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.
CALGARY, Alberta — Canadian Electricity Association CEO Sergio Marchi took advantage of several opportunities during last week’s NERC Board of Trustees meeting to complain that he and other Canadian stakeholders have been excluded from Department of Homeland Security cybersecurity briefings.
“We’re forbidden to participate because we are considered, quote unquote, foreigners,” said Marchi, whose association represents integrated utilities, independent power producers, transmission and distribution companies, power marketers and industry suppliers. “The irony is the two CEOs [representing Canada’s electricity sector] happen to be American citizens.”
Marchi said that over the last year, he and the two U.S.-born CEOs on the Electricity Subsector Coordinating Council (ESCC), ENMAX’s Gianna Manes and Hydro One’s Mayo Schmidt, have been shut out of the classified briefings.
NERC responded that the Canadians have been excluded because they don’t have the proper security clearance. It added that it is working with industry and government partners to increase the functionality of the Electricity Information Sharing and Analysis Center (E-ISAC) portal, which gathers, analyzes and shares security data across the North American grid.
“NERC as a private company does not have authority to grant or sponsor clearances or to provide access to classified briefings in the United States or in Canada,” CEO Jim Robb said in a statement provided to RTO Insider. “However, NERC will ensure that all NERC events are inclusive of all our North American stakeholders. Simply getting information is only piece of the security pie, and the E-ISAC is in a unique place to analyze and triangulate information to identify threats and mitigation actions to share information that North American stakeholders need to protect their systems.”
Marchi told RTO Insider that the exclusion from the ESCC briefings has become more of an issue under the Trump administration.
“It’s frustrating, and whether it’s NERC or Bruce Walker [the Department of Energy’s NERC representative], they haven’t been able to pinpoint who is blocking us and why,” he said. “This is an example, where everyone says we should be in the meeting, but we don’t know who [is preventing us] and why we are kept out of the meeting. We’re hopeful we can make progress, and the next time the council meets, we can be on the same team.”
Robb acknowledged the issue while briefing trustees on the ESCC’s recent discussions. He said improving information sharing with Canadian industry members is “complicated territory.”
Marchi said the CEA was willing to give Robb a “proper runway” to improve the process.
A former member of the Canadian Parliament and cabinet minister, Marchi also objected to what he said was a 25% budget increase for the E-ISAC as part of NERC’s overall 9.5% budget increase.
“Our Canadian utilities receive the same information from Canadian sources, but it’s quicker and of higher quality,” Marchi said. “Why should we pay twice for information that is of less quality, and that is late on arrival?”
In his statement, Robb pointed out that Canadian stakeholders were able to file comments on the 2019 budget and business plan as part of NERC’s “open and transparent” budget process. He said the organization takes their concerns seriously.
“[We] had multiple meetings, phones calls and written exchanges with [Canadian stakeholders] to discuss the 9.5% increase,” Robb said. “While we acknowledge [their] concerns, we believe the budget approved by the NERC Board of Trustees is the right answer for industry based on all feedback we received.”
Robb acknowledged that the Canadian government has, at times, “authorized release of information to Canadian industry sooner than the U.S. government.” He said NERC recently executed a memorandum of understanding with the Canadian Cyber Incident Response Centre to help improve E-ISAC access to the Canadian government’s security information.
Marchi said the CEA will monitor the next budget cycle and “consider our options” at that time. He said the E-ISAC’s relationship with U.S. security organizations is “an important piece of that puzzle.”
“It’s very important those relationships are picture perfect, if a new investment to the E-ISAC will create the outcomes they’re intended to,” he said. “We need to continue to work closely as our industry evolves at a rapid pace and cyberattacks continue at a great pace. This work must be done in a cost-effective and efficient manner, because both regulators and customers demand and expect it.”
NERC Board Chair Roy Thilly said improving the involvement of Canadian utilities in the E-ISAC “is a very high priority” for the trustees. “We ask the Canadian utilities to work with us to help you provide that value.”
Earlier in the week, the NERC board and Canadian regulators held their annual meeting. NERC said Canadian regulators were briefed on cybersecurity, including the E-ISAC long-term strategic plan and the organization’s reliability assessment and performance analysis capabilities.
Robb Reflects on Cross-border Interconnections
Robb noted several significant milestones during his president’s report, pointing to NERC’s 50th anniversary and the 15th anniversary of the 2003 blackout in the Northeast. As Robb put it, a vegetation contact in Ohio led to power failures in Ontario and “returned the favor” for 1965, when a transmission line tripped in the Canadian province and blacked out Manhattan.
“These anniversaries and our meeting in Canada have given me a chance to reflect on the interconnected nature of our grid and the importance of our international collaboration,” he said. “The Electric Reliability Organization [ERO] is an agency for driving a common approach to reliability and security. We have a tremendous amount of work to do together, and it is a high priority for all of us.”
Robb said the early returns on NERC’s six-month-old, five-year strategic plan have been “very positive,” but that there is a “tremendous amount of work to do.”
“It’s a very complex system to defend,” he said of the grid.
The continuing retirements of coal- and nuclear-fired generation, combined with the rapid deployment of variable resources and natural gas plants, is a problem “no one agency or individual forum can solve,” Robb said.
He said NERC has started work on a guideline to bring “greater clarity” regarding what kind of contingencies need to be studied.
“There are serious issues in the Northeast and desert areas of the Southwest,” Robb said. “We need to move along very quickly on this.”
CEO: AESO’s Challenges Same as Everyone Else’s
The Alberta Electric System Operator (AESO) faces steep challenges in meeting legislative mandates to phase out its coal-fired generation — which accounts for 40% of its installed capacity — and produce 30% of its energy from renewables by 2030. Adding to the challenge, it has very little hydro and no nuclear power in its generation mix.
But that’s no different than the challenges facing other jurisdictions, CEO David Erickson said.
“With the integrated nature of the grid in North America, working together to solve those problems is important,” he said. “That’s the only way to get through this transformation, with the increasing penetration rate of renewables, cyber threats and changing generation mix. Those are real challenges we need to work together to solve. The ISO/RTO community has a big role.
“That said, NERC has an enormous role to get through this. I encourage the industry, I encourage NERC to work together. Whether we like it or not, we’re in this together. There’s a better path that’s more efficient and a lot more effective, if we do this together.”
MISO is probing what eligibility requirements it should establish before allowing electric storage resources to function as transmission assets.
The RTO is considering study processes, modeling, cost recovery and retirement rules, all raised with stakeholders during a special Aug. 17 Planning Advisory Committee conference call to discuss the issue.
MISO is leaning toward requiring a storage resource to complete the interconnection queue if it wishes to provide market services, regardless of whether a resource has already been approved as transmission through the annual Transmission Expansion Plan (MTEP).
The RTO has so far only connected storage to its system through its generator interconnection procedures, and the procedures do not contemplate electric storage resources as transmission assets, MISO Director of Planning Jeff Webb said.
“We have connected batteries recently through Attachment X. However, that process doesn’t contemplate these devices being solely used for transmission services or mixed services,” Webb said.
“One of the complaints for having them go through the queue is a timeline and compatibility process,” he said, explaining that a transmission-use storage resource would likely have to wait through a few MTEP cycles before it could become eligible through the interconnection process. The annual MTEP reliability modeling considers only generators already approved for interconnection, not future resources.
Webb said some storage owners might ask why their resource will have to undergo reliability studies as part of the interconnection queue when they’re already operational under the MTEP assessment.
“Would the subsequent interconnection process be superfluous? What function would it serve?” Webb asked rhetorically. “Maybe there’s a type of expedited interconnection. I don’t know.” He asked stakeholders for their ideas.
American Transmission Co.’s Bob McKee predicted that MISO will see many storage resources connecting under mixed-use market and transmission functions.
“To get the value out of that device, you’re going to use it for as many services as you can. I think we’re really going to have to make sure the process doesn’t impede the value for the customer.” He warned against completing separate assessments simply for the sake of following MISO’s current process.
Some stakeholders asked if it was a matter of treating all generation fairly as a matter of principle, or necessary to allowing storage’s possibly superior capabilities to compete in more than one area. Others said MISO may need to complete queue analyses with and without the presence of storage resources to find out whether storage as transmission is truly as reliable as traditional transmission.
Webb said MISO will likely make special modeling considerations for storage resources beyond traditional wires modeling.
“When we’re talking about wires or transformers or cap banks, those are available all day, every day to provide for any and all reliability issues or conditions on the grid that they can assist with. Storage as transmission would similarly be called upon by MISO to address any reliability issues they would be effective for,” Webb said.
He said storage as transmission in particular would have to be under some form of MISO control to make sure it is charged to perform its reliability functions over peak hours, for example. MISO plans to notify the resources when and at what charge state they will be needed to provide transmission reliability services and will provide enough time to ensure the resource can reach the necessary state of charge.
Webb said that if MISO chooses to defer a 40-year transmission project in favor of a storage solution, it must also gauge the anticipated life of a device for modeling, considering which major components will likely have to be replaced and when. He said MISO may find itself approving the original deferred transmission project if a storage asset doesn’t stand up over decades.
MISO must also decide how storage assets will recover costs so that customers don’t pay twice for the same services, Webb said, paying particular attention to the treatment of market revenues if either partial or full revenue requirements are recovered under cost-based transmission rates. Storage asset owners might decide to recover only a portion of transmission rates so the asset can compete with a cheaper wires solution, Webb said.
MISO is currently considering at least three approaches to cost recovery:
Full cost-based recovery for transmission reliability services, with full crediting of market revenues;
Partial cost-based recovery for transmission reliability services, calculated as asset cost minus asset owner-estimated market revenues with crediting proportional to cost-based revenue; or
Partial cost-based recovery for transmission reliability services, calculated as asset cost minus asset owner-estimated market revenues with no crediting of market services revenues because the amount was estimated to be necessary to recover asset costs.
Storage resources would also likely have to be registered in the MISO market for charging and discharging, even if they are strictly treated as transmission, Webb said. The question also remains about what storage assets would pay and be paid for energy used for charging and discharging when they must operate for transmission system reliability under MISO instruction. Webb said in those cases, storage owners could either be price-takers in the market, charged and paid at LMPs for injections and withdrawals, or they could be neither paid nor charged for such injections and withdrawals. He also said MISO and stakeholders could come up with a third option for consideration.
The RTO is also looking to draft a storage-as-transmission retirement process, Webb said. Traditional wires assets are rarely decommissioned in the footprint, according to MISO, and Webb said storage resources may become subject to system support resource studies or an equivalent to discern whether the devices are necessary for reliability purposes.
Webb also said stakeholders raised an issue of MISO investigating whether there are possible conflicts of interest if a transmission owner is also allowed to become a market participant operating a storage resource for market services. However, Webb said MISO did not think the issue was markedly different than utility-owned generation participating in the market today.
MISO will continue to discuss policy for storage-as-transmission at the September PAC meeting. Webb asked for stakeholder suggestions through Sept. 7.
The Trump administration’s replacement for the Clean Power Plan will require modest efficiency improvements that could boost the output of coal-fired generators while giving states discretion over enforcement, according to published reports.
The New York Times, The Washington Post, Politico and Bloomberg all reported that the replacement will be announced this week, perhaps at a Trump campaign rally in West Virginia coal country Tuesday. The Wall Street Journalreported Monday evening that acting EPA Administrator Andrew Wheeler had signed the new plan, which EPA has dubbed the “Affordable Clean Energy” (ACE) rule.
According to the reports, EPA has decided not to seek reversal of the 2009 finding that greenhouse gases endanger public health, as coal magnate Robert Murray and others have urged. Leaving the endangerment finding in place means the agency must address CO2 emissions. Wheeler is a former Murray Energy lobbyist.
The reports said EPA will order that individual coal plants make heat rate improvements to increase the electricity produced from the same amount of coal — reducing carbon emissions per megawatt-hour. Observers say that could increase coal plants’ dispatch as their lower production costs make them more competitive.
| Energy Information Administration Annual Energy Outlook 2018
‘Inside the Fence Line’
The Obama administration’s plan would have required utilities to switch from coal to gas and renewables to produce a 32% cut in power sector carbon emissions below 2005 levels by 2030. The Trump administration says the CPP overstepped EPA’s authority by imposing regulations “beyond the fence line” of individual plants. (See EPA to Announce Clean Power Plan Repeal.)
The U.S. Supreme Court stayed the CPP pending legal challenges in February 2016. The D.C. Circuit Court of Appeals heard arguments in the case, but Trump’s EPA asked the court to delay its ruling so it could rewrite the rule. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
EPA previously estimated that “inside-the-fence-line” plant modifications, such as equipment upgrades and adoption of best practices, would improve average coal plant heat rates by 4%.
Politicoreported that the White House Office of Management and Budget finished reviewing the draft and sent it back to EPA last week.
The plan reportedly would allow states to decide whether to adopt changes to “New Source Review,” a policy that requires power plants to adopt pollution controls when they make upgrades that could increase emissions.
President Trump signing his executive order seeking to undo the Clean Power Plan as coal miners, Interior Secretary Ryan Zinke, then-EPA Administrator Scott Pruitt and Vice President Mike Pence watch.
The CPP replacement, following the proposed rollback of automobile efficiency standards, is another indication of the Trump administration’s determination to reverse Obama-era environmental policies and its reluctance to address climate change. EPA says transportation (26%) and electric generation (30%) are responsible for more than half of all greenhouse gas emissions in the U.S.
On Aug. 2, EPA and the National Highway Traffic Safety Administration announced they would cap fuel economy requirements at a fleet average of 37 mpg starting in 2020. Under the Obama rules, the standard had been set to rise to about 47 mpg by 2025.
Bloomberg noted that the release of the CPP replacement “comes during a summer dominated by wildfires and hotter-than-normal weather. Northern Europe has withered in a deadly heat wave. California recorded its hottest July on record as its forests burned on an unprecedented scale. At least 116 people in Japan have died this summer, with the country posting its highest-ever temperatures in July. Meanwhile, parts of India are dealing with the worst flooding in a century.”
Reduced Reductions
The Energy Information Administration says carbon emissions were 27% below 2005 levels at the end of 2017 and will drop another percentage point to 28% through 2030 without the CPP.
The Washington Post reported that the plan would allow the release of at least 12 times the amount of carbon dioxide into the atmosphere compared with the Obama rule over the next decade.
By 2030, the Post said, the new proposal would cut CO2 emissions from 2005 levels by 0.7 to 1.5%, compared with business-as-usual. The CPP would have cut carbon emissions by about 19% by the end of the next decade.
EPA’s new plan would reduce sulfur dioxide and nitrogen oxides that help form smog by 1 to 2% each from 2005 levels over the same time period. Cuts under the CPP for those pollutants would have been 24% and 22%, respectively, the Post said.
The new proposal, which is subject to a 60-day comment period, will almost certainly face legal challenges from environmentalists.
The Environmental Defense Fund said EPA should be more, not less, aggressive in reducing emissions despite industry trends favoring gas and renewable generation over coal.
“To be clear, we need the long-term regulatory signal established by the Clean Power Plan in order to ensure these trends continue — and to secure the full benefits of the pollution reduction that the Clean Power Plan would require,” wrote Rama Zakaria, EDF’s senior manager for regulatory policy and analysis, in a blog post last week. “If acting EPA Administrator Wheeler decides to replace the Clean Power Plan, EPA must fulfill its legal imperative to establish carbon pollution limits that achieve maximum feasible pollution control and adequately address the urgent threat of climate change.”
The EPA on Tuesday announced its replacement for the 2015 Clean Power Plan, saying it will be cheaper and give states more control while producing similar CO2 emission reductions even as it increases coal-fired electric generators’ market share.
“The CPP exceeded the agency’s legal authority, which is why 27 states, 24 trade associations and 37 rural electric coops and three labor unions challenged the rule,” Acting EPA Administrator Andrew Wheeler said during a press briefing announcing the Affordable Clean Energy (ACE) rule. “… The era of top-down, one-size-fits-all federal mandates is over.”
Compared to the CPP, EPA says the ACE rule will result in 0.2% to 0.5% lower electric prices in 2025 while increasing coal production for power sector use by 4.5% to 5.8%.
The ACE rule defines the “best system of emission reductions” (BSER) as heat-rate efficiency improvements that can be achieved at individual coal plants, in contrast with the CPP, which set state emissions limits and encouraged switching to natural gas and renewables.
The new plan will cover about 600 coal-fired generating units at 300 facilities. EPA is not proposing a BSER for natural gas-fired combined cycle plants. Instead, the agency is seeking comment on available emission reductions for them.
IMEA owns 12% of LG&E and KU’s Trimble County 1, a 514-MW coal-fired unit between Louisville and Cincinnati. | LG&E-KU
The rule also slows down the implementation schedule and introduces a new test for determining whether physical or operational changes to a power plant qualify as a “major modification” triggering New Source Review.
EPA’s regulatory impact analysis (RIA) for the proposal concludes that ACE will cut compliance costs by up to $400 million annually compared to CPP while reducing 2030 carbon emissions by up to 1.5% from projected levels without the CPP. “When states have fully implemented the proposal, U.S. power sector CO2 emissions could be 33% to 34% below 2005 levels, higher than the projected CO2 emissions reductions from the CPP,” EPA said in a press release.
EPA notes that power sector emissions have declined without the CPP due to industry trends favoring increased natural gas and renewable generation. “The ACE rule will continue this trend,” EPA said.
Yet Assistant EPA Administrator Bill Wehrum undercut the agency’s projection, telling reporters that the flexibility being afforded states makes predictions difficult. “We believe the law requires states to have primary authority for implementing this program and determining what emission limitations or other measures actually should be applied at the power plants within their jurisdiction. That flexibility and that latitude means, beyond a certain point, it’s difficult to predict what states are going to do,” said Wehrum, who heads the Office of Air and Radiation.
EPA’s RIA calculated benefits and costs of three replacement scenarios and one repeal scenario, all of which would result in CO2 emission reductions from current levels. “The RIA projects small increases in emissions of CO2, sulfur dioxide (SO2) and nitrogen oxides (NOX) under all four scenarios compared to CPP,” EPA said. “However, comparing the replacement scenarios to the full repeal scenario shows a replacement would lead to significant reductions in emissions for these pollutants in the future.”
`Overly Burdensome’
EPA said it would be “overly burdensome” to require states to evaluate all options for reducing emissions.
Instead, the agency identified a list of the “most impactful” heat rate improvement measures states should consider. EPA’s list of “candidate technologies” includes: improved operating and maintenance; boiler feed pumps; air heater and duct leakage controls; variable frequency drives; blade path upgrades for steam turbines; redesign or replacement of economizers and “neural network/intelligent soot blowers.”
Leaking steam valves | Electric Power Research Institute
“Opportunities for heat rate improvements are source-specific and dependent upon the individual unit’s design, configuration, age and operating and maintenance history,” EPA said.
States’ Role
The rule will allow states to establish “standards of performance” based on the emission limitations achievable through the BSER. “EPA is not setting a presumptive standard of performance. States will be given the flexibility to design a plan that, in the state’s judgment, will work best under its particular circumstances,” the agency said, citing as considerations the plant’s current technology and practices and its remaining useful life.
States will have three years from the date of the final rule to submit their plans EPA approval, compared with nine months under the CPP. EPA will have 12 months to approve or reject state plans, up from four months under CPP. For states that fail to submit an approvable plan, EPA will have two years to develop its own plan, up from six months.
Coal Heat Rates by State | EIA
Because efficiency upgrades reduce the amount of coal burned — and CO2 released — per unit of electricity generated, the rule will improve the plants’ competitiveness against alternative fuels, potentially increasing coal’s share of the generation mix.
The RIA’s scenario assuming 4.5% heat rate improvement at $50/kW projects coal production for power sector use will be 5.8% higher than under CPP by 2025, rising to 9.5% by 2035 — the same as the 2035 scenario with no CPP.
A scenario assuming the same heat rate improvement at a cost of $100/kW would see coal’s use increase 4.5% in 2025, rising to 7.4% in 2035.
“The Clean Power Plan would have caused more fuel-secure coal-fired power plants to retire prematurely even though policy makers have become increasingly concerned that coal retirements are a threat to grid resilience and national security,” said Michelle Bloodworth, CEO of the pro-coal group ACCCE, which estimates almost 40% of the nation’s coal fleet has retired or plans to do so.
Changes to New Source Review
EPA proposes allowing states to adopt an hourly emissions increase test for determining whether power plant upgrades are a “major modification” triggering New Source Review under Clean Air Act Section 111(d).
Only projects that increase a plant’s hourly rate of pollutant emissions would need to undergo a full NSR analysis, which could result in additional pollution controls.
Under current rules, NSR review can be triggered if annual emissions increase because of increased dispatch even if hourly emissions drop.
“Existing plants might therefore forego investing in efficiency improvement projects, rather than risk triggering NSR by undertaking such projects,” EPA said. “Worst case, if compelled to undertake efficiency improvement projects in order to comply with state-developed standards of performance, some existing facilities might choose to shut down altogether, in advance of the end of their expected useful life.”
EPA will accept comments on the proposal for 60 days after publication in the Federal Register.
The CPP replacement, following the proposed rollback of automobile efficiency standards, is another indication of the Trump administration’s determination to reverse Obama-era environmental policies and its reluctance to address climate change.
The CPP would have required a 32% cut in power sector carbon emissions below 2005 levels by 2030. The Trump administration says the CPP overstepped EPA’s authority by imposing regulations “beyond the fence line” of individual plants.
The U.S. Supreme Court stayed the CPP pending legal challenges in February 2016. The D.C. Circuit Court of Appeals heard arguments in the case, but Trump’s EPA asked the court to delay action so it could rewrite the rule. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
Reaction
Some conservatives were disappointed in the new rule, urging instead that the administration seek reversal of the 2009 finding that greenhouse gases endanger public health.
But their criticism was muted compared to that from CPP supporters.
“The administration’s own analysis shows this proposal would be wholly ineffective in addressing carbon pollution from power plants, and therefore harmful to our citizens, who are already suffering from the dangerous impacts of climate change,” officials from 14 states said in a letter to Wheeler.
“In regulating greenhouse gas pollution, the EPA is legally required to use the ‘best system of emission reduction,’ not a mediocre or downright counterproductive system of emission reduction,” said Richard Revesz, director of New York University’s Institute for Policy Integrity. “This proposal is an enormous step backwards, and it will have severe repercussions for public health and the climate.”
But Tracy Terry, director of energy at the Bipartisan Policy Center, said the rule “isn’t necessarily a slam dunk for coal,” noting that plants’ fates will depend on the aggressiveness of their state’s implementation plan. “There are a number of coal-heavy states with gubernatorial elections in November. The outcomes of those races could have an impact on how the rule is eventually implemented,” Terry said.
Attorney Timothy McMahan, chair of Stoel Rives’ Climate Change Practice Initiative, predicted Pacific states will erect a “green wall” against the Trump administration’s efforts.
He noted that California’s cap and trade has been extended through 2030. “As the fifth largest economy in the world, California’s efforts are a significant test case for the premise that carbon regulation can coexist with economic growth and jobs creation,” he said in a statement. “This summer, in both Oregon and Washington, the groundwork is being laid to enact sweeping new greenhouse gas legislation. … With other states pursuing their own climate legislation, and given market forces making coal investments questionable, the impact of the ACE rule to reverse state efforts is uncertain, particularly if states will truly be free to enact their own legislation free from administration efforts to manipulate energy markets in favor of coal generation.”
Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, tweeted that “GHGs, the Clean Power Plan, and 111(d) are the distractions in today’s proposal.
“Rewriting the New Source Review regards will likely result in far more emissions,” he said.
David Doniger, senior strategic director of the Natural Resources Defense Council’s Climate and Clean Energy Program, responded to Peskoe, noting that Wehrum, while a member of the George W. Bush EPA, “tried this loophole before.
“Lost in court,” Doniger said. “Won’t go better this time.”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:20)
Members will be asked to endorse the following manual change:
3. Market Efficiency Process Enhancement Proposal (9:20-9:50)
Members will be asked to endorse the market efficiency phase 1 proposal developed at the Market Efficiency Process Enhancement Task Force (MEPETF), along with the associated revisions to the Operating Agreement and Manual 14B: PJM Region Transmission Planning Process. The changes would exclude from the base case those units with facility study agreements (FSAs) and suspended interconnection service agreements and their associated network upgrades at the time of the case build, unless they are needed for reliability. (See “Market Efficiency,” PJM PC/TEAC Briefs: July 12, 2018.)
Members also will be asked to endorse revisions to Manual 14F: Competitive Planning Process adding language identifying eligible congestion drivers and clarifying language regarding benefit/cost analyses. (See “Manual 14F Changes,” PJM PC/TEAC Briefs: Aug. 9, 2018.)
4. Order 1000 Transmission Project Cost Containment Provisions (9:50-10:20)
Members will be asked to endorse a proposal to extend by one year the implementation deadlines for the cost containment comparative framework for competitive transmission projects. The proposal is being offered by the proponents of the cost-containment proposal that the MRC endorsed in May. (See Cost Containment Clears MC Vote Despite PJM Plea.)
5. FTR Liquidation Process (10:20-11)
Members will be asked to endorse a proposed problem statement and issue charge related to PJM’s problems with liquidating a large financial transmission rights portfolio on which GreenHat Energy defaulted. Members will also receive an update on alternatives for handling the liquidation.
If the problem statement and issue charge are approved, stakeholders plan to seek a vote on a motion to request that PJM ask FERC for permission to discontinue liquidating any positions in the defaulted portfolio through Nov. 30. The motion is intended to give stakeholders time to develop new liquidation rules for submission to FERC. (See PJM Reeling from Major FTR Default.)
6. Transmission Replacement Process (11-11:40)
Members will be asked to endorse a proposal from American Municipal Power for ensuring that PJM’s planning process for facilities at the end of their life are transparent and consistent and give stakeholders an opportunity for input under FERC Order 890. The proposal will require changes only to Manual 14B. Stakeholders will also hear PJM’s perspective. (See PJM Stakeholders End Tx Replacement Task Force.)
Members Committee
1. FTR Liquidation Process (1:15-1:30)
Members will be asked to approve a motion requesting that PJM ask FERC for permission to discontinue liquidating positions in GreenHat Energy’s defaulted FTR portfolio through Nov. 30. (See MRC item 5 above.)
