New Mexico’s largest utility has requested state regulators’ permission to join the Western Energy Imbalance Market, officials announced Wednesday.
Public Service Company of New Mexico (PNM) has applied to join the EIM by 2021, Mark Rothleder, the EIM’s vice president of market quality and renewable integration, told the market’s Governing Body during its meeting in Denver.
PNM, which serves about 510,000 electricity customers in the state, still needs approval from the New Mexico Public Regulation Commission, Rothleder said.
The Governing Body greeted the announcement as good news. If PNM’s request to join the EIM is approved, it could give California and other states access to New Mexico’s wind and solar resources, and New Mexico could draw on California’s solar output during peak usage hours.
Wind far in New Mexico | Public Service of New Mexico
Part of the EIM’s mission is to trade renewable energy between states that generate and use it at different times.
California’s solar energy output reaches its peak midday, during a time of low in-state consumption, while solar farms in New Mexico and Arizona come online earlier, some in time to meet California’s high morning demand for electricity. Wind farms in New Mexico and Wyoming ramp up later in the day, when Californians get home and turn on their lights and TVs.
PNM owns or jointly owns 3,200 miles of electric transmission. It owns, leases or has power purchase agreements for about 2,580 MW of generation, dominated by gas (33%), coal (30%) and nuclear (16%). Its wind capacity totals 300 MW (12%) with solar at 117 MW (5%).
“Having cost-effective electricity available to immediately back up [intermittent] renewable energy in real time supports reliability and also ensures our renewables are used to their fullest potential,” Thomas Fallgren, PNM’s vice president of generation, told the Associated Press on Wednesday.
CAISO started the EIM in 2014, and its members have realized more than $400 million in benefits, including more than $71 million during the second quarter of 2018. (See EIM Benefits Surge to $71.2M in Q2.)
PNM would be the first New Mexico utility to join the EIM.
Major utilities in Arizona, California, Nevada, Oregon, Utah, Washington and Wyoming are already members. Idaho Power and Powerex joined this year.
With Gov. Jerry Brown’s support, CAISO also is pushing to become an RTO for the Western states. A bill to advance the change, AB 813, is pending in the legislature, but its fate is uncertain. It must be delivered to Brown before lawmakers end their current session Aug. 31. (See CAISO Regionalization Bill Cast on Uncertain Course.)
SACRAMENTO, Calif. — A measure to replace generating capacity and limit economic disruption caused by the retirement of the state’s last nuclear power plant is headed to the desk of Gov. Jerry Brown.
Pacific Gas and Electric’s Diablo Canyon Power Plant, which sits on a scenic stretch of coastline south of Big Sur, generates nearly a tenth of California’s in-state power and 20% of the utility’s needs.
Diablo Canyon | PGE
Senate Bill 1090, which passed the State Assembly by 67-1 on Aug. 20, would require Diablo Canyon’s output to be replaced with “a portfolio of greenhouse-gas-free resources,” the first measure of its kind in California.
The bill seeks to avoid a spike in emissions, which occurred after the San Onofre Nuclear Generating Station in Southern California closed in 2013 and fossil-fuel burning plants were brought online to compensate.
The measure directs the Public Utilities Commission to approve full funding for measures to lessen the impact on the local economy and to retain skilled workers until the plant is retired in 2025, when its last Nuclear Regulatory Commission operating license expires. The PUC approved PG&E’s application to retire the plant in January but balked at providing $85 million in community-impact funds and millions more for job retention and retraining, asking the legislature for guidance.
The bill, which cleared the State Senate 31-4 in May, was co-authored by Senate Majority Leader Bill Monning, a Democrat, and Assemblyman Jordan Cunningham, a Republican, both of whom represent districts surrounding Diablo Canyon.
“I am hopeful that Gov. Brown will also be supportive of the safe, reliable and carefully planned retirement of the Diablo Canyon Nuclear Power Plant and sign SB 1090,” Monning said in a statement. “The bill is imperative to the local economy, the state’s energy grid and the region.”
An agreement reached in 2016 among PG&E and environmental and labor groups initially laid out plans for the plant’s closure.
The Natural Resources Defense Council, which helped negotiate the agreement, lauded the bill’s passage.
“The package of policies included in SB 1090 offers a model for the phaseout of aging power plants with clean, increasingly less expensive energy while providing a just transition for workers and communities affected by the shutdown,” NRDC’s western energy director, Peter Miller, wrote in blog post Monday.
A spokeswoman for Monning said she had “no idea … one way or another” whether Brown will sign the bill.
Brown, who has until Sept. 30 to sign or veto the measure, declined to comment on his position. “We typically do not weigh in on pending legislation,” Deputy Press Secretary Brian Ferguson told RTO Insider.
MISO’s replacement of its market settlements platform is complete, with the RTO now settling at five-minute intervals.
The RTO reported “smooth and uneventful launches” for both the new platform and settlement time. Officials said the $10.3 million platform replacement is yielding more value than originally expected, though MISO is collecting more financial data through the end of the year before it announces the savings.
MISO rolled out five-minute settlements for weekly billing last month, later than most RTOs/ISOs, owing to extra time needed to replace its settlements platform and test the new program with stakeholders. (See MISO Wins Delay on 5-Minute Settlement Roll-Out.) Last year, the RTO billed $27 billion worth of market-based charges on an hourly basis to more than 450 market participants for the day-ahead market, real-time market, financial transmission rights and its resource adequacy construct.
Executive Director of Market Operations Shawn McFarlane told the Technology Committee of the Board of Directors on Aug. 21 that many settlements corrections are now automated, freeing up settlement analysts’ time. The time to make a settlement recalculation after correcting data has dropped to about 10 minutes from four hours.
“We’ve got some great results,” Kevin Caringer, executive director of MISO’s IT team, told board members.
The new settlements platform also allowed MISO to implement five-minute intervals in about three months, versus the originally estimated nine months, McFarlane said. He added that the RTO is also expected to spend less time coding to make changes on the new settlements system. He said coding changes will likely be necessary as MISO continues its multiyear project to entirely replace its market platform. (See MISO Platform Replacement Risks Delay, Budget Overrun.)
McFarlane said MISO sent market participants sample statements several times during testing of the new interval time, receiving input to correct issues before the program went live.
“This is an important step forward for MISO … that improves the efficiency of our market operations and ensures pricing transparency for the energy being delivered in real time,” McFarlane said.
The committee praised management for better-than-expected results.
“It’s very impressive to see a project of this magnitude come to light,” Director Theresa Wise said.
“Delaying the implementation so that we were in lockstep with stakeholders was a very good decision,” Director Baljit Dail said.
MISO also plans to replace its transmission settlements system in 2019. The system financially settles transmission customers’ use of the transmission system in monthly bills.
RENSSELAER, N.Y. — A NYISO proposal to disqualify some holders of renewable energy credit (REC) contracts from getting paid carbon charges risks undermining the state’s energy market, stakeholders heard on Monday.
In July, the ISO proposed that renewable generators holding REC contracts signed on or before Jan. 1, 2020, be ineligible to collect the carbon pricing portion of wholesale market energy prices. (See NY Sets Carbon Pricing Timeline, Reviews Progress.)
| Institute for Local Self-Reliance
“This would be the first time the NYISO has taken an action that goes against existing contracts,” said Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), which promotes renewables and energy efficiency. “It will increase uncertainty and decrease the willingness of future investors to invest in New York. It’s not very helpful in that regard.”
Reeder delivered a presentation on the topic Aug. 20 to the Integrating Public Policy Task Force (IPPTF), the group exploring how to incorporate the cost of CO2 emissions into the ISO’s markets to support the state’s nuclear plants.
NYISO’s proposal aims to limit customer impacts of the carbon charge by helping reduce or eliminate what it terms “double payments” to renewable resources. According to Reeder, that tells investors that it’s financially risky to develop energy resources that lower carbon emissions in New York. All carbon-free generators should receive the full market energy price, including carbon price effects, he said.
Reeder said the ISO should defer to the state’s Public Service Commission because double payments are a matter of public policy, not market design. REC contracts for 2019 solicitations and beyond should align with the indexed price approach that the PSC approved for offshore wind REC contracts (ORECs), he said. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)
The task force should separately estimate the consumer impacts of receiving the carbon price for existing REC contract holders, nuclear plants under the zero-emission credits regime, combined cycle gas turbines and state-owned hydro generation, Reeder said.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said that, “given the amount of potential double payment at stake here, no one should take it as a given that carbon pricing moves forward absent this issue being resolved.”
Making consumers pay renewable developers higher energy prices to reflect carbon pricing, while also requiring them to pay the same developers for RECs for carbon-free generation attributes, is a clear double payment that must be addressed by NYISO or the PSC, he said.
Renewable developers have benefited from other rule changes, including the Clean Energy Standard and the PSC’s decision to offer three-year contracts to maintain the operation of existing renewable generation facilities (Case 17-E-0603), Mager said. “So these things happen all the time, and I would venture to say that the vast majority of rule changes in the last five to 10 years have been extremely favorable to renewable developers.”
Evaluating a Carbon Charge
Daymark Energy Advisors’ Marc Montalvo, representing the New York Department of State’s Utility Intervention Unit, delivered the preliminary results of a study evaluating NYISO’s proposed carbon charge in outcomes between two cases, a “status quo” case assuming state policies are met but the carbon charge is not implemented, and a case with the carbon charge. The study period included each year between 2020 and 2025, in addition to 2030 and 2035.
Adding a carbon charge would result in higher emissions in New York through 2035, according to a study for the N.Y. Utility Intervention Unit. | Daymark Energy Advisors
The proposed carbon charge could result in slightly lower CO2 emissions in the Eastern Interconnection but higher emissions in New York, the study found. Low capacity prices and the large number of renewables being added to the system now may push prices too low to support new renewable entry within the study period, he said.
“Because so much new generation is being added, we thought it prudent to look at the proposal,” Montalvo said. “We used slightly different assumptions from the ISO’s; for example in the dynamic modeling of proposed border adjustments, which don’t capture likely changes in behavior.”
Several stakeholders questioned the usefulness of such a shuffling exercise, as the ISO’s straw proposal intends to be carbon-agnostic to resources outside New York: Imports would earn the locational-based marginal price but not the carbon adder; similarly, external loads would buy New York energy at the LBMP without paying the carbon charge.
A study for the N.Y. Utility Intervention Unit projects a proposed carbon adder would push incremental average LBMPs in Eastern Zones (F‐K) about $16/MWh higher than Western Zones (A‐E) through 2035. | Daymark Energy Advisors
Montalvo said all the modeled regions add and take away resources based on policy and economic reasons, and “we’ve seen resources stick around for years for reasons impossible to know from the outside.”
He claimed that his group’s “very detailed model of the Eastern Interconnection” provides valuable insight into the effects of pricing carbon into New York’s wholesale electricity markets.
Stakeholders also had access to two comments submitted on the ISO’s carbon pricing straw proposal — one from “private retired citizen” Roger Caiazza, and another from Consolidated Edison. (See Stakeholders Annoyed by NYISO Carbon Price Draft.)
The task force next meets Aug. 27 at NYISO headquarters.
FERC ruled Monday that PJM’s Independent Market Monitor can take part in negotiations over individual generators and doesn’t have to stick only to RTO-wide market issues, parting from a federal appeals court ruling on the Monitor’s role (ER18-1226).
The commission’s order came in response to an administrative law judge denying the Monitor’s request to participate in settlement discussions regarding PA Solar Park’s reactive service rate schedule.
The judge denied the IMM’s motion to intervene, citing a D.C. Circuit Court of Appeals ruling in June blocking the Monitor from participating in an unsuccessful attempt by Duke Energy and Old Dominion Electric Cooperative to recoup millions of dollars in “stranded” gas costs incurred during the 2014 polar vortex. (See Duke, ODEC Rebuffed on Polar Vortex Gas Refunds.)
In denying the motion and a subsequent appeal, the ALJ cited the D.C. Circuit’s characterization of the Monitor’s role as an “auditor” and said PJM’s Tariff provisions “support the notion that the [Monitor] should be limited to commission proceedings and technical conferences that address PJM and its markets at a macro level, but not discrete and individualized proceedings that are limited to specific parties and singular rate filings.”
The commission disagreed, remanding denial of the Monitor’s appeal back to the judge. FERC pointed out it initiated a process in 2014 to ensure resources in PJM’s footprint don’t receive payments for reactive power capability after the units have been deactivated. (See Impatient FERC Orders Immediate PJM Action on Reactive Power Payments to Retired Plants.)
Individual rate proceedings “are part of a broader, continuing effort by the commission to ensure that the rates for reactive power service within the PJM footprint are just and reasonable,” FERC said, adding the Monitor’s involvement would contribute to the “public interest.”
The ruling does not automatically admit the Monitor into the PA Solar Park case, however. Because the Monitor’s June 19 request to intervene was made after the filing deadline, FERC said the judge must rule on whether to admit the IMM anyway.
The Monitor said its filing was late because “no individual notice” of the matter was provided. It agreed to accept the record as it has developed to date and said its involvement would not prejudice existing parties in the proceeding.
After an unusual surge in the first quarter, CAISO prices fell in the second quarter based on lower prices for natural gas and increased output from wind, hydroelectric and solar sources, the ISO’s Department of Market Monitoring told stakeholders Tuesday.
“Q1 prices were relatively high, while Q2 prices were relatively low,” said Amelia Blanke, CAISO’s manager of monitoring and reporting, during a call to discuss the department’s quarterly market report.
She noted prices are generally lower in the first two quarters and rise later in the year. This year was different, however. Q1 prices spiked because of the increased costs of natural gas, due to tight supply and high demand, and limited hydroelectric output, due to scarce precipitation.
Snowpack in the Sierra Nevada was only 54% of normal in early April, Blanke said.
Hydroelectric and renewable sources picked up in the second quarter, adding supply and helping to lower prices. Still, she said, hydroelectric is expected to remain below average this year.
| CAISO Department of Market Monitoring
“We are predicting relatively low hydro for this year, but not as low as we had at the peak of the drought in 2015,” Blanke said.
Also during Q2, north-to-south congestion in the day-ahead market continued to play a significant role, as it had in the first quarter, CAISO reported. It increased day-ahead prices in the San Diego Gas & Electric area by $3.54/MWh, Blanke noted.
Planned outages in Southern California were largely to blame for the congestion, she said.
“Outages in Southern California also caused congestion in the 15-minute market,” the CAISO report said. Congestion increased prices in the San Diego Gas & Electric area by about $4.95/MWh and in the Southern California Edison area by about $1.32/MWh, it said.
Another major development in Q2 was Idaho Power and Powerex joining the Western Energy Imbalance Market on April 4, Blanke said. The report noted prices in the Northwest region including the two companies are generally lower than those in the ISO and other EIM balancing areas because of their “abundant supply and limited transfer capability out of the region.”
SACRAMENTO, Calif. — An unpopular proposal by Gov. Jerry Brown to limit the liability of utilities for wildfire damage has been tabled for now, a state senator said.
Brown proposed the plan in a July 24 letter to state lawmakers. It would have altered California’s unique system of holding utilities strictly liable for fires sparked by transmission lines and other equipment.
Some critics called it a multibillion-dollar bailout for the state’s three big investor-owned utilities, Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
PG&E, in particular, lobbied heavily this year to repeal longstanding rules that make utilities pay for all wildfire damage, even when the companies are only partly to blame for a fire. The legal doctrine, called “inverse condemnation,” says that because utilities can create easements across private property via eminent domain, they also are liable for damage to private property. Efforts to challenge the doctrine in court have been unsuccessful, even though California is the only state in the nation that employs it to such an extent.
NASA’s Earth Observatory showed the fires raging in California’s wine country in Oct. 2017. | NASA
PG&E and other utilities have said their financial stability is threatened by huge wildfire debts. PG&E faces billions of dollars in damages for the highly destructive wine country fires of October 2017, which wiped out the northern portion of the city of Santa Rosa, destroying hundreds of homes.
Investigations by the California Department of Forestry and Fire Protection concluded that some of the most damaging fires in Napa and Sonoma counties last year were caused by trees and branches contacting PG&E power lines.
A PG&E spokeswoman declined comment Monday.
Strict Liability vs. Negligence Test
Brown proposed allowing judges to weigh the benefits of power transmission against the harm done to private property in inverse condemnation actions. His plan would have required a court to decide if a utility had acted reasonably under the circumstances —essentially replacing strict liability with a more lenient negligence test.
A conference committee of state senators and assembly members has been meeting this month to gather information and weigh changes to state law.
The committee’s co-chairman, Sen. Bill Dodd, a Napa Valley Democrat, told several news outlets last weekend that Brown’s proposed liability changes would not be considered during the remainder of the legislative session, which ends Aug. 31. On Monday, Dodd’s spokesman, Paul Payne, told RTO Insider that Senate Bill 901 would move forward without Brown’s liability plan.
“The bottom line is the inverse condemnation [proposal] will not go forward this year. It’s off the table,” Payne said. “The committee will bring the balance of the ideas forward in the final legislative product, which will be SB 901.”
The remainder of the bill deals with wildfire mitigation plans and measures such as reducing fuels and keeping utility lines free of tree limbs and other vegetation.
“There wasn’t enough support for it within the committee,” Payne said of the liability change. “The senator feels some of the prevention measures will do what’s needed to protect the public from future fires, so they’re going to go forward with prevention provisions.”
During a series of hearings in recent weeks, the committee has heard from critics that include cities and counties, farmers, insurers and ratepayer advocates. Many expressed outrage that the utilities might avoid liability even as major fires were raging throughout the state.
Among the groups that testified was The Utility Reform Network. The group’s legal director, Tom Long, urged lawmakers at an Aug. 9 hearing to adopt a disaster relief plan for wildfires such as the Florida Hurricane Catastrophe Fund, which he said could be paid for with small charges on insurance premiums.
TURN spokeswoman Mindy Spatt said Monday the group remains concerned with efforts to relieve utilities of wildfire responsibility. Other bills working their way through the Legislature are far more beneficial to utilities than to ratepayers, she said.
Dodd’s Senate Bill 1088, for instance, would require utilities to submit fire safety plans every two years to the California Public Utilities Commission, which would be required to ensure that cost impacts are just and reasonable, verify compliance with applicable laws and “authorize rate recovery of the reasonable revenue requirements” to implement the plans.
Spatt called it a gift to utilities responsible for starting fires.
“In our view, consumers are still at risk,” she said. “PG&E wants a blank check. They’re lobbying really hard to get that changed.”
The conference committee on SB 901 plans to hold further hearings on Tuesday and Thursday in the State Capitol in Sacramento.
VALLEY FORGE, Pa. — If FERC hoped to receive a consensus proposal from PJM stakeholders on how to revise the RTO’s capacity market, it may be disappointed.
PJM staff unveiled a new proposal at a special session of the Markets and Reliability Committee on Wednesday and were careful to differentiate it from the fixed resource requirement (FRR) FERC suggested in its rejection of the RTO’s previous “jump ball” proposal. (See FERC Orders PJM Capacity Market Revamp.)
The RTO calls the proposed construct the Resource-specific Carve Out, or ReCO, because it would start with a subsidized generation resource exiting the capacity market with a corresponding amount of load rather than the FRR’s inverse situation of a designated amount of load exiting the capacity market with a corresponding resource.
The same three FERC staff members who attended PJM’s last meeting on the issue returned on Wednesday. At the previous meeting, the RTO provided a general overview of its plan and offered representatives of four other proposals time to outline their approaches. (See PJM Stakeholders Search for Capacity Rules FERC Will OK.)
FERC staff are uninvolved in the commission’s decision on the topic and were only there to offer insight.
Whether PJM accepts it is another question.
Matthew Estes, a FERC attorney, advised consolidating the different aspects of several FRR-like proposals, including PJM’s, into a single filing. He highlighted proposals developed by Exelon and a coalition of environmental organizations.
“Try to come up with a proposal that includes as much agreement as possible, or at least filling in the holes,” Estes said, adding that PJM should consider filing a comparison of the proposals. “I think it would be helpful to the parties and the commission to see where there can be consensus and still disagreement.”
But Craig Glazer, PJM’s federal liaison, wasn’t optimistic.
“Is there commonality? I’m guessing there isn’t that much,” he said, noting that the order requires a response from PJM directly, not a stakeholder-endorsed proposal. “The purpose of this [meeting] was to give PJM’s thoughts.”
PJM’s ReCO proposal would define a minimum offer price rule (MOPR) in its annual Base Residual Auctions, how resources would become subject to the rule and what options those resources have to exit the capacity market instead of accepting the MOPR. The proposal focuses on removing price-suppressing impacts of resources offering into the auctions at rates that have been subsidized by other out-of-market payments, such as state programs for renewable or zero-emission generation.
ReCO, RECO, RICO
Whatever the final proposal is, it’s likely the name won’t remain. James Wilson of Wilson Energy Economics noted that PJM already has a RECO acronym for Rockland Electric Co., and Exelon’s Jason Barker pointed out the pronunciation suggests the federal Racketeer Influenced and Corrupt Organizations Act (RICO).
“We have it in the notes to change the name,” PJM’s Adam Keech said.
Glazer emphasized that it’s “not [an] open-ended” option for resources to choose to avoid a must-offer requirement, but a “narrowly carved right” for states to offer subsidies without requiring ratepayers to pay twice for capacity.
Resources would be subject to mitigation through the MOPR if they are at least 20 MW and receiving out-of-market revenues that are at least 1% of actual or anticipated market revenues. Outside payments from any federal program adopted prior to March 21, 2016 — the date set by FERC back to which companies would be eligible for refunds in a 2016 complaint that Calpine and Eastern Generation joined on how the existing MOPR handles subsidized resources (EL16-49) — would be exempt. Federal subsidies after that would have to include “a clear statement of congressional intent” to not be subject to the MOPR.
Those parameters set off a series of stakeholder concerns. Tangibl’s Ken Foladare suggested increasing the 1% threshold so as to not be “trip[ped] up” unintentionally by combinations of state and local programs that aren’t targeting wholesale power markets. Others asked why the date of the Calpine complaint was the cutoff and whether making exemptions for federal programs was discriminatory against state programs.
Glazer said PJM made room for federal programs because it is federally regulated and that it set the cutoff so that staff do not “have to romp through the tax code” to infer Congress’ intent for older programs that likely did not contemplate current legal issues. It would create “an administrative nightmare” and “we’ll never get anything done,” he said, and neither would FERC.
“I’m not sure they wanted to be in the middle of endless fights over the tax code,” he said.
PJM counsel Jen Tribulski said staff “didn’t feel that we needed to draw that same line in the sand” for state programs.
Several stakeholders asked for clarification of PJM’s position on how it would handle programs promulgated by federal agencies that don’t regulate the RTO, such as the Department of Energy, which has been considering ways to subsidize ailing coal and nuclear facilities. Glazer said PJM would accept a program “to the extent that it is legal and it applies to us,” but he declined to wade in farther.
“That’s your legal argument,” he said of stakeholder positions on what should apply to PJM. “Save it for court.”
MOPR Exemptions
Another area of contention was the number of MOPR exemptions PJM is considering. Beyond federal programs, the proposal would also exempt resources listed in PJM’s Tariff as self-supply for public power and vertically integrated entities prior to July 7, 2017 — the date the D.C. Circuit Court of Appeals remanded back to FERC its 2013 order on the RTO’s MOPR. (See PJM Stakeholders Split on Request to OK MOPR Compromise.)
New resources would be subject to net short/long criteria that would look at the owner’s full portfolio to determine whether, in aggregate, its resource fleet exceeds thresholds of having either too much or not enough generation to supply its load. New units that are determined to have exceeded the thresholds would be subject to the MOPR.
Barker asked why PJM plans to apply the MOPR to units that receive state payments for externalities the RTO’s markets aren’t valuing, such as Illinois’ zero-emissions credits and New Jersey’s nuclear diversity certificates for nuclear generators.
“We’re not chasing intent,” Glazer said. “They all have a distorted effect on the market.”
Barker called it “very convenient” that PJM would “hide behind” FERC’s directive for a MOPR with “few to no exemptions” to avoid discussing state programs after it had already outlined several other exemptions.
“It sounds like if there is an attribute that’s not priced by this market, it sounds like you just don’t want that to be considered,” he said.
Glazer called it a “debate that’s beyond the economic regulator and beyond us.”
PJM’s Stu Bresler said the reason is because “the subsidy is directly aimed at a resource to produce electricity” and if the unit can clear the auction without the subsidy it “has no fear of being MOPRed.”
Barker also challenged the details of PJM’s proposal to apply the MOPR to resources that exit the capacity market through ReCO but decide to return after the subsidy that made it eligible for ReCO expires. The applicable MOPR would include any project investment that occurred during the time frame when the subsidy was received.
DR
Under the plan, existing demand response resources would have a MOPR floor of $0/MWh, but planned DR would have a floor of the average offer price for planned DR from the previous three BRAs. Until those data become available, the floor would be based on the average offer price for DR from those BRAs. Keech said that planned DR would likely be considered as customers added that hadn’t participated previously.
Eric Matheson with the Pennsylvania Public Utility Commission warned that might create barriers to entry if the previous offers were exceptionally high.
What Load?
ReCO would work by allowing resources receiving an “actionable subsidy” subject to a MOPR to exit the capacity auction along with a corresponding amount of load. While both the load and the resource would be included for the purposes of clearing the auction, the resource wouldn’t receive any revenue. That money would instead be allocated as a pro rata credit back to all PJM load in the state subsidizing the resource on the basis of such loads’ locational reliability charges.
Such resources would be subject to PJM’s Capacity Performance requirements, but staff said that the resource and the load aren’t required to be located in the same area.
“I don’t know that we’ve come up a reason why that matters quite yet,” Keech said.
Vistra Energy’s Arnie Quinn said it could result in undesirable cost shifting.
“There’s a physical element and there’s a financial element. You’ve honored the physical element, but you haven’t honored the locational pricing,” he said.
Joe Bowring, PJM’s Independent Market Monitor, agreed that it “does not make sense to have load and supply in separate locations.”
FirstEnergy’s Jim Benchek said the cost-allocation portion of the ReCO plan “makes sense” because there will be multiple auctions — the BRA and three subsequent Incremental Auctions — along with states with multiple zones to determine a final price to credit back to ratepayers. The final zonal capacity price is never the same as the BRA or IA prices, he said.
Matheson said it will be important for state regulators to have a role in the crediting process and determination.
Other Ideas
Keech confirmed that PJM doesn’t plan to pursue an approach similar to the Competitive Auctions with Sponsored Resources construct recently approved for ISO-NE.
“I’m not here to tell you it can’t be [implemented],” Keech said. “I’m just going to tell you that we’re not going to pursue it as part of this proceeding. … That doesn’t mean that we can’t discuss it sometime down the road in some other stakeholder proceeding.”
That decision was endorsed by Wilson, who said CASPR is “a very, very complicated process, resulting in very complex rules that to do something that’s really quite modest.”
However, Keech said PJM is still contemplating whether its initial idea for a two-phase auction that eliminates subsidized offers will work in combination with the MOPR or ReCO. It is also looking at a “diversity load adder” to ensure load remains in the capacity market to account for the diversity of PJM’s generation fleet.
FERC’s Emma Nicholson said that “the commission did contemplate that this is a major rule change,” so it “could envision some timing issues” with implementation and that “transition mechanisms might be necessary.”
Next Steps
Staff are planning another session on the topic on Sept. 11 and said they would consider how to address Estes’ suggestion of combining the FRR-related proposals. Susan Bruce, who represents the PJM Industrial Customers Coalition, asked that staff announce as early as possible if they plan to develop a comparison matrix to submit to FERC so stakeholders have time to provide input.
“I think we’re treading on unusual grounds here,” she said.
In a move that should please environmental and ratepayer advocates, FERC has denied requests to shut down debate on whether PJM’s Capacity Performance construct should make room for seasonal resources that can’t adhere to CP’s requirement to always be available (EL17-36).
The commission on Friday dismissed two requests for rehearing of its February order calling for a technical conference on whether the PJM should move from a year-round to a seasonal capacity construct. The commission ordered the conference in response to two complaints, one from the Advanced Energy Management Alliance, and a combined filing from Old Dominion Electric Cooperative, Direct Energy and American Municipal Power. (See FERC Rethinking PJM Capacity Performance Rules.)
PJM and the PJM Power Providers Group (P3) argued that FERC should have dismissed the complaints for not providing new evidence or changed circumstances that would require a decision other than approving CP. P3 challenged FERC’s position that the complaints “raised important issues as to whether certain aspects of the [CP] construct are performing as well as expected.”
FERC rejected those arguments, saying it hadn’t made a final decision on the issue and that the February order was just to open the investigation. It rejected PJM’s argument that the complaints were collateral attacks on CP and said the complainants had proven that CP might be unjust and unreasonable.
“The fact that the commission accepted a rate design in a proceeding under Section 205 of the [Federal Power Act] does not preclude the commission from later re-examining that rate design in a subsequent FPA Section 206 proceeding,” the commission said.
FERC said AEMA identified seven “distinct developments since the conditional acceptances” of CP:
multiple planning studies indicating that CP alone may not suit the region’s resource adequacy needs, and no study showing a winter resource adequacy shortfall;
a new reliability analysis from PJM showing that nearly all the resource adequacy value of marginal capacity lies in the summer months;
auction results that suggest CP will actually degrade resource adequacy by reducing needed peak-season capacity;
new PJM load forecasting information showing that peak-shaving programs have little impact on future capacity purchases, contradicting prior assumptions;
PJM stakeholder resolution of a previously deferred CP cost allocation component;
auction offers showing that significant amounts of capacity have been unwilling or unable to take on CP obligations at any price and that the aggregation mechanism proposed for demand response, energy efficiency and intermittent renewables does not appear to be working; and
indications that the combination of seasonal and annual capacity worked well during the phase-in of CP, as evidenced by PJM’s statements that its available capacity mix has been sufficient to meet demand.
FERC also found value in PJM sensitivity analyses presented in the complaints, settling arguments by PJM that they don’t provide new evidence or changing conditions because they’re solely backward-looking and completely hypothetical.
PJM’s load has its peak demand in the summer. | PJM
“We continue to find that these analyses constitute new evidence sufficient to warrant further investigation,” the commission wrote. “Given that PJM is a summer peaking system, these studies support the contention that the move to a single, annual capacity product may have pushed valuable summer-only resources out of the capacity market and thereby increased capacity costs with little or no reliability benefit. They indicate that allowing PJM to procure some capacity as summer-only capacity would allow PJM to procure significantly less capacity during non-summer periods and provide equivalent reliability at lower total capacity costs.”
FERC also rejected arguments that it’s too soon to determine whether anything’s wrong with CP.
“The concerns raised — including whether customers are paying more than necessary to ensure reliability — are the type of concerns that may be exacerbated, rather than ameliorated, by the passage of additional time,” the commission wrote.
VALLEY FORGE, Pa. — PJM would have to implement programs adhering to specific rules and strict oversight in order to include summer demand reductions in its load forecasts, stakeholders learned last week.
Staff unveiled a proposal for implementing the demand reductions initiative, which has been driven by ratepayer representatives, at an Aug. 15 meeting of the Summer Only Demand Response Senior Task Force. Participation would be restricted to demand response programs approved by a state or regional regulator, and, to avoid double-counting, customers included in the programs would be barred from also participating as DR or price-responsive demand in PJM’s markets during the same delivery year. Instead of receiving a direct payment, their value would be included as avoided capacity costs for the entire zone through a shift in the variable resource requirement curve used in the Base Residual Auction and Incremental Auctions for the delivery year.
Programs would need to indicate several factors by Aug. 31 prior to the delivery year’s BRA, including:
A threshold on PJM’s temperature-humidity index to trigger interruption;
A duration in hours;
The number of megawatts that can be curtailed per hour;
The months an interruption can occur; and
All historical add-backs for the programs.
PJM’s Tom Falin said the add-backs are necessary to “start with a clean load history.”
“Our concern is that some of this peak shaving may already be reflected in the load history,” he said.
Measurement and verification of the curtailment will also be important to confirm that what gets included in the load forecast is what actually occurs to ensure “as accurate a load forecast as possible.”
Staff’s initial forecast reduction will be based on a modified load history that assumes perfect curtailment performance since 1998. After three years of actual monitoring, the forecast will transition to using a three-year rolling average. But performance during the first two summers will be “key,” Falin said, because “we’re going to take the performance result for that summer and assume that would have happened for the previous 18 years.”
EnerNOC’s Brian Kauffman presented an alternative proposal that would allow summer DR to participate in both load forecast adjustment (LFA) and as Capacity Performance resources. To avoid double-counting, Kauffman offered several proposals on measurement and verification, add-backs and payment rules to differentiate between megawatts committed under the LFA versus CP versus energy markets.
PJM staff were immediately against the idea, but Kauffman implored them to “first explore this and determine if it’s impractical.”
The Independent Market Monitor’s Skyler Marzewski offered a revised proposal that would prohibit participation in multiple markets and exclude add-backs. PJM’s Andrew Gledhill said “we’re going to have to get the accounting right” because there might be potential for gaming.
Eric Matheson with the Pennsylvania Public Utility Commission withdrew his proposal but provided a presentation on timing conflicts between state peak-shaving programs, such as Pennsylvania’s Act 129, and PJM’s requirements.
PJM’s Rebecca Carroll said the group’s next meeting on Aug. 29 will cover dual registrations in capacity and energy programs, and whether load-reduction offers can be increased and decreased in IAs or just increased. Staff are hoping for a vote in time to review it at the group’s Sept. 19 meeting and report to members at the September meeting of the Markets and Reliability Committee.
Staff also confirmed that any changes the group develops wouldn’t be able to be implemented until the 2020 BRA.
