Staff contended that the binding constraints interconnections cause are a reliability issue. They said potential constraints are currently being ignored in the interconnection process, only to crop up later on the system.
Stakeholders said that it’s premature to lower the DFAX threshold across the board when MISO hasn’t yet put together an LRTP portfolio for its southern region. The current and upcoming LRTP portfolios are marketed as being able to support more generation interconnections on the grid.
The Texas Public Commission honored interim ERCOT CEO Brad Jones’ tenure last week, showering him with praise, political recognition, the Lone Star Flag that flew over the State Capitol in his honor and his second standing ovation of the week.
“I cannot, on behalf of all the people of this agency, ERCOT and the state of Texas, thank you enough for being willing to step up and take what has to be one of the toughest jobs in the state in a time of true crisis,” PUC Chair Peter Lake said during the commission’s Oct. 6 open meeting.
Jones was pulled out of retirement to lead ERCOT on an interim basis two months after the February 2021 winter storm that brought the Texas grid within minutes of a total collapse. The PUC first asked him to serve in a consulting role before he was asked to replace Bill Magness, who was fired in the storm’s wake. (See ERCOT Board Chooses Jones as Interim CEO.)
What Jones hoped would only take a few months lasted more than a year before ERCOT’s Board of Directors found a permanent CEO in Pablo Vegas. In the meantime, Jones focused on improving the grid operator’s credibility. He guided ERCOT through two summers dotted with conservation measures — setting a new record demand peak of 79.8 GW last July — and ensured staff implemented winterization measures to reduce the chances of another disaster.
“It was a very tough, tough spot to be in. You handled it confidently with poise and composure,” Lake said. “A lot of tough decisions, a lot of first-time moves, unprecedented actions and then getting through this record-breaking summer. So, thank you again for not only being willing to do the job, but doing it so well under such extraordinarily tough circumstances. You got a big retirement smile on your face, and you’ve earned it”
Commissioner Will McAdams recalled that Jones only requested $1 for his salary when he was asked to take over at ERCOT.
“I think you were willing to do it for free, but we wouldn’t let you, and there was nobody else around that would step up to take such a very extraordinary difficult position,” said Commissioner Lori Cobos, who sat on the board at the time.
“In my mind, there was only one person that was capable of coming in and helping,” Commissioner Jimmy Glotfelty told Jones, who spent more than 30 years in the sector, including a stint as ERCOT’s COO. “I’m sure everybody who’s been around this town for a long time, who’s been in the power sector and coming to the PUC, said, ‘Brad Jones has to step up and do this.’ It was a daunting task, but it comes pretty naturally to you. You know this system frontwards and backwards, and I think all Texans have benefited from your knowledge.”
Brad Jones recognizes ERCOT, PUC staffs before the commission. | Admin Monitor
Jones thanked the commissioners for their comments, saying the PUC was “extraordinary” during the last year and a half, providing leadership and support to he and ERCOT.
“I wanted to make sure that you all knew what each of you meant to us, the collaborative nature, the conversations that we’ve had about numerous topics. It’s been helpful to us in setting our targets, but it’s also been helpful in having your support and driving some of this change in the last year and a half,” Jones said.
“And when I say the commission, I don’t want to leave out the staff,” he said. “I’ve watched the staff work extraordinarily hard over the last year and a half to make very quick changes on pathways that we’d never used before to get reliability in place quickly and to do that in a way that had not been done ever before. The staff has been fantastic with us and working closely with us.”
Jones also thanked the State Legislature for the laws passed after the winter storm and Gov. Greg Abbott for his support. In turn, Jones was presented with resolutions from both houses of the legislature and a statement of recognition from Abbott.
Finally, McAdams pushed Jones on his immediate plans after he winds up a transition period with Vegas on Oct. 31.
“He is going on a vacation, and he needs to say that publicly,” McAdams said.
“Yeah, now that I’m finished at ERCOT, I’m going to Disney World. …
“All I can say is, ‘Wow, what a time to be coming back into Texas,’ with what’s going on in the market and what’s going on in the economy. I can’t remember a more exciting time to be in this industry,” he said.
Sierra Club Efficiency Petition Rejected
In business matters, the PUC rejected the Sierra Club’s petition for a rulemaking related to energy efficiency (53971).
The commission said Sierra’s proposal would significantly change peak demand reduction and energy efficiency goals, increase cost caps for consumers and utility investment in low-income programs, adjust performance bonuses, and remove barriers to program disclosure.
However, it also said there is no room on its current rulemaking calendar to accommodate the environmental organization’s proposal.
Lake has tasked Commissioner Kathleen Jackson with directing the PUC’s energy-efficiency efforts. A workshop has been scheduled for Oct. 18 to discuss an implementation plan.
NYISO stakeholders on Friday responded negatively to the ISO’s proposal for a 10-kW minimum capability requirement for individual distributed energy resources to qualify for participation in an aggregation.
Although most proposals discussed at the Installed Capacity Working Group (ICAPWG) meeting did not elicit reactions from stakeholders, NYISO’s 10-kW DER minimum requirement proposal generated significant pushback.
The ISO argued that the proposal would help DER market implementation, save staff time reviewing aggregations for interconnection and enable it to fully integrate new software and internal procedures to comply with FERC Order 2222. (See NYISO Proposes 10-kW Min. Capability Req for DERs in Aggregations)
Stakeholders, however, took exception to the ISO’s language that they would “explore” lowering the minimum capability requirements later after getting experience and a better understanding of DER penetration versus directly promising to lower the minimum capability later.
Chris Hall, of the New York State Energy Research and Development. Authority, summarized the main concern, arguing that, with average size of residential storage resources at 7 kW, the “provision essentially eliminates all of these residential assets from participating.” Though NYSERDA is “sympathetic to the ISO’s limitations,” it is “deeply troubled by this proposal,” he said.
Adam Evans of the New York Department of State agreed with Hall’s assessment, stating that “folks at the DPS who are close to these types of resources have been hearing that this proposal would pretty much eliminate residential participation.” NYISO’s intention should be to “get more resources to participate” and that putting “a barrier right from the get-go” was inadvisable, he said.
David Skillman of Sunnova Energy echoed these complaints, saying how his company’s fleet consists of resources between 6 and 8 kW, meaning they would not be able to participate in aggregation. That, he said, “flies in the face of FERC 2222,” which was established to “give the small guys a chance to play on the same field as the big guys.”
Aaron Breidenbaugh of CPower shared how recent conversations he had at the Advanced Energy Management Alliance indicated that there was “pretty significant concern about the potential disenfranchisement of an entire customer class” and suggested that NYISO change the language of “explore.”
Other tariff revisions or modifications were collectively proposed to clarify existing rules and processes.
These included making no aggregation types eligible for the NYISO Station Power program, accommodating retail charging rates for aggregations and clarifying several rules in the ISO’s Market Administration and Control Area Services tariff.
The ISO intends to return to an upcoming ICAPWG meeting to further review the draft language and then expects to seek approval from Business Issues Committee and Management Committee later this year. It would then file the proposals with FERC for an anticipated implementation in 2023.
Also during Friday’s ICAPWG meeting, NYISO Principal Economist Nicole Bouchez presented the results of a study examining the differences in expected ramp-up and ramp-down rates as the grid undergoes rapid transition, the impact of seasonality impacts and the rate of growth as more intermittent resources are added.
The ISO examined two policy cases listed in the outlook for the years 2030 and 2040, calculating their ramp rates, average number of ramp hours per event and hourly percentiles to better show distribution of the rates.
Bouchez pointed out that initial findings “qualified as having no real observable trend” in the number of hours ramped over time, and that if anything, one could “posit that ramp-down events are a little bit longer, but even that is difficult to say.”
However, when NYISO examined how many megawatts there are in those ramp periods, it found that the ramp rates were “amplified” in magnitude over time as “more and more installed capacity of renewable resources” were added.
More important, Bouchez said, the ISO found that although ramp events are normally distributed over time, the average ramp megawatt is impacted across the seasons.
For Case 1 there were less ramp up and down needs in the shoulder seasons. Case 2 had more ramp needs in the winter, while both the summer and shoulders were similar.
Bouchez stated that the findings will be included in a white paper that the ISO expects to present in draft form either in late October or early November, after which there will be a stakeholder comment period of three to four weeks. She also said that any related market changes or additions will be studied in next year’s Balancing Intermittency Project, which will use the data presented at Friday’s meeting for structure.
Transmission owners found themselves on the defensive throughout Thursday’s FERC technical conference on transmission planning and cost management, as panelists decried the rising spending on end-of-life and other local projects that do not face any prudency reviews.
Kamran Ali, vice president of transmission planning and analysis at American Electric Power (NYSE:AEP), pushed back against the criticism, saying PJM’s Attachment M-3 process, which governs planning of supplemental projects — those not needed for system reliability or public policy compliance — is “the gold standard” for transparency.
Lisa McAlister, American Municipal Power | FERC
“I can say that because I manage the transmission planning for AEP in four different RTOs,” Ali said. “I think it would be beneficial if people were to bring actual factual examples to the table: ‘In the M-3 process, here are the regional projects that would have displaced local projects, or here are the local investments that were not prudent, that were not rationalized that somehow made it through.’ If we have some of those real examples, I think we can enhance the M-3 process. Without examples I think it’s very difficult to make any improvements.”
PJM evaluates supplemental projects only to make sure they do not harm reliability. Municipal stakeholders have long complained about the lack of transparency surrounding their costs. (See PJM TOs Sign off on Supplemental Project Deal.)
Lisa McAlister, general counsel for regulatory affairs for American Municipal Power, responded that the reason that there are no examples is “because we simply don’t have enough information to identify” any. She said AEP does “a better job” than other PJM TOs in providing information, but “what we don’t have is how those replacements are prioritized; we don’t know [how] replacement versus maintenance decisions [are made]; how assets rank compared to other assets on the system.”
‘Appearance of Transparency’
“AEP has done a very good job in the M-3 process of responding to a limited number of suggestions,” agreed Kentucky Public Service Commission Chair Kent Chandler. “I have a certain number of questions, and [there] are now stock answers that they’re ready to provide people. … The reality is that although I understand what their criteria is … I have no idea what weight they’re giving” to them.
Kentucky Public Service Commission Chair Kent Chandler | FERC
“The M-3 process gives us far more insight into local planning than the non-RTO utilities that we have, and even the MISO utility that we have,” Chandler added. “We understand through the M-3 process what their assumptions are and the criteria maybe, but there’s no way that we’re provided enough information to be able to replicate the decisions that are made by the utilities. So we understand that they may be looking at asset conditions, [but] we have no idea what kind of weight they’re giving them; whether they’re prioritizing certain conditions over others. It’s the appearance of transparency, and it’s enough to maybe placate some folks … but it is not enough to have an appreciation for how they’re actually doing local planning.”
But that’s still far more than what the PSC gets from its non-RTO utilities, he said. “We don’t find out what their planning outputs are until they show up to the commission for a certificate of public convenience and necessity, or it’s a fairly small transmission project and we don’t see until they file a rate case and it shows up in their forecasted test period. … We have no insight into their local planning.”
McAlister said RTOs should do more rigorous analyses of local planning criteria and proposed projects. But “to really have a meaningful opportunity to have a back-and-forth, you need more than the ability to submit comments,” she said. “There has to be some kind of actual requirement that the transmission owners respond.”
Greg Poulos, Consumer Advocates of PJM States (CAPS) | FERC
She said PJM created a website for members to submit questions, but the RTO usually just says, “we’re working with the transmission owners; we’ll get back to you.” She said mirroring the M-3 process in other regions, “just having an arbitrary set of meetings and days to comment, we don’t think is something that gets us there.”
Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), said in-house experts can only do so much.
“We have the money to hire an expert. I just don’t know what our expert would do with only 10 days to review projects, no ability to ask the questions and no expectation that they’re going to respond to us,” he said.
“Those are things you would hear from … an independent transmission monitor: ‘Those are flaws in this process. There’s a significant gap here [and] PJM, you need to do something about that.’ It’s different from me saying that, because I’m not getting response to that.”
Kenneth Seiler, PJM’s vice president of planning, said the RTO has not pursued more regional projects because the RTO is not seeing high load growth except in some areas such as Northern Virginia, which has experienced an explosion of data center load. (See PJM Sees Additional $603M ‘Data Center Alley’ Tx Spend.)
Kenneth Seiler, PJM | FERC
“We look for opportunities for regional transmission, but in many cases, it’s not the most cost-effective solution,” Seiler said. “We have had occasions in the past, though, where we had identified regional solutions [and] we could not get the line sited. The one example I can think of off the top of my head was about a $100 million regional transmission facility … The [state] commission wouldn’t site it within that particular state. And we ended up spending over double — over $200 million for sub-transmission upgrades.”
Erik Heinle, of the D.C. Office of the People’s Counsel, said PJM’s expertise in engineering and power flow analysis is “world class.”
“But we see far too many instances where PJM is not acting as the regional planner and bringing regional projects to the region,” he said.
Existing Cost Containment Practices
FERC Commissioner Willie Phillips expressed interest in MISO’s variance analysis, in which the RTO reevaluates projects facing lengthy schedule overruns or a 25% cost increase. MISO can either let projects continue, cancel them or assign them to different developers. Jeanna Furnish, MISO’s director of expansion planning, said the variance analysis could be applied in other regions to scrutinize projects.
FERC Commissioner Willie Phillips | FERC
SPP Executive Vice President of Regulatory Policy Paul Suskie said that, more than a decade ago, SPP’s first regionally funded 345-kV line turned out to be significantly more expensive than its original estimate, causing the RTO’s Regional State Committee to call for a review and develop methods to contain costs. Since then, Suskie said, SPP has been tracking project costs in an evolving process. He said projects that exceed 20% of their original costs are subject to restudy, suspension and even cancellation.
FERC Chair Richard Glick asked transmission owners how they currently reduce cost exposure for customers on large, regional transmission projects.
Carolyn Cowan Barbash, vice president of transmission development and policy for NV Energy, said her company tries to write projects’ technical specifications as clearly as possible and makes sure it attracts multiple bidders on solicitations.
Ameren Transmission Company (NYSE:AEE) President Shawn Schukar said his utility considers how large projects will impact future projects and vets contractors for past performance in addition to their cost estimates. He also said Ameren considers the quality of transmission components and how often they might need maintenance and replacement. He said he “took exception” to the perception that transmission owners aren’t currently motivated to keep costs in check.
‘Cooking the Books’
Attorney Lauren Azar, a former Wisconsin regulator, said FERC should create a process for challenging local planning criteria (LPC), saying “a few bad apples” in MISO have overly restrictive criteria for the generation interconnection process.
“Even before any new generation is added into the models, upgrades are already required, because of the LPCs. So in other words, the TOs are cooking the books so that those generators are required to pay for those upgrades, even before their proposed generation is added,” she said. “That’s not OK.”
Grid-enhancing Technologies
Panelists also weighed in on the role of grid-enhancing technologies as a way to cut costs.
PJM’s Seiler said the industry could benefit from a guide identifying where grid-enhancing technologies “would have the biggest bang for the buck.”
Erik Heinle, D.C. Office of the People’s Counsel | FERC
“There’s a lot of reluctance on behalf of our asset-owning utilities to apply grid-enhancing technologies, frankly, because of things like the reliability of the internet, security of [the technologies and creating an] additional avenue by which we could be attacked from a cybersecurity view.
“And these things have to be reliable. From a pure planning viewpoint, in my mind, there’s very few grid-enhancing technologies that can be relied upon on a day-in, day-out basis where I know I can count on having that extra transmission capability.
“Things like dynamic line ratings can be applied on the physical transmission line to squeeze out a few more megawatts from a pure system operations view. From a planning view, I can’t count on” them, he said.
Heinle disagreed, saying GETs should be part of regional planning. Distributed energy resources “served as a valuable planning tool in California a few weeks ago. And when you hear comments like, ‘Well, we can’t always count on this or that’ — those were similar comments that we heard about solar [and] wind, not too long ago. We found ways to incorporate them into the grid, and to use them in our planning for resource adequacy.”
Glick asked consumer advocates if grid planners give sufficient consideration to alternatives when local transmission projects are proposed.
CAPS’ Poulos said there is not: “The transmission owners in the [PJM] region say, ‘We have control of whether we’re going to do grid-enhancing technology. You have no input on this.’”
Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR
VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a PJMeffort to prohibit critical gas infrastructure from participating in demand response programs that could jeopardize the reliability of gas-fired generators. The endorsed language revises sections of manuals 11 and 18 to add language excluding “critical gas infrastructure” from being eligible as price responsive demand programs.
The changes are being considered as NERC and FERC work on their own efforts to address concerns raised by the impact of February 2021’s winter storm — that a spike in load could lead to gas infrastructure being curtailed and causing a cascading failure as downstream gas generators have their fuel interrupted. The PJM language would stand until the federal regulatory bodies finalize their own standards. (See “Critical Gas Infrastructure Approved,” PJM MIC Briefs: March 9, 2022.)
Much of the lengthy discussion on the topic focused on how PJM is considering defining critical gas infrastructure in its tariff: “as electric loads, which if curtailed, will significantly impact the delivery of natural gas to bulk-power system natural gas-fired generation.” The tariff language is not part of the package endorsed Thursday and is still being fine-tuned by PJM staff with input from Thursday’s meeting.
At issue was the definition of “significant impact.” Calpine’s David “Scarp” Scarpignato questioned how PJM would classify a curtailment causing a drop in pipeline pressure causing a downstream gas plant to run at less than full capacity, or a curtailment that doesn’t cause a direct drop in a plant’s ability to generate but has that effect when combined with other contingencies.
“A significant impact is a difficult measure. That’s going to be difficult to implement those rules. … I wonder if we can substitute ‘direct’ for ‘significant,’” he said.
Joe Bowring, PJM’s independent market monitor, said he believes the language is “fuzzy” and therefore not enforceable. He also questioned whether there’s a risk of gas infrastructure being enrolled in DR programs this winter (2022/23) as PJM considers the revisions, which will not be applied until the winter of 2023/24. Bowring also questioned why PJM has not done its own assessment of the facilities rather than relying on the sellers of demand response for the information.
PJM’s Peter Langbein said curtailment service providers have told staff that there are not currently any gas infrastructure facilities enrolled in their programs that would meet the general definition under consideration.
Paul Sotkiewicz, of E-Cubed Policy Associates representing J Power USA, said he’d prefer to see an explicit prohibition against electric-driven gas compression stations participating in DR in any form.
“We’re setting ourselves up for a cascading failure without addressing compression,” he said.
Elimination of ‘CT Rule’ Receives Endorsement
Stakeholders also endorsed manual revisions being sought by PJM to eliminate the “CT Rule,” which grants combustion turbines an exception from rules requiring that generators follow dispatch signals. Currently CTs can recover the costs of their full generation regardless of their load signal, while other generators receive the lesser of their actual generator or their dispatch.
PJM’s Lisa Morelli, director of market settlements initiatives, said the rule is a holdover from when CTs put out a fairly constant rate of power. Now that they have a wider dispatchable range, it makes sense to require them to conform to dispatch, she said. The elimination of the exception can be made by removing a single line in Manual 28.
“CTs will now be treated as all other resources in balancing of operating reserve credits,” she said.
During the Sept. 21 Markets and Reliability Committee meeting, Morelli said simulations show that uplift payments to CTs were about $1.3 million lower when recalculated without the exception over the eight highest CT uplift days in summer 2021, a 10% drop. (See: “PJM Staff Seek Removal of CT Exception on Load Signaling,” PJM MRC/MC Briefs: Sept. 21, 2022.)
Impact of State and Local Regulations on Net CONE Discussed
PJM staff provided a first read on an issue charge and problem statement exploring how local considerations, such as state and local regulations, might affect the development of the net cost of new entry (CONE). The topic will return to the MIC for possible endorsement at its next meeting.
James Wilson, a consultant to state consumer advocates, recommended broadening the issue charge and potential solutions to include other possible changes beyond net CONE, such as to the shape of the variable resource requirement curve.
Gary Helm of PJM said the RTO’s intent was to stick with addressing CONE and net CONE, as opposed to weighing the outcomes.
Four-year Review of Default CONE and ACR Underway
PJM’s Skyler Marzewski and consultants from The Brattle Group presented an overview of the first four-year review of the default CONE and avoidable cost rates and the timeline for drafting the new values.
PJM’s tariff requires the RTO to update default gross CONE and default gross ACR values for minimum offer price rule purposes every four delivery years beginning with 2022/23.
The methodology would use public national sources for the installed capital costs and fixed operating and maintenance costs, as well as using the same financial assumptions as in the quadrennial review.
“It will be a very similar process to what we did last time,” Marzewski said.
Stakeholders questioned if there’s sufficient geographic variability to justify using data specific to the PJM region, instead of national data. Marzewski said this was explored; however, it was found that there’s limited local data available. The largest variations in the cost of development tend to be the size and configuration of generators, according to Brattle’s presentation.
Default values for offshore wind were not explored in the analysis thus far as the focus was on existing generation. Instead, unit-specific analysis would be undertaken for OSW, as well as other generators with highly variable costs.
PJM Reviews Proposed VOM Language
PJM staff reviewed a set of proposed manual revisions that would codify a PJM package creating standardized variable operating and maintenance costs. The RTO’s package was the preferred solution coming out of the MIC’s Sept. 7 meeting, receiving more than 70% support over a competing package from Constellation Energy, which received 54%. (See “Two Alternatives on VOM Advance to MRC,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)
Constellation’s Jason Barker questioned PJM’s classification of nuclear major maintenance costs as variable costs that are directly related to electric production based on starts and run hours and thus must be reflected in a unit cost-based offer, rather than in a capacity market offer. Barker said there is an apparent contradiction in PJM’s proposed Operating Agreement and manual provisions that define nuclear refueling and other major maintenance projects as “variable” while also excluding time-based or preventative maintenance from classification as a variable cost. Barker said that Constellation and other nuclear operators consider costs incurred during planned nuclear outages as “fixed” costs. He also highlighted that all nuclear planned outages are scheduled years in advances, suggesting that projects undertaken during those outages are time-based. The company’s package would exclude nuclear planned outage costs from PJM’s definition of major maintenance.
The manual changes will go to the MRC on Oct. 24 for a first read with a vote anticipated on Nov. 16.
Other MIC Topics
A first read was presented on a proposal to merge the DER & Inverter-Based Resources Subcommittee and Demand Response Subcommittee into a new subcommittee, given the similarity of the subjects they cover and the composition of their stakeholder participation. PJM staff said doing so would simplify scheduling internally and for stakeholders, although there were some concerns that doing so could conflate their charges and the issues they aim to address.
PJM’s Andrew Levitt gave a first read of a proposal to expand the RTO’s current hybrid resource provisions to include installations with multiple types of generation paired with storage. The current hybrid definition allows for only one type of generation, for example solar paired with storage, while the Hybrid Resources Phase II solution would allow for “any number of different types of [generation].” The proposal would also create a detailed energy market model for inverter-based resources paired with storage, such as wind and solar combinations.
PJM provided an explanation on the impact of negative day-ahead and real-time LMPs in the calculation of the balancing operating reserve credits. Negative DA or RT LMPs can result in unnecessary BOR credits caused by the treatment of day-ahead or balancing revenues, the RTO says. PJM plans to present potential solutions during future special sessions.
Summary of FTI Consulting examination of new dynamic reserve project | FTI Consulting
Summary of proposed tariff revisions for the CRIS expiration evaluation project | NYISO
