VALLEY FORGE, Pa. — An unprecedented spell of hot weather across PJM earlier this month left stakeholders questioning whether the RTO’s operational decisions produced the unusual price signals some generators witnessed while complying with emergency load management instructions.
Rebecca Carroll, PJM’s director of dispatch, told the Operating Committee on Tuesday that an underestimated load forecast for Oct. 1, combined with typical maintenance schedules and unexpected line losses, triggered the RTO’s first ever generator-involved performance assessment interval (PAI) the following day.
Members, however, wondered aloud whether decisions PJM made before calling upon 725 MW of demand response contributed to unstable LMPs that, at times, dropped well below $0 and contradicted dispatch instructions during the event.
The trouble began on Oct. 1 when PJM’s peak load exceeded its forecast by 5,500 MW, knocking the RTO into a spinning reserves event and triggering shortage pricing for three five-minute intervals. Carroll said PJM also called upon 800 MW of shared reserves from the Northeast Power Coordinating Council to compensate.
PJM’s load on Oct. 1, 2019 | PJM
Carroll said that on the following morning, the load was tracking well with forecasts — until a 765-kV line in the American Electric Power zone failed and 2,000 MW of generation called upon the day before failed to start. Those losses, in combination with a peak load forecast of 131,000 MW and anticipated congestion over the Hyatt transformer and the Peach Bottom-Conastone 500-kV line, prompted staff to call up 725 MW of long-lead DR resources for a pre-emergency load management event. The decision triggered a PAI that lasted from 2 p.m. until approximately 4 p.m. in the AEP, Dominion Energy, Pepco and Baltimore Gas and Electric zones.
What should have happened next, according to several stakeholders, was a rise in LMPs for those zones, set by DR operating during the PAI. Instead, prices in the AEP zone tanked, and 4,500 MW of anticipated load never materialized. The missing load meant that scarcity pricing was never implemented, Carroll said, because DR remained marginal and “never had the chance to set price.”
“This was a record-setting temperature for the month of October and much hotter than Oct. 1,” she said. “So for the load to come in only 1,000 MW higher on Oct. 2 really doesn’t make sense.”
Carroll said staff is reviewing its modeling, referred to as “back-casting,” and investigating other potential factors behind the discrepancy in the load forecasts.
“Our forecasting in Mid-Atlantic looked really good,” she said. “We are looking into what percentage of the load was not there because of the load management we called and what percentage was not there because of changes in weather.”
David “Scarp” Scarpignato of Calpine disagreed with PJM’s decision to call upon DR with two-hour lead times rather than the 30-minute resources that make up the bulk of the RTO’s DR fleet. Carroll said the challenges facing the grid that morning, combined with the cheaper pricing offered from long-lead DR, factored into its decision.
“You’re not allowing the prices to go where they need to go,” he said. “You’re taking emergency actions, and if you’re making them wrong, you’re going to crush prices.”
PJM’s load on Oct. 2, 2019 | PJM
Carroll later told the Market Implementation Committee on Wednesday that staff originally anticipated needing DR for several hours to sustain the forecasted load that afternoon.
“It didn’t set price when we called it, but the anticipation was that it would have been marginal throughout some portion of that day as the load materialized,” she said.
Paul Sotkiewicz, president of E-Cubed Policy Associates and PJM’s former chief economist, pushed staff to explain why prices at generator buses in the AEP zone turned negative during the PAI.
“I’m basically eating the negative prices or I’m getting penalized, and that’s something that should never happen in a PAI,” he said.
Carroll said PJM’s operations staff are preparing a paper for next month’s OC meeting that will walk through the timeline for the two days, the decisions made and the factors that impacted pricing. Staff will also release an FAQ that answers stakeholders questions posed in both meetings and through email.
“PJM does really have some concerns about the way the load materialized on Oct. 2,” she said. “There’s a chunk of 3,000 MW [missing] that PJM can’t explain at this point, and we don’t know where it went.”
She also said staff suspects there was a “behavioral component” among larger customers that made the decision to go offline during the PAI to avoid the higher prices that were anticipated.
“We are hoping that through these back-casting activities, we can put a finer point on where PJM made an error in load forecasting and where we need more visibility on how generation and load are going to behave,” she said.
MISO says it might update the solar and wind generation dispatch assumptions in its reliability planning models with projected — rather than past — numbers because of the lack of historical data on intermittent resources.
The accelerating pace of renewable adoption, especially solar, could require use of projected inputs for planning rather than relying on historical performance for renewable dispatch assumptions, the RTO said Tuesday.
“It’s clear to me that there’s a rapid change, and many more renewables have been added to the MISO footprint,” Senior Manager of Expansion Planning Edin Habibovic said at a meeting of the Planning Subcommittee.
Although MISO staff think the time is ripe to review dispatch assumptions, there’s also “strong stakeholder interest” in re-evaluating assumptions for solar resources, he said. “What we’re now trying to ask is, ‘Are the current modeling assumptions for wind and solar penetration a good representation of system conditions, and, if not, what can be done?’”
MISO reported that its footprint currently contains only five solar units totaling 314 MW, compared with 228 wind units worth 22.6 GW.
Habibovic said the historical data on the five solar units aren’t sufficient to estimate dispatch in reliability modeling. Furthermore, some of those resources couldn’t inject power into the grid at summer peak demand over the last few years, either because of maintenance, weather or other reasons.
Meanwhile, 56.7 GW worth of new solar generation is under study in the interconnection queue.
“Obviously this is a concern; we do not have enough statistically sufficient data to draw conclusions,” Habibovic said.
MISO could examine the locations of possible renewable interconnections in the queue and review historical weather data from the past six years to “plug into the program” to come up with an approximation of wind and solar generation injections, he said.
It could also use data from its ongoing renewable integration impact study to inform new dispatch assumptions, he said. He suggested using the 40% renewable penetration scenario in the study as a starting point. (See MISO: Grid Can be Stable at 40% Renewables.)
Current queue study data indicate that MISO could soon have more than 116 GW of renewables, which would align closely with scenarios in the study showing 50% penetration. However, Habibovic said a 50% penetration scenario might be too optimistic to use in assumptions.
“I don’t want to be too optimistic and say all the solar in the queue will be interconnected. At the same time, I don’t want to be too pessimistic and say only 10% of the queue will be interconnected,” Habibovic said, explaining his rationale for preferring the 40% scenario.
MISO hasn’t settled on a new process to update renewable dispatch assumptions and is asking stakeholders for their input.
“What is the right balance? … What is that magical dispatch?” Habibovic asked stakeholders.
He said MISO is looking to identify credible wind and solar dispatch scenarios at different points of the year. The RTO might also need to periodically review renewable dispatch assumptions in reliability planning studies as penetration increases, he added.
Written stakeholder opinions on the topic are due by Oct. 31. Habibovic promised more discussion at upcoming Planning Subcommittee meetings.
ERCOT CEO Bill Magness told the board that a newly formed task force will improve ERCOT’s response to the expected wave of battery energy storage resources.
The grid operator currently has 104 MW of installed storage capacity, adding 67 MW since 2016. Another 62 MW of storage is planned to be added in 2020.
“As big as the issue is getting and as many people are interested in coming in, we feel like we need to get a little ahead of it,” he said. “There can be lots of different answers to some of these questions and challenges, but we just need some answers so we can incorporate them into the systems and models and enable participation of this new resource in the market. We feel like we need to further develop the rules and protocols around this issue.”
ENGIE’s Bob Helton, chair of the TAC, said the task force will benefit both the storage companies and the ERCOT market.
“They don’t have the bandwidth to go to three, four or five stakeholder meetings to get what they need and to inject what we need,” he said. “We need those people to tell us what they’ve seen and take advantage of their experience.”
The team, which doesn’t meet until Oct. 18, will be structured similarly to the Real-Time Co-optimization Task Force (RTCTF). It will be chaired by ERCOT’s Sandip Sharma, with a members’ representative to be selected during the first meeting.
The group will focus first on modifications to how energy storage is modeled and used on the system. Staff said the changes will make different storage configurations “more palatable” before a permanent fix is brought for approval by the end of 2020.
The BESTF’s work will be timed to coincide with that of the co-optimization group, which is working on a three-year timeline. The task forces’ design changes will be part of a major system upgrade in 2024.
Taylor, Spak OK’d as Vice Presidents
The board ratified the promotions of Sean Taylor to vice president and CFO and Mara Spak to vice president of human resources.
Taylor, who has served as controller since joining ERCOT in 2013, replaces Mike Petterson, who announced his retirement after 18 years with the grid operator. Petterson will be honored during ERCOT’s annual meeting in December, but not before participating in an ironman competition in Argentina.
Spak has four years with ERCOT and almost two decades of HR experience.
The board approved the latest directive for the Southern Cross Transmission DC tie-line, a proposed Pattern Development HVDC transmission project in East Texas that would ship more than 2 GW of energy between the Texas grid and Southeastern markets.
The directive requires ERCOT to develop and implement a methodology “to reliably and cost-effectively coordinate outages” once the DC tie is interconnected.
As part of its market oversight, the PUC approved the project but issued 14 directives to ERCOT, requiring that certain studies and determinations be made to accommodate Southern Cross. The project is expected to be energized in 2023 (46304).
The board unanimously approved 15 Nodal Protocol revision requests (NPRRs), two changes to the Nodal Operating Guide (NOGRR), a single revision to the Planning Guide (PGRR), two system-change requests (SCRs), a change to the Settlement Metering Operating Guide (SMOGRR) and a Verifiable Cost Manual update (VCMRR):
NPRR918: Clarifies and updates hourly validation rules for the non-opt-in entity load forecast related to the submission of point-to-point obligations.
NPRR930: Requires staff to use an outage-adjustment evaluation process to delay accepted or approved outages after issuing an advance action notice, providing time for qualified scheduling entities to adjust their outage plans. The NPRR sets an offer floor of $4,500/MWh to make resources whole after following ERCOT’s instructions.
NPRR936: Changes the congestion revenue rights auction transaction limit from that of the CRR account holder to the counterparty level.
NPRR939: Replaces ERCOT’s practice dividing load resources — other than controllable resources providing responsive reserve service (RRS) — into two groups. Those resources would instead be divided into small groups of 500 MW each to allow a smaller manual deployment of RRS to help them meet their ancillary service responsibility toward physical responsive capability.
NPRR940: Removes from the protocols NPRR664’s gray-boxed language that introduces a fuel index price for resources.
NPRR948: Incorporates changes in the American National Standards Institute standards; increases the test schedule for coupling capacity voltage transformers tested in the last quarter of a year and removes references to fiber-optic current transformers.
NPRR950: Prohibits any switchable generation resource contracted to provide black start service from generating in any control area other than ERCOT.
NPRR951: Expands the network security analysis active constraints report and the network security analysis inactive constraints report to include megavolt-ampere flows and limits.
NPRR952: Fully replaces the Houston Ship Channel with Katy Hub as the reference for the natural gas fuel index price in ERCOT systems.
NPRR954: Allows transmission and distribution service providers or load-serving entities to opt out of Texas standard electronic transaction 867 data for electric service identifiers with ERCOT-polled settlement meters.
NPRR958: Modifies and better aligns the wind and solar capacity calculations used in ERCOT’s Capacity, Demand and Reserves (CDR) report.
NPRR959: Splits the CDR’s existing non-coastal wind region into a Panhandle region and an “other” region.
NPRR960: Revises NPRR863’s gray-boxed language to implement the board-approved phasing approach for the NPRR. Also corrects resource status references within the gray-boxed language.
NPRR961: Aligns the protocols with changes proposed in NOGRR194.
NPRR962: Requires hourly publication of the approved DC tie schedule for the following seven days.
NOGRR191: Paired with NPRR939, allows ERCOT to manually deploy load resources providing RRS to maintain at least 500 MW of physical responsive capability reserves while maintaining stable grid frequency for smaller disturbances.
NOGRR194: Clarifies and relocates to the Nodal Operating Guide black start training attendance requirements, originally located in the Nodal Protocols.
PGRR072: Allows staff to collaborate with stakeholders in setting a resource not yet subject to a notification of suspension of operations to “out of service” in the regional transmission plan and geomagnetic disturbance vulnerability assessment base cases, provided the resource’s entity notifies ERCOT of its intent to retire or mothball the resource or makes its intent public.
SCR803: Adds to the wind-integration report a new graphical dashboard showing actual and forecasted solar production and creates new solar-integration reports.
SCR804: Gives transmission operators access to ERCOT’s GridGeo application, a browser-based tool that replaces the Macomber Map and gives better situational awareness of the ISO’s transmission grid.
SMOGRR022: Removes from the guide references to fiber-optic instrument transformers.
VCMRR023: Aligns the manual’s language with NPRR940’s removal of gray-boxed language.
ITC Holdings said last week it’s looking for utilities to buy capacity on the Lake Erie Connector, an underwater 345-kV HVDC transmission line that will transmit 1,000 MW of power back and forth between Ontario and Pennsylvania.
The “shovel ready” project has cleared the last of its permits, ITC Chief Operating Officer Jon Jipping told RTO Insider on Friday, and the company now hopes the five-year investment of time and money spent jumping through regulatory hurdles in the U.S. and Canada will pay off.
“We had a really big plan and gave ourselves enough time,” he said of ITC’s progress since acquiring the project in 2014. “The connection of these two markets is going to bring some real savings.”
Lake Erie Power Corp. first conceived of the project in 2013 as a solution to the Ontario Independent Electricity System Operator’s excess power and congested transmission lines and PJM’s growing demand for emissions-free generation. (See Merchant Transco Plans 1,000 MW Line into PJM.)
The Lake Erie Connector Project will use HVDC technology to transmit 1,000 MW of power between Ontario and Pennsylvania. | ITC Holdings
Jipping said Ontario’s renewables penetration could help PJM states meet their clean energy targets, while Pennsylvania’s vast reserves of shale gas could provide lower-cost energy to the Canadian province.
“We took a strategic and tactical view of the project to go and get the permits, spend the money and get the land rights because we really felt it lent a lot more credibility to what is a very unique project,” he said. “It’s two countries, it’s connecting new markets, going across a big lake.”
The project mirrors other underwater transmission lines in France and Spain, Jipping said, and carries lower risk thanks to the progression of HVDC technology. Still, he said the construction — which will take upward of three years — isn’t without challenges.
“I don’t want to say it’s easy, but it’s fairly straightforward,” he said. “Lake Erie is not very deep. It’s much less challenging, technologically, compared to the offshore wind projects in New Jersey.” (See Orsted Wins Record Offshore Wind Bid in NJ.)
PJM’s most recent generation interconnection facility study estimates network upgrades for the project will cost $4.7 million with an in-service date of March 31, 2024. The 73-mile bidirectional line will traverse underneath Lake Erie to connect a retired 4,000-MW coal plant in Nanticoke, Ontario, to a new converter station in Erie, Penn., which will eventually tie into Penelec’s existing Erie West substation. Neither the RTO nor the utility had anything to say about the project at this phase.
RTO Insider reached out to Erie County Executive Kathy Dahlkemper to discuss her dealings with ITC throughout the permitting process. Although she was unavailable for comment, Dahlkemper told Buffalo’s NPR affiliate in 2017 that she didn’t expect the project to cause problems in the community where ITC planned to build the new convertor station.
“You have to understand that this is coming into Erie County in probably one of the least populated areas, particularly along the lake,” she told WBFO. “So the impact to where people live to their property is actually fairly minimal because of where they are coming in to our county.”
Jipping told RTO Insider on Friday that early concerns from Erie residents about property values and water contamination were allayed through public meetings and slight changes to the developer’s initial construction plans. He said company representatives will return to the local townships once construction begins to answer more questions.
“We were able to explain what we were doing and were able pick routes that were minimally impacting the community,” he said. “We had to buy a little more property than we wanted and do some route changes, but that’s pretty normal for us.”
Pacific Gas and Electric restored power to 738,000 customers across central and Northern California over the weekend after its public safety power shutoffs (PSPS) and failed communications prompted a backlash from the public, state regulators and elected officials.
California Gov. Gavin Newsom backtracked on his earlier statements that the shutoffs were an appropriate means to prevent wildfires and said during a news conference last week that PG&E’s neglect of its power lines had led to the massive intentional blackout of more than 2 million residents.
“This is not, from my perspective, a climate change story as much as a story about greed and mismanagement over the course of decades,” the governor said Thursday during a press conference at the state’s Office of Emergency Services near Sacramento.
PG&E said it restored power to 738,000 customers it had blacked out to prevent wildfires. | PG&E
Responding to criticism in his own news conference, PG&E Corp. CEO Bill Johnson acknowledged mistakes. The utility’s website had crashed, its phone lines were overloaded and its shutoff maps were inconsistent if not incorrect, he said.
“To put it simply, we were not adequately prepared to support the operational event,” Johnson said.
The CEO said the utility decided to shut off power in 34 counties based on its weather predictions but did not have the “granularity” needed to limit shutoffs to areas where they were most needed. He vowed the company would do better next time.
PG&E instituted the blackouts as part of its effort to prevent the type of deadly and destructive fires that its equipment sparked during similar windy fall weather conditions in 2017/18. Those fires included the Camp Fire, which killed 86 people and destroyed much of the town of Paradise in November 2018.
At least one fire flared up last week near the San Francisco Bay Area community of Moraga but was quickly contained. No major wildfires occurred in Northern California during the blackout.
CPUC Responds
The PSPS was included in the wildfire mitigation plan PG&E filed with the California Public Utilities Commission earlier this year. The commission approved PG&E’s plan in May. (See California Regulators OK Utility Wildfire Plans.)
That did not stop the CPUC from slamming PG&E at its voting meeting Thursday in San Francisco. In that meeting, new commission President Marybel Batjer said PG&E’s actions were unsupportable. (See Calif. Regulators Bash PG&E Power Shutoffs.)
CPUC President Marybel Batjer | State of California
“The management and the response of the company, PG&E, to the [PSPS] have been absolutely unacceptable,” Batjer said. “The impacts to individual communities, to individual people, to the commerce of our state, to the safety of our people has been less than exemplary.
“This cannot be the new normal,” she said. “We can’t accept it as the new normal, and we won’t.”
She called for a review of the public policies that led to by far the largest blackout to prevent wildfires ever to hit the state.
Commissioner Genevieve Shiroma suggested the massive shutoff wouldn’t have been necessary if PG&E had maintained and upgraded its infrastructure to prevent fires.
“The sheer magnitude [of PG&E’s PSPS] is indicative of the condition of the utility in terms of what we call the hardening — that means the condition of the poles, the lines, the wires, the transformers, the transmission lines — and the maintenance, or lack thereof, of the system and the vegetation management,” Shiroma said.
The CPUC’s deputy executive director for safety, Elizaveta Malashenko, told commission that the shutoffs affected about 2,400 miles of transmission lines and 24,000 miles of distribution lines. CAISO had been working to contain the shutoffs so that they didn’t spill over into neighboring areas, she said.
The state had tried to help PG&E keep its website and servers working, soliciting help from the likes of Microsoft and other tech companies, she said.
Southern California Response
Several wildfires did occur in Southern California as hot dry Santa Ana winds blew late last week. The largest of the blazes was the Saddleridge Fire, which burned nearly 8,000 acres above the San Fernando Valley, forcing widespread evacuations.
Residents told several news outlets they’d seen flames beneath a Southern California Edison transmission tower Thursday night as the fire started, but those reports have yet to be confirmed by fire officials or SCE.
SCE had shut off power to thousands of its customers in the greater Los Angeles area to prevent fires, but a spokeswoman told the Los Angeles Times that the transmission line in question had not been de-energized.
All but four SCE customers had power as of Monday, the company said on its website.
Firefighters continued to make progress on the Saddleridge Fire, which was about 43% contained as of Monday morning, according to the California Department of Forestry and Fire Protection. Cal Fire said the blaze had caused at least one death.
BURLINGTON, Vt. — More than 300 people last week attended the annual Renewable Energy Vermont conference, where state officials, renewable energy advocates and a Vermont congressman described their efforts to combat climate change while calling for even more measures.
REV Executive Director Olivia Campbell Andersen asked state officials what action has had the most impact on their work to transition to a clean energy economy.
Vermont Department of Public Service Commissioner June Tierney highlighted the increase in media coverage of renewable energy, which has helped drive legislative engagement.
“Our legislature is really engaged now, which really makes a difference,” Tierney said. “Kudos to Connecticut and New York for leading. … I’m not so concerned about being in the vanguard, but of bringing people along.
“We have been leaders in Vermont. … When we adopted a renewable energy standard in 2015, it was the finest in its time,” she said. “But the most impactful thing has been the regulator’s mind, and the degree to which the regulator has been open to these changes.”
She said more is demanded of regulators in a small state like Vermont, where the legislature has invested the responsibilities for planning, envisioning and economic regulation in the DPS.
Rep. Peter Welch (D-Vt.) said, “Tax credits make a huge difference at the beginning of a technology,” adding that the House of Representatives “may be able to do something on the electric vehicle front by extending the tax credit.”
Welch is a member of the bipartisan Advanced Energy Storage Caucus in Congress and co-sponsor of the Energy Storage Tax Incentive and Deployment Act (H.R.2096), which would establish an investment tax credit for energy storage.
The caucus is focused on integrating renewables into the grid, increasing electrification of heating and transportation, and improving energy efficiency, he said.
“Whether the existing investment [EV] tax credits we have now will be extended or not, we don’t know yet, but my experience has been that there is hugely bipartisan support to extend,” Welch said. “The question is always when and how that’s going to get done, and it usually gets done at the very end of the session, when there’s an overall omnibus budget bill and tax agreement. … My prediction is they will be extended.”
Vermont Lt. Gov. David Zuckerman said, “The Trump tax cuts supposedly offered about $500 million to Vermonters in savings in their federal taxes, but over $300 million is going to the top 10% of Vermonters. My guess is that most of that $300 million is probably not going to be spent in Vermont; it’s going to be sent to Wall Street.”
Zuckerman proposed instead to take half that money from wealthy residents and spend it on in-state programs such as weatherizing houses or expanding broadband access in rural areas.
“We do not have time for slow, incremental change,” Zuckerman said.
Burlington Mayor Miro Weinberger proposed imposing a statewide carbon pollution fee in Vermont to help cut carbon dioxide emissions 37% by 2040, calling it “perhaps the most critical thing we can do to address the climate emergency, and that would create a transformative tailwind that pushes into all of our other efforts to decrease carbon emissions.”
Weinberger said the carbon charge would not be a tax, but a “revenue-neutral carbon fee,” as “money collected by the state would be rebated back to Vermont households and businesses and keep those resources working in the economy.”
Regional Reflections
Peter Olmsted, chief of staff at the New York Energy Research and Development Authority, said his state started its clean energy revolution a decade ago as it sought “to understand how the utility business model was going to evolve and respond to the needs of consumers, the need to respond to climate.”
However, understanding the necessary changes to regulators’ thinking has been “the bigger challenge for us, whether it be a matter of prioritization of issues, capacity and resources, [or] an asymmetry of information between the regulator and the regulated,” Olmsted said.
Regarding reliability, Olmsted said that “80% of our transmission lines were put in service before 1980, and over the next 10 years, the investment to upgrade those is going to be on the order of $30 billion.”
New York needs to reconcile aging infrastructure with plans to develop “a significant amount of renewable energy and clean energy resources on the grid simultaneously… so energy storage we believe is a key ingredient in that,” he said.
The interconnection “queue for NYISO has just exploded,” Olmsted said. “We were at 200 MW in the queue in 2018 when we commenced our energy storage roadmap process, and we’re now seeing upwards of 5,500 MW in our queue, so we know the demand and the interest is there.”
“We’re trying to enable an economy-wide decarbonization, which mirrors the executive order seeking 100% zero carbon by 2040,” Gillett said. “We’re also working to make a resilient, reliable and secure electricity commodity supporting growth in the green economy.”
The cornerstone of the state’s grid modernization proceeding is affordability, not only for residential customers, but also for commercial and industrial ones, she said.
RMI View
Jules Kortenhorst, CEO of the Rocky Mountain Institute, said, “We were a think tank, but the time for thinking is over. We are facing a climate crisis and the clock is ticking.
“The accelerating pace of an energy transition may become the wind in our sails, just when we need it most,” he said in comparing two contrasting views of the transition, one that thinks it best to go slow and the other that says the planet is on an exponential curve for warming.
Kortenhorst finds hope in the seemingly most mundane area of efficiency: “boring old building codes.”
“If we don’t get our buildings to near net-zero emissions, there is no way we’re going to reach our climate goals,” he said.
He also highlighted that solar is in many places of the world already the most cost-effective way to produce electricity, and 90% of natural gas projects in the country are now beaten economically by wind and solar.
“And it’s a global trend … in the buildup to the Paris [Agreement on climate change], India said it would build half coal and half solar. … Now they see the economic benefit of leapfrogging,” he said.
“As we are starting to deploy batteries to stabilize our electricity grid and to make solar available at the end of the afternoon when the sun is setting, we are driving down the cost such that electric cars become cheaper, at which point Ford, GM and Chrysler see that the future is electric, which drives costs down even further, which makes it easier to store the solar energy in batteries for our grid,” Kortenhorst said.
“These feedback loops are starting to build on themselves, and we see a dramatic shift in the way in which people are starting to understand that if we weave a complex of web of renewable energy solutions, we will be able to shift to a low-carbon energy future much faster and much more cost-effectively.”
Vermont imports four times as much energy as it produces within the state, and the largest utility, Green Mountain Power, “is highly dependent on imports from [Canadian] hydropower and nuclear power from Millstone and Seabrook, [which] are long distances away, as is most of the hydropower,” said Kim Hayden, who leads the energy and environment practice group at the Burlington-based law firm of Paul Frank + Collins.
“Seabrook and Millstone are among the two most vulnerable nuclear units in the country subject to inundation, based on [studies that took] a lot of time and effort by the Nuclear Regulatory Commission after Fukushima,” Hayden said. She noted that one study resulted in NRC adopting a rule (84 FR 39684) requiring owners of coastal plants to modify their infrastructure “to withstand the levels that are now expected from storm surges and severe inundation.”
Hayden called for better planning, such as fixing the transmission constraints associated with the Sheffield-Highgate Export Interface (SHEI), which prevents the development of new renewable energy resources in northern Vermont. She also said the state should increase its renewable energy standard.
Rebecca Towne, CEO of the Vermont Electric Cooperative, agreed with Hayden’s concerns about long-distance imports, saying that utilities would ideally like to pair load and generation in the same location — and hopefully synchronize the periods of demand and output.
“Vermont is not a very big state, and so it doesn’t take a very far transmission line to get out of state … and anything that goes by transmission line, by nature, whether it’s in-state or out-of-state, is not paired generation and load,” Towne said.
“So the SHEI challenge is too much renewable generation in the northern part of Vermont, versus the load,” she said. “The problem we run into is the location and timing of all that generation and the load is mismatched. The real way to fix that is to go with more transmission lines, but that doesn’t really make any sense, mostly because our load is going down.”
Storage has the unique characteristic of being either load or generation, depending on when it’s needed, said Chris McKay, director of sales for battery energy storage solutions at WEG Electric in Barre, Vt.
“That ultimate dial or control is something you can do with a battery that the utilities and other planners are trying to create through other means, with controllable loads and dispatchable generation,” McKay said.
PJM will pay two trading firms $12.5 million to end a dispute over the 890 million MWh GreenHat Energy default under a settlement agreement filed with FERC on Thursday.
Apogee Energy Trading and Boston Energy Trading and Marketing (BETM) will accept credits of $5 million and $7.5 million, respectively, to resolve the firms’ claims of economic harm that resulted from PJM’s decision to not liquidate GreenHat’s entire portfolio of financial transmission rights during the 2018/19 planning period (ER18-2068). After the company defaulted in June 2018, PJM reran only the July FTR auction — a decision the RTO says kept costs to members down and avoided a cascade of market violations that would increase uncertainty for years to come.
“Those payments are integral to an overall package that allows payors in PJM to avoid the risk of the additional default allocation assessments that might result if the proceeding were litigated to conclusion,” the RTO’s attorneys wrote in the settlement. “PJM and many settling parties also attach considerable value to the settlement’s removal of a cloud over the July auction and subsequent FTR auctions in the same planning period, and in avoiding the possibility of disruption to such auction results.”
Apogee and BETM had opposed PJM’s request to waive existing rules to settle the remainder of GreenHat’s portfolio. PJM sought the waiver to reduce the impact on the monthly FTR auctions throughout the rest of the year. After FERC denied the request, the firms protested the RTO’s subsequent motions for rehearing and clarification.
Throughout discussions, PJM and the two firms disagreed over how much economic harm the original auction results caused. In the agreement filed Thursday, the RTO said the payments serve as a proxy for rerunning the July auction.
“When sophisticated parties reach such a settlement, the resulting compromise value can be expected to reflect the parties’ efforts to protect their respective interests, based on their separate assessments of adverse litigation outcomes, the cost of litigation, impacts on market viability and the value of preserving settled market outcomes,” PJM wrote. “Such is the case here. Rather than engage in complex and extended litigation about each method, practice and assumption that might be used to rerun or resettle the July auction, Apogee, BETM and the payor settling parties explored whether they could reach agreement on payment levels, informed by the differing estimates of economic harm by PJM and Apogee, and by PJM and BETM.”
In addition to Apogee and BETM, the settling parties were American Electric Power Service Corp., American Municipal Power, Buckeye Power, DC Energy, Direct Energy Business, Direct Energy Business Marketing, Dominion Energy Services, Duke Energy Kentucky, Duke Energy Ohio, East Kentucky Power Cooperative, EDF Trading North America, EDF Energy Services, EDP Renewables North America, Elliott Bay Energy Trading, Exelon, FirstEnergy Service Co., LS Power Associates, Mercuria Energy America, Mercuria SJAK Trading, NextEra Energy Marketing, NRG Power Marketing, the PJM Industrial Customer Coalition, the PSEG Companies and Southern Maryland Electric Cooperative.
Although PJM did not describe the settlement as uncontested, it said “none of the settling parties shall seek rehearing of an order approving or accepting this settlement without modification or condition.” The other settlers aren’t asking for money because they believe they benefited from the way PJM ran the July 2018 auction and settled the remainder of GreenHat’s portfolio.
PJM members are funding the credits to Apogee and BETM through default allocation assessments. PJM said it will establish another $5 million fund for additional claimants, though it anticipates there won’t be any, based on the limited protest filings it received during the proceeding.
After receiving their credits, Apogee and BETM will be subjected to the same default allocation assessments that other members face. PJM spokesperson Jeff Shields told RTO Insider on Monday the default will cost members $177.5 million — substantially less than the cost of rerunning the July auction.
“The settlement is the product of intensive good faith negotiations among the participants to this proceeding,” he said. “It brings to a close open issues around the treatment of defaulted GreenHat portfolio. The settlement is supported by a broad array of stakeholders, there has been no indication that it is opposed by anyone, and it is in the public interest.”
PJM said it will rerun the July auction for the sole purpose of supporting the credit payments established in the settlement. The simulation will liquidate the entirety of GreenHat’s portfolio, which would impact FTR auctions in any month between September 2018 and May 2019. If any of the FTRs offered for liquidation would set price, then the simulated auction is rerun after removing 50% of the total defaulted FTR positions, regardless of path or period. PJM would waive all applicable Tariff rules concerning simultaneous feasibility test violations; prohibitions on selling FTRs not owned by an auction participant; FTR forfeitures; and requirements for participants to post additional credit based on tentative clearing results.
“The agreement not to apply the Tariff rules listed above is a key benefit of the ‘black box’ approach to settling this case,” the RTO’s attorneys wrote. “If PJM actually reran the auction, the referenced rules could cause cascading deviations from actual settlement results in other auctions conducted for the 2018/19 planning period, likely creating additional Tariff violations, further disrupting the market and undermining market participants’ faith in the finality of the FTR auctions.”
PJM asked FERC to waive both the reply comment period and the regulations necessary to effectuate the settlement. The RTO and the settling parties will answer questions on the deal in a meeting at FERC from 1 to 3 p.m. Oct. 17. The meeting will be available via teleconference (Phone: 800-375-2612; Meeting Access ID: 379441).
Bruce Rew, SPP’s senior vice president of operations, predicted a year ago that there was “a good chance” the RTO would reach the 70% barrier for renewable energy penetration.
Rew’s prognostication skills are not in doubt. The RTO tweeted last week that it met 73.67% of its demand Wednesday with wind, hydro and other non-fossil resources.
| SPP
The mark came at 2:14 a.m. CT, when SPP’s load was 22.5 GW. Renewable resources suppled 16.5 GW of that power, with wind supplying 65.4% and hydro 8.3%. The grid operator also set a record for wind generation on Sept. 30, when it produced 17,109 MW at 12:30 a.m. That broke the previous mark of 16,972 MW, set Sept. 11.
ERCOT, which has 22,313 MW of installed wind capacity, holds the RTO high for wind generation, set in January at 19,672 MW.
An important fall pastime, along with baseball playoffs, is to look back to see which electric market design model performed best over the summer. For the last several summers, a lot of eyes have been on the ERCOT market, given its relatively low reserve margins and lack of a mandatory forward capacity market. The results are in. There was no firm load shed because of supply shortages, and ERCOT’s 2019 Summer Operational and Market Review stated, “Overall, the market outcomes supported the reliability needs.” My colleagues and I at Grid Strategies ran the revenue adequacy numbers and found that prices did what they should, providing appropriately strong signals to attract new market entry while charging customers only for what they needed.
The key distinction between ERCOT and regions with a capacity market or resource adequacy requirement is that in ERCOT, responsibility for assessing the level of supply and demand need for investment lies with market participants, not the grid operator itself. Other regions are charging customers more than 20% of the total cost of energy, capacity and ancillary services through capacity markets. In contrast, ERCOT focuses on grid operations more like an air traffic controller, saving consumers that money. It uses spot energy and reserves prices to accurately value energy over time and at each location, and lets market participants handle their own price risk management and supply assurance through bilateral contracts. Spot energy values at times of scarcity are allowed to reach $9000/MWh — reflective of true consumer valuation of supply at that time and place — and the value of reserves, which is based on a downward sloping operating reserve demand curve. By keeping dollars in spot markets as opposed to a capacity market, this market design attracts flexibility from demand response, storage, hydro and any other source that delivers when it is needed. There are no drawn out subjective debates with RTO management and stakeholders about what resources should count how much toward the elusive concept of “capacity,” and what public policies should be mitigated, as is the case in the Northeast. (See our paper showing how the minimum offer price rule costs PJM consumers $5.7 billion extra per year.)
One would expect that when the system is low on capacity — as it was this summer with around an 8% reserve margin — prices would occasionally be very high and on average equal or exceed the amount that efficient new units need annually to recover their capital investment cost. In economic theory terms, in an efficient market at equilibrium, over the course of the year there would be enough “rent,” or profit earned from prices that exceed generators’ operating costs, that new generators see enough profit incentive to enter. So the question is, were prices over the last year high enough to attract and retain needed units? Our analysis below indicates the answer is YES.
Let’s take a look at the prices in 2019 so far (see our blog for data, assumptions and methodologies). The figure below uses ERCOT historical real-time ORDC data generated during each security-constrained economic dispatch interval to display the number of hours that prices have exceeded generators’ operating cost from January through September.
ERCOT price duration curve analysis (January to September) | ERCOT
As shown above, prices have been consistently higher this year than in previous years. So far, prices have already exceeded $200/MWh for 95 hours, with four hours and 10 minutes reaching the systemwide offer cap price. This September alone, with the most record-high temperature days since 2011, was responsible for 10 minutes worth of prices at the offer cap and 20 hours worth of prices above $200/MWh. For reference, 2018 saw 54 hours over $200/MWh and only 10 minutes at the offer cap. Since the creation of the ORDC in June 2014, ERCOT only saw prices hit the offer cap one other time in 2016 for five minutes.
So prices have been higher, but were they high enough to attract entry? To answer that question, we can look at net margin for different units. In Grid Strategies’ analysis of year-to-date data, efficient new peakers earned 35% above what they need to earn in an average year to pay for the capital cost of building the units, and combined cycle units earned 25% above that target. In most prior years when reserve margins were higher, they earned less than this target level.
Peaker net margin analysis | Potomac Economics
These high spot prices signal to retail electric providers to go out and sign more contracts with generators so they can shield themselves from high spot market prices in the future. Those long-term power purchase agreements are then used by prospective generators to finance their new plants. An influx of 4,000 MW of solar and 5,000 MW of wind plants expected by next summer will likely take care of much of this need. Market participants also have clear responsibility and incentives to seek sources that shield them from high prices when wind and solar output is low. The Public Utility Commission of Texas reviews those entities’ creditworthiness to make sure they are financially equipped to serve the load they commit to serve — an important and often forgotten regulatory responsibility of state commissions. Few customers actually had to pay the high spot prices, as they were covered by contracts signed well in advance, and the prices withstood the mild political opposition without regulatory intervention.
This year may have been the best test to date of the ERCOT market design. The results so far indicate that despite the hot summer and low reserve margin, no firm load was shed because of supply shortages, while the system did provide sufficient price signals to attract and retain needed resources. High spot prices did not attract political intervention, and consumers only paid for what they needed. ERCOT’s 2019 experience should answer a lot of questions about whether ERCOT’s unique market design works. One thing is for sure though: Our October pastime of reviewing the past summer’s power market results will come again as surely as the sun rises or the baseball playoffs begin.
Rob Gramlich is founder and president of Grid Strategies LLC, a clean energy grid consulting firm.
The latest salvo was Rocky Mountain Institute’s claim that the bulk of new natural gas generation is/will be uneconomic. As I said before, perhaps the advocates hope that if gas investment is scared off, then renewables and batteries become a fait accompli.
The first major flaw was that 40 to 50% of RMI’s “clean energy portfolio” (CEP) comes from demand response and energy efficiency. It assumed large amounts of those resources are available at low cost.
And, importantly, it assumed that these hypothetical low-cost resources were only available to its renewables/battery CEP portfolio and not to a gas portfolio. As a result, the economics that RMI attributed to its renewables/battery portfolio actually came from mixing in low-cost DR and EE that are not unique to that portfolio.
The second major flaw was that in its modeling, RMI used traditional fossil generation to recharge the batteries. Yes, ironically, traditional fossil generation was supplying a “clean energy portfolio.” And, most dramatically, in a last hour of covering peak load, the equivalent of a 1.5-GW gas generator was matched by: zero wind and a negligible amount of solar; batteries charged with traditional fossil generation; and huge amounts of DR and EE, neither of which are unique to a renewables/battery scenario. In other words, renewables contributed virtually nothing to matching the 1.5-GW gas generator.
RMI says investors are “taking notice,” pointing out that final investment decisions for new gas plants have declined since 2014. But at this level, they are the same as they were in 2010. Trend or cycle? And RMI is not correct that the capacity factor of combined cycle gas plants is declining; in fact, the article cited by RMI has a chart clearly showing the opposite.[efn_note]https://www.spglobal.com/marketintelligence/en/news-insights/trending/Pu5fAcJoqopojxYhGN0tMw2.[/efn_note]
Just as Energy Information Administration data show that the capacity factor of combined cycle gas plants is at a record[efn_note]EIA Electric Power Monthly, Table 6.7.A, for August 2019 and August 2014, available here, https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_a.[/efn_note] high:
Natural gas combined cycle average annual capacity factors | based on EIA data
Even if RMI were right about such things as capacity factors, none of it is really reflective of investor sentiment. The real indicators are things like the share price of NRG Energy — the best proxy for competitive fossil generation (about half of which is gas) — which is up from $11/share to $40/share in the last three years. And RMI’s own statement that there is “more than $100 billion in planned gas infrastructure investment through 2025.”
If gas is a bad investment, Wall Street didn’t get the memo. RMI may suggest its study is the memo, so that takes us back to the study itself.
RMI’s Reply on Assuming and Co-opting the Low-cost Resources
RMI’s aggressive assumption on lots of available DR and EE cannot be sustained by referring, as RMI does, to “definitive resource potential assessments” (my emphasis). Potential is just that.
But more important, RMI admits that it assumed the availability of (low-cost) DR and EE for its renewables/battery portfolio and not for its gas portfolio. It now says that’s OK because its study showed that DR and EE are “natural complements to zero-marginal-cost generation from wind and solar.”
I can’t find anything in the study that remotely supports that proposition. I can’t even find the words “complement” or “zero” in a word search. Please note that RMI saying in its study that it optimized resources in its modeling should not be confused with a showing that certain resources complement each other better than others.
Bottom line: The RMI study’s co-option of low-cost DR and EE resources for its CEP portfolio is a fundamental, unsupported flaw.
Low-cost Resources Threat to Gas?
RMI says that the implication of my critique is that inexpensive DR and EE are themselves a threat to gas investment. A clever thought. But too clever by half. It’s RMI, not me, that assumes vast availability of low-cost DR and EE.
And if DR and EE are a threat to gas, then they must be a bigger threat to more-expensive renewables. Is RMI warning Wall Street about renewable investment? No, I didn’t think so.
The CEP Dependency on Fossil Generation
RMI does not deny that in the last hours of peak conditions, fossil units are providing needed generation via batteries, and renewables are providing virtually nothing. RMI says that just reflects the leveraging of available fossil generation for the foreseeable future.
Fair enough I guess. So long as everyone understands that RMI’s modeling is not of a sustainable equilibrium condition. Instead, it depends on fossil generation sticking around so when solar and wind aren’t generating, the system can still serve load reliably. And as I’ve pointed out, if new gas generation is scared off, then the old fossil with much higher carbon emissions will be what carries the CEP portfolio.
Finally, RMI goes on to overplay its hand by claiming that nothing undermines its central finding “that CEPs can compete and win on gas plants’ own turf.” No. In its modeling, RMI’s CEP portfolio is undeniably dependent on fossil generation. RMI admits that. The converse is not true: A fossil fleet is dispatchable and is not dependent on renewables/batteries, as decades of reliability grid operation without renewables or batteries attest.
