WASHINGTON — FERC Chairman Neil Chatterjee emphatically denied Thursday that he is considering resigning from the commission by the end of the year, as was reported by POLITICO earlier this week.
“Let me say it right now: I’m not going to take a job at an RTO or a company or an environmental group or a consumer advocacy,” Chatterjee told reporters after the commission’s monthly open meeting Thursday. “I’m not going to run for office in Kentucky. I’m not running for office in Virginia. I have never expressed interest in being [the secretary of energy]. I intend to finish my term so that stakeholders can have confidence in the durability of this commission.”
Chatterjee, whose term expires June 30, 2021, repeated much of what he said when he talked to POLITICO in a podcast, in which he spoke passionately about the “privilege to be nominated” and honoring his “commitment to the president that nominated you, the Senate that confirmed you and to stakeholders.”
He noted that FERC “has been through a lot. There has been so much turnover in leadership, really going back to 2013,” which he said has negatively impacted staff morale and certainty with stakeholders. “I am not going to contribute to that,” he said.
Chatterjee also committed to staying on the commission even if a Democratic president is elected next year; as a Republican, he would be forced to give up the chair to a Democrat.
In the podcast, Chatterjee denied any plans on running for political office in Kentucky, where he will lead the EnVision Forum this Monday. (See Chatterjee Coal Country Forum to Consider ‘Energy Transition’.) He said that while Kentucky would “always be home to me,” he has lived in Virginia for 16 years and raised his children there. “I’m not going to disrupt that to move home to Kentucky and run for office.”
POLITICO also reported that Chatterjee is being considered as a potential replacement for Energy Secretary Rick Perry, whom the outlet also reported earlier this month was considering resigning by the end of the year. (Perry has similarly denied that report, but late on Thursday, President Trump confirmed he would leave and said the administration has already selected his replacement.) POLITICO cited “three people familiar with [Chatterjee’s] thinking” in its report, which it briefed it in its daily “Morning Energy” email on Tuesday.
“I was frustrated with the story because literally the only person that could know my future plans is me,” Chatterjee said. “The headline was I’m ‘eyeing the exit, per sources,’ and then my statement that I intend to finish out my term was three or four paragraphs down; I thought that was a little misleading.”
CARMEL, Ind. — MISO and PJM are close to embarking on their first major interregional transmission project after years of coming up short in identifying a joint effort worthy of the designation.
The RTOs say they will support the $21.6 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in the northwestern corner of Indiana, a that project that qualifies as an interregional market efficiency project (IMEP) on their seam, according to MISO Senior Manager of System Planning Jarred Miland.
The RTOs have approved two portfolios of smaller targeted market efficiency projects in 2017 and 2018, but they have never agreed to an IMEP project until now.
“Both us and PJM think this is a good project. We want to move this forward,” Miland told MISO stakeholders at an Planning Advisory Committee meeting Wednesday.
PJM officials the following day said rebuilding the line was the best option and deemed the project its preferred solution after determining it passed a “reliability no-harm test.” The project will undergo a “second read” in November under PJM’s process.
Both RTOs say they plan to recommend the project to their respective boards later this year.
PJM customers stand to pay for the lion’s share of the line rebuild, with MISO being allocated just 10.85% — or about $2.4 million — of the full cost.
MISO expects the project to yield a 3.12:1 benefit-cost ratio, while PJM estimates a ratio of 2.63:1 based on its own calculations.
The project need was identified by MISO planners in this year’s Market Congestion Planning Study, part of the RTO’s annual Transmission Expansion Plan (MTEP) — the only such project to be recommended from the study. MISO said its congestion forecast this year was relatively low because of flattened demand and little price difference between generating units.
MISO board approval of the IMEP will likely be delayed until the RTO can get a cost allocation method in place for its market efficiency projects. MISO’s first cost allocation plan — which includes the IMEP cost allocation method — was stalled earlier this year when FERC raised concerns about cost causation. (See Key Details Change in MISO MEP Cost Allocation Plan.)
Miland said the project will be mentioned in the MTEP 19 report, but included in Appendix B — rather than Appendix A — of the report, which lists projects with a documented need not yet ready for construction, with costs not included in MTEP spending totals. MISO’s board plans to hold a separate vote to approve the IMEP after FERC approves MISO’s cost allocation filing.
While progress continues on MISO-PJM seams work, no projects have been recommended for the MISO-SPP seam. This year, planners emerged empty-handed after producing a coordinated system plan study, prompting more intense calls for process changes between the RTOs. (See MISO, SPP Empty-handed After 3rd Project Study.)
WASHINGTON — FERC Chairman Neil Chatterjee accused Commissioner Richard Glick of seeking to politicize commission staff’s Winter Energy Market Assessment after Glick complained that he had not been allowed to suggest changes to the report before staff’s presentation at Thursday’s open meeting.
“As I understand it, traditionally — and since I’ve been here — when we’ve had these types of reports … [commissioners] had the ability to see the reports in advance and make some suggestions if things weren’t clear … and I’m very disappointed that didn’t occur today,” Glick said. “That is the normal process, and for some reason we were told we had to go back to the original [unedited] report.”
Glick’s concerns were at least in part over the report’s statement that “Coal and oil-fired generation continue to play an important role in maintaining electric reliability during the winter, especially in the Northeast, where winter demand for natural gas can exceed pipelines’ capacity.”
“As I understand it in NYISO, coal makes up about 2% of installed capacity, and it’s even less in New England — it’s like 1%,” Glick said after the staff presentation. “So, what is it about coal and oil that makes it more important for the winter in terms of reliability than nuclear and hydro … or other technologies?”
Oil, which can be used as an alternative fuel for some natural gas generators in New England, made up 1% of ISO-NE’s generation mix and 0.9% of its net energy for load (NEL) in 2018, according to the RTO. Coal had identical shares. Renewables, excluding hydropower, were responsible for 10.4% of capacity and 8.7% of NEL.
In an email to ERO Insider, Glick said his staff suggested changes after the assessment had been reviewed and edited by the chairman’s office. In addition to questioning why the draft highlighted the importance of coal and oil, there were “clarifying” edits intended “to help the public better understand the information in the report,” he said.
Chatterjee acknowledged in a press conference after the meeting that Glick’s suggested edits had been ignored, saying it would be improper for “politically appointed commissioners” to “scrub” staff’s work.
“Perhaps prior iterations of the commission were more politicized and had politically appointed commissioners scrubbing staff’s work. I wanted to be above politics and feel that we should go with the career staff’s work,” he said, prompting laughter among some FERC staff in the room.
Glick’s ‘Biases’
Chatterjee suggested Glick’s questions on the value of coal and oil were “an example of his negative biases toward certain sources of generation.”
Chatterjee also rejected complaints that he has politicized the commission as chair, saying, “I think the compliance actions we took today on Order 841 [opening wholesale markets to storage] are [proof that the allegation] is just patently false.” (See related story, FERC Partially Approves PJM, SPP’s 841 Compliance.)
Glick said he was “offended by the chairman’s characterization during his press conference. I wasn’t the one scrubbing language and the chairman knows that.”
The Democratic Glick has often disagreed with Republicans Chatterjee and Commissioner Bernard McNamee over their refusal to consider greenhouse gas emissions in approvals of natural gas pipelines. But Thursday’s meeting put staff publicly in the middle of their dispute. It was a bit like two warring parents asking their children to take sides.
The report noted that 5.6 GW of natural gas-fired generation capacity will have been added nationwide between last winter and winter 2019/20, prompting Glick to ask staff for the equivalent statistics for wind (12 GW) and solar (6 GW) — which were not in the report.
That led McNamee to press staff to acknowledge that the figures were based on renewables’ nameplate capacity and did not discount them for their lower capacity factors.
It is at least the second time that Glick has criticized the chairman recently over his administration of the commission. In July, Glick and then-Commissioner Cheryl LaFleur complained that Chatterjee had unilaterally ended an investigation into whether Dynegy had acted improperly in FERC Clears MISO 2015/16 Auction Results.)
Staff’s winter assessment found that all NERC assessment areas are projected to have reserve margins above their target levels for the winter. The National Oceanic and Atmospheric Administration says there is a high chance that winter will be warmer than average for the Northeast, West, Texas and Florida, with the Upper Midwest expected to have normal temperatures.
It also said natural gas storage levels will be about the five-year average heading into the winter and that gas futures prices are lower than last year with the exception of Boston, where basis futures prices averaged $6.54/MMBtu, up $1.16 from last winter, as of Oct. 4.
In other findings, staff said:
Production of consumer-grade natural gas set new record highs in the first half of 2019, averaging 90 Bcfd through June, up 12% from 2018. The Marcellus Basin in Pennsylvania, West Virginia, Ohio and New York led production regions with an average of 22 Bcfd through June 2019. The Permian Basin in Texas and New Mexico averaged 9 Bcfd in 2019 through June, a 38% increase from last year. Pipeline additions in both regions allowed additional gas supplies to reach markets.
The Energy Information Administration forecasts U.S. gas demand will average 100 Bcfd from November to March, up 1% from last winter. Electric generation is expected to increase 6% to 27 Bcfd, which would be an all-time winter high. Industrial natural gas demand is also expected to increase by 2% to 25 Bcfd, while residential demand, generally the biggest driver of winter peaks, is expected to drop 3% to 25 Bcfd.
More than 3.4 GW of coal-fired generation retired between March and June 2019, with an additional 6.2 GW of coal expected to shutter by February 2020. About 680 MW of nuclear capacity retired between March and June, with an additional 829 MW of retirements announced through February 2020.
Southern California Gas’ system is expected to face continued restrictions because of pipeline outages and repairs. Some 530 MMcfd of import capacity on Line 235-2 has been offline for the past two years, but repairs completed on Oct. 14 returned 173 MMcfd of import capacity to service.
Algonquin Gas Transmission and Texas Eastern Transmission have announced capacity reductions to allow pipeline safety and integrity testing in the Northeast, but most restrictions should end by December.
ISO-NE’s Pay-for-Performance program and PJM’s Capacity Performance program, which use penalties and bonuses to incent performance during capacity critical periods, will be fully implemented for this winter. ISO-NE also is developing market-based fuel security rules, which are expected to be filed in April 2020.
Reserve Margins
Glick noted that all of the assessment areas were projected to have reserve margins well above target levels, with the Northeast Power Coordinating Council forecasting levels of about 70% in New England and New York. Yet winter remains a concern in New England because of its limited pipeline structure, which can lead to gas shortages for generation.
“So are there other metrics we should be thinking about?” he asked. “This is an important issue we should start considering because the way we structure market rules … sometimes causes us to over procure capacity or make decisions that might be good for one part of the year and might not be good for another part of the year. … I would hope the commission and NERC and others can take a look at [that].”
Southern California Edison came under increasing scrutiny Wednesday for its possible role in starting the Saddleridge Fire near Los Angeles, while Pacific Gas and Electric defended its public safety power shutoffs (PSPS) that affected more than 2 million residents last week as an effective means of preventing wildfires in its territory.
PG&E cited about 100 incidents in which high winds had toppled trees and branches onto de-energized power lines, which it said could have started a fire had they been active.
“While we understand and recognize the major disruption this PSPS event imposed on our customers and the general public, these findings suggest that we made the right call, and importantly no catastrophic wildfires were started,” Michael Lewis, PG&E’s senior vice president of electric operations, said in a statement.
The utility came under heavy fire from Gov. Gavin Newsom and the California Public Utilities Commission, among others, for its largescale power shutoffs. (See related story, CPUC Orders Changes to PG&E Shutoff Rules.)
PG&E is in Chapter 11 reorganization following devastating wildfires sparked by its equipment in 2017 and 2018. It told the U.S. Securities and Exchange Commission on Friday it had lined up more than $34 billion in financing commitments to help it emerge from bankruptcy.
SCE Blamed for Fires
SCE also shut down power during high winds last week, but on a smaller scale: It cut service to roughly 24,000 customers.
An SCE transmission line near Saddle Ridge Road, on the outskirts of suburban Los Angeles, may have been active when the wildfire apparently started beneath it Thursday night, according to SCE and fire investigators.
“The cause of the Saddleridge Fire remains under active investigation,” the Los Angeles Fire Department said on its website. “The area of origin has been identified by LAFD Arson Investigators as a 50-by-70-foot area beneath a high-voltage transmission tower.”
The Saddleridge Fire burned approximately 8,400 acres above the San Fernando Valley area of Los Angeles. | National Wildfire Coordinating Group
SCE filed an incident report with the CPUC on Friday “out of an abundance of caution,” saying its 220-kV Gould-Sylmar line had been “impacted” around the time the fire began.
“The Saddleridge Fire was reported in the Sylmar (in the vicinity of Yarnell Street/210 Freeway) area on Thursday, Oct. 10, 2019, at approximately 9 p.m.,” the report said. “Preliminary information reflects SCE facilities were impacted close-in-time to the reported time of the fire. SCE is monitoring the event and the investigation continues.”
Residents told several Los Angeles area news outlets that they’d seen flames beneath transmission lines about the time the fire started. The fire has so far caused one fatality and damaged or destroyed 100 structures.
SCE said Wednesday that it was considering shutting power on Thursday to about 32,500 customers in Inyo, Mono, Kern, Los Angeles, Riverside and San Bernardino counties in the face of increasing winds, the LA Timesreported.
“We provide as much advance notice as we can ahead of when we think the weather might come,” company spokesperson Robert Villegas said. “It’s a situation that might develop, but it might not, so we ask for customers’ patience.”
SCE has also been blamed for major wildfires in 2017 and 2018.
State fire investigators determined the utility’s power lines sparked the Thomas Fire, a 280,000-acre blaze in Santa Barbara and Ventura counties that killed two people and later caused a mudflow that killed 21. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
The California Department of Forestry and Fire Protection (Cal Fire) is continuing to investigate the cause of the Woolsey Fire, which killed three, burned 1,643 structures and scorched nearly 97,000 acres in Ventura County in November 2018. SCE equipment is a suspected cause.
PG&E Lines up $34 Billion in Financing
PG&E’s equipment was blamed for starting the Camp Fire in November 2018 that killed 86 people and destroyed much of the town of Paradise, including more than 14,000 homes there. It was by far the deadliest and most destructive in state history.
Cal Fire investigators also found PG&E equipment had started 21 of the 22 major wildfires in the northern San Francisco Bay Area in October 2017, including in the famed wine country of Napa and Sonoma counties.
An estimated $30 billion in liability for those fires drove PG&E to seek bankruptcy protection in January. In recent weeks, the company has been fighting a competing reorganization effort by its bondholders that amounts to a hostile takeover.
The bondholders, led by two large hedge funds, have offered to invest more than $29 billion in PG&E Corp. and its utility subsidiary in exchange for a controlling stake in the companies. Their plan would pay off billions of dollars in wildfire debts to homeowners, local governments and insurance companies, including $13.5 billion for individual fire victims.
U.S. Bankruptcy Court Judge Dennis Montali ruled Oct. 9 he would admit the bondholders’ plan into the bankruptcy proceedings, primarily because it had won the backing of thousands of fire victims through the Official Committee of Tort Claimants. (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)
The bondholders’ main argument was that it had the financial resources ready to pay for its plan, while PG&E lacked similar funding and had only offered the tort claimants a trust capped at $8.4 billion.
PG&E filed a form with the SEC on Friday saying it had received $34.35 billion in commitment letters from J.P. Morgan Chase Bank, Bank of America and others to pay for its own reorganization plan.
“PG&E is confident that its plan charts the best course for its emergence as a financially sound utility positioned to serve its customers and contribute to California’s clean energy future,” the company said in a statement released Thursday.
The release outlined PG&E’s objectives for its reorganization plan, including assuming all PPAs and community choice aggregator servicing agreements; fulfilling pension obligations and other employee agreements; and providing for the utility’s future participation in the state wildfire fund established under Assembly Bill 1054.
PG&E also reiterated its $8.4 billion cap in damages to wildfire victims and said it still intends to pay out $11 billion in subrogation claims to insurance companies.
Both reorganization plans are scheduled to be considered by the bankruptcy court Oct. 23.
PG&E’s stock, which had traded at nearly $70/share in mid-2017, had sunk to a near-record low of $7.88 on Wednesday.
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.
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.
