FERC on Monday approved settlement agreements among CAISO, Pacific Gas and Electric and Calpine covering reliability-must-run (RMR) contracts for three Northern California gas-fired plants, reducing the revenue they will receive and making them subject to a must-offer requirement.
While the commission said the agreements resolved all issues in dispute in the proceedings and appeared to be “fair and reasonable and in the public interest,” the out-of-market RMR payments are not popular with many CAISO stakeholders and were opposed by the California Public Utilities Commission (CPUC) after the ISO’s Board of Governors reluctantly approved them in November. (See Board Decisions Highlight CAISO Market Problems.) The CPUC in January voted to require PG&E to hold solicitations to replace the agreements with energy storage. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.)
The Metcalf settlement reduces the plant’s annual fixed revenue requirement from about $72 million to $43 million through 2020 if it retains its RMR status and makes the plant operator responsible for routine repairs and capital expenses. Under the agreement, the plant will recover $8 million in 2018 capital items in 12 installments of $675,000 beginning on Jan. 1, 2018. If the RMR agreement is extended, capital recovery would remain at about $8 million per year. The settlement also grants the plant $8 million in 2019 and 2020 if the revised agreement is not renewed and the unit shuts down.
Calpine’s Feather River Energy Center | Calpine
The Feather River and Yuba City settlements would reduce each plant’s 2018 revenue to about $3.5 million from the previous $4.4 million, with a 2% hike for 2019 and 2020, if the RMRs are renewed.
The settlements would also take all three plants from Condition 2 (eligible for full cost-of-service payments) to Condition 1 (eligible for only a portion of their revenue requirement) status and impose a must-offer requirement, which the ISO’s Department of Market Monitoring has recommended for all RMR units. CAISO is working to revise its RMR program to establish a must-offer requirement for resources. (See CAISO, Stakeholders Debate RMR Revisions.)
CAISO Tariff Waivers
In a separate order, FERC also granted CAISO a limited Tariff waiver to permit nine scheduling coordinators (SCs) to submit out-of-time requests to recertify 18 resources for the 2018 resource adequacy compliance year (ER18-857). CAISO said the SCs had failed to renew an exemption related to its Resource Adequacy Availability Incentive Mechanism (RAAIM) program by the Nov. 15, 2017, deadline because of confusion about the recertification process for acquired resources within the program.
FERC said the waiver grants certainty to those resources that they their RAAIM exemption will not be unwound. CAISO replaced its Standard Capacity Product with RAAIM in November 2016. SCs must present an affidavit for each resource adequacy year testifying that each resource meets eligibility for exemption from certain performance incentives.
Energy Crisis Settlement
The Commission also approved an uncontested settlement filed Feb. 6 among CAISO, Wayzata Opportunities, PG&E, Southern California Edison and San Diego Gas and Electric related to the 2000/01 California energy crisis (EL02–18). The agreement ensures the payment of interest to the resource owners who had received delayed compensation for certain power supply contracts because of the default of the California Power Exchange. The filing parties said approval of the settlement would avoid further litigation, eliminate regulatory uncertainty and enhance financial certainty.
ERCOT will have more breathing room as it prepares for record demand this summer after an additional 525 MW of generation recently came online in Texas.
The ISO said Monday it now has 78.2 GW of capacity available to meet an expected peak demand of 72.8 GW, which would break the 2016 record of 71.1 GW. The additional capacity has boosted ERCOT’s planning reserve margin from 9.3% to 11% since the previous seasonal assessment of resource adequacy (SARA) report.
“That definitely improves the situation,” said Pete Warnken, ERCOT’s manager of resource adequacy, during a media call Monday.
The additional generation comes from the 225-MW, gas-fired Denton Energy Center that recently went into service in North Texas and the return of the mothballed 300-MW gas unit at Barney Davis in Corpus Christi.
South Texas Nuclear Generating Station
Warnken said rotating outages are still possible under extreme scenarios, “but that risk has been reduced a little bit with those resources.”
ERCOT has approximately 2.3 GW of capacity available through load-control measures with transmission or distribution service providers. Tight reserves could also trigger the need for the ISO to deploy ancillary services and contracted emergency response service capacity to maintain sufficient operating reserves.
Staff also expects industrial facilities to make voluntary load reductions and increase the power they sell into the market during peak demand.
“We expect the market to respond to scarcity conditions,” Warnken said. “It’s a good bet to expect they’ll be looking at summer conditions and making decisions appropriately before they bring their resources on.”
Dan Woodfin, the ISO’s senior director of system operations, said the grid will also benefit with the completion of the Houston Import Project, a $590 million effort that will allow more power to be imported from the north.
“All the pieces are in service at this point,” Woodfin said. “That will help reduce congestion into the Houston area because it improves the transfer capability.”
ERCOT also released its latest Capacity, Demand and Reserves (CDR) report, which includes planning reserve margins for the next five years. The reserve margin peaks at 12.3% in 2020, before dropping to 8.9% in 2023.
The CDR report adjusts the 2019 summer demand forecast down to 74.2 GW, reflecting a delay in a new industrial facility on the Texas coast. Staff expects the load forecast to eclipse 77 GW in 2023. That number includes the planned integration of Lubbock Power & Light’s customers, which is scheduled to take place in 2021.
The ISO’s target planning reserve margin is 13.75%. Warnken said staff is studying an economically optimal reserve margin, which would balance the amount of generation needed to maintain reliability with its cost.
The next CDR report will be released in early December.
A recently passed New Jersey law could lead to the state subsidizing nuclear plants outside its borders, Public Service Enterprise Group (PSEG) CEO Ralph Izzo said during his company’s first-quarter earnings call Monday.
“The bill simply says that New Jersey wants 40% of its power supplied by nuclear energy and it does not limit it geographically,” Izzo said.
Izzo made the statement in response to a question from Morningstar’s Director of Energy Research Travis Miller, who said he thought nuclear plants outside New Jersey could be eligible for the zero emission credits (ZECs) authorized by the legislation.
PSEG head Ralph Izzo says NJ Gov. Phil Murphy supports the jobs at the Hope Creek nuclear plant. | NRC
In addition to the Salem and Hope Creek nuclear plants that PSEG operates in Salem County, N.J., Izzo said the Peach Bottom nuclear plant in Pennsylvania, of which PSEG is half owner, could compete for ZECs. So, he added, could two other Pennsylvania nukes: Talen’s Susquehanna and Exelon’s Limerick.
The ranking system the legislation encourages the New Jersey Board of Public Utilities (BPU) to use in determining which plants get ZECs is driven by their impact on the state’s air quality, Izzo said.
Gov. Phil Murphy has not signed the legislation, which was passed April 12. He has 45 days from then to sign it into law; veto it, which both houses of the legislature could override with two-thirds majorities; conditionally veto it, which amounts to sending it back to the legislature with changes requiring majority approval; or not sign it, in which case it would become law after the 45 days pass. (See NJ Lawmakers Pass Nuke Subsidies, Boosted RPS.)
Izzo declined to opine on what he thinks Murphy will do — “You never, ever want to pretend to be constraining your governor,” he said — but he also said the governor has been outspoken about nuclear power being a bridge to a future with much more renewable generation capacity and supportive of the jobs at PSEG’s two nuclear plants in the state.
As for PJM’s efforts to improve its capacity market, Izzo said PSEG supports the RTO’s two-stage capacity repricing proposal over the Independent Market Monitor’s plan to expand the minimum offer price rule. PJM earlier this month filed both plans with FERC, asking it to choose one and outline what aspects of it should be revised. (See PJM Capacity Proposals to Duel at FERC.)
Izzo said PSEG prefers the status quo to either option because it doesn’t interfere with the ability of states to price attributes that markets aren’t currently pricing, which, in PSEG’s case, are the emissions-free generating capabilities of its nuclear fleet.
PJM’s two-stage approach would at least continue to allow states to value carbon-free generation,
but what’s really needed is a price on carbon, he said.
“The market’s just got these inherent inconsistencies built into it,” he said. “If we could get a price on carbon … capacity markets could do what they’re supposed to do.”
PSEG CFO Dan Cregg addressed the company’s recent agreement to pay $39.4 million to settle an investigation into violations of PJM’s energy market bidding rules over 9 years. (See PSEG to Pay $39.4M to Settle FERC Investigation.) He said PSEG’s Power unit recorded an incremental $5 million pretax charge to income in the first quarter that will conclude the issue.
“We do not believe the order will have any ongoing impact” on PSEG Power, he said.
PSEG earned $558 million and $1.10/share in the first quarter, up from $114 million and $0.22/share in the first quarter of last year. Last year’s results included costs related to the early retirement of the Hudson and Mercer generating stations and a reserve for the impairment of leveraged leases.
As part of his effort to promote renewables, Gov. Murphy issued an executive order that began moving the state towards a solicitation of 1,100 MW of offshore wind capacity.
Izzo said PSEG has a lease and a partner, which he didn’t name, for offshore wind development, but said since his company has no experience in that area, it “would be interested in the transmission component as much as, if not more than, the actual wind farms.”
PJM wants to take a more holistic look at how the grid’s supply chain works and factor the findings into its markets.
The RTO announced a plan Monday it thinks will help ensure the reliable delivery of both electricity and the fuel necessary to generate the electricity. The three-phased approach will analyze fuel security throughout PJM’s footprint to identify vulnerabilities, develop criteria to address them and include those criteria in the models used for capacity auctions.
The result would be constraints on the grid that trigger clearing price differences in affected locational deliverability areas (LDAs) in the same way deliverability constraints already trigger price separation in base residual auctions (BRAs). Those price differences would signal opportunities for developers to build new infrastructure.
PJM hopes to have the process in place for the 2022/23 BRA in May 2019.
The RTO will brief stakeholders on the plan and discuss the study scoping document at a special Markets and Reliability Committee meeting from 9:00-12:00 EDT on May 8. The RTO apologized for scheduling it on a “no meeting day,” saying there were no other available times on the committee meeting calendar in May.
In announcing the plan, CEO Andy Ott repeatedly reiterated that, while PJM’s grid is currently reliable and has no fuel security issues, problems could materialize if current trends continue for too long. The percentage of gas-fired generation has been growing quickly in PJM’s fleet. The RTO determined last year it wouldn’t have reliability concerns even with a high percentage of gas generation, capping its analysis at 86% of the fuel mix because the current 14% share of demand response and hydro and biomass production is not likely to change, but the analysis didn’t address the security of the gas plants’ fuel supplies. Because they are beholden to gas pipelines, gas plants can have — and pay for — a wide range of contracts, from receiving uninterruptable service to being cut off first if there’s not enough gas in the pipeline. Other plants maintain backup supplies of liquid fuel, such as oil or liquified natural gas (LNG), onsite or are connected directly to Marcellus shale gas wells. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
Ott called the plan a “narrow” portion of the resiliency initiatives going on at PJM and throughout the nation. He pointed to pipeline constraints in ISO-NE as justification for the plan to get “ahead of those issues in a timely manner.”
“At some point in the future, we may be overdependent on one pipeline or one set of fuel-delivery infrastructure,” he said. “Our approach is to develop these criteria to make sure that we’re monitoring those trends.”
Plan Mechanics
It’s unclear how the mechanics of the plan will work, as the transmission-constraint pricing it would be modeled on raises prices in areas that have issues. That would suggest the price signals would also reward fuel-insecure units within those LDAs.
Natural gas pipeline | Ohio Power Siting Board
“If we see a fuel security problem, the price would elevate in that area,” Ott confirmed in his Monday morning briefing.
PJM spokespersons said the question is beyond RTO staff’s current analysis, but Robbie Orvis of the clean energy consulting firm Energy Innovation predicted it might be designed as a shadow price that calculates what the price would be without the insecure resources and offers them as an adder for secure ones.
Ott appeared to corroborate that in describing the price separation as an “adder.”
“The increased cost to fix that would be adding more onsite fuel tanks or other types of fuel-secure resources,” he said. “The idea is not to give units more money. The idea is to look at the exposure that we have.”
He noted wind, solar and batteries could qualify as fuel secure, but a renewable resource alone “would probably [qualify at] a much smaller amount than its nameplate capacity” in capacity auctions.
Impact
PJM said part of the study is to determine what, if any, new construction is necessary and where. Orvis added it’s unclear whether it would create demand for new coal and nuclear units, but “it seems rather unlikely” given the net revenues for those technology types calculated by PJM’s Independent Market Monitor in its 2017 State of the Market Report are “well below” their respective costs of new entry calculation.
“Given just how short these units would be on revenue recovery, it would take a very high price from some kind of new market product for fuel security to cause new coal and nuclear builds,” he said. “It’s worth noting that those low revenues are consistent across zones, so it doesn’t look like there are even any specific constrained areas where those plants are especially attractive.”
The adder would make the threshold easier to reach but require significant additional action.
“Over time, with a high enough price, large retirements, and in constrained zones, it is possible that some kind of fuel security price adder could tip the scales and incent new capacity, but it would take a significant deviation from today’s prices,” Orvis said. “PJM’s high reserve margins in the near- and medium-term, based on its cleared capacity in the capacity market, indicate that it’s unlikely there will be a capacity shortfall to push capacity market prices up.”
Orvis noted the modeling parameters PJM plans to use will likely underestimate the generation fleet and therefore might indicate a fuel delivery constraint when there are actually many more resources available.
“It is possible PJM will charge its customers for a service or attribute that is not needed. It would be better if they modeled the system based on what is actually expected to be available rather than their required reserve margin since they have in the past and will in the future continue to come in well above that reserve margin,” he said.
Reaction
Paul Bailey, CEO of the American Coalition for Clean Coal Electricity, praised PJM’s action and urged other grid operators to follow suit. “We are also encouraged that PJM is following a work plan consistent with the urgency necessary to address lack of fuel security,” he said. “Over the next three years, more than 6,000 MW of fuel-secure coal-fueled generating capacity in PJM are expected to retire.”
Meanwhile, NRG Energy spokesman David Gaier noted PJM on Monday also said that FirstEnergy’s announced retirements of its Davis-Besse, Perry and Beaver Valley nuclear plants will not cause reliability problems.
“Units can retire as scheduled” PJM said in a presentation for the May 3 Transmission Expansion Advisory Committee meeting. “Operational flexibility allows [us] to bridge any delays with the transmission upgrades.”
Gaier said the RTO’s analysis undermines FirstEnergy’s request that the Department of Energy declare an emergency to keep the plants running. “Clearly, the attempt by FirstEnergy to keep open its uneconomic nuclear plants on the backs of ratepayers is a subsidy in search of a crisis — one that doesn’t exist,” Gaier said.
AUSTIN, Texas — The Public Utility Commission (PUC) of Texas on Friday orally approved Southwestern Public Service Company’s (SPS) request to build a wind farm in West Texas, clearing the way for a 1.23-GW project that will provide renewable energy and economic benefits to SPS customers in the Lone Star State and New Mexico.
Walker and Arthur D’Andrea requested additional information from SPS during the commission’s April 12 meeting, expressing doubts as to whether they had a “legal basis” to grant an application for new generation when the company already has sufficient capacity. (See Texas Regulators Seek More Details on SPS Wind Project.)
“I’m sorry if we kind of freaked out, but it’s a big question, and we don’t have a ton of time to review it,” D’Andrea told SPS representatives and the consumer groups with whom they had reached a unanimous settlement.
“I think you’ve done a nice enough job … for the ratepayers,” D’Andrea said. “You’ve certainly done a great job of getting everyone’s finger on the trigger.”
SPP staff had also previously stamped its approval on the SPS proposal.
Walker instructed staff to reflect Friday’s several minutes of discussion in its draft order. The final order will be approved during the PUC’s May 10 meeting (Docket No. 46936).
“It’s been a very cooperative effort, with both local stakeholders and statewide stakeholders,” SPS President David Hudson told RTO Insider after the April 27 open meeting. “This project will bring tremendous economic value to the region for three decades.”
Xcel will use Vestas turbines on its wind farms | Xcel Energy
The commission’s approval allows SPS parent Xcel Energy to proceed with construction of a 478-MW wind farm near Plainview, Texas, and a 522-MW facility near Portales, N.M., both in SPP’s footprint. Xcel will begin construction on the Texas facility in June and in New Mexico next year.
The company, which will own both facilities, will also purchase 230 MW of energy from two NextEra Energy Resources in Texas.
SPS received approval for the New Mexico portion of the project from the state’s Public Regulation Commission in March.
Xcel says the project will save customers hundreds of millions of dollars in production costs over a 30-year period. SPS will receive 100% of the available production tax credits for 10 years, passing the savings directly to its customers.
Xcel also expects the project to generate more than $150 million in local property tax payments over the next 25 years in Texas and New Mexico.
PUC Lowers CenterPoint Energy’s Tx Rates
The commission also approved CenterPoint Energy’s request to revise its wholesale transmission rates to reflect the reduction of the federal income tax corporate rate from 35% to 21%, thanks to the Tax Cut and Jobs Act of 2017 (Docket No. 48065).
The revision reduces CenterPoint’s transmission rate base from $2.11 billion to $2.08 billion and its wholesale transmission revenue requirement from $389.5 million to $347.8 million. Its interim wholesale transmission rate drops from $5,753.91/MW to $5,138.64/MW.
KANSAS CITY, Mo. — SPP’s Board of Directors was last week forced to table the appeal of a rejected revision request, cutting short the discussion when they realized the supporting documentation was not included in the background materials.
The Tariff change (MWG-RR272) requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period. It failed to receive the Markets and Operations Policy Committee’s (MOPC) endorsement by a handful of votes. (See Vote to Make Variable Resources Dispatchable Falls Short at MOPC.)
However, additional information on the measure was not part of the 638 pages of background material for the Apr. 24 meeting, leading Director Phyllis Bernard to move to table the measure “until we have further background information in front of the Members Committee before we vote.”
The Members Committee agreed with Bernard. Oklahoma Gas & Electric abstained from the vote.
The rejection was appealed by members, SPP staff and the Market Monitoring Unit (MMU).
Director Larry Altenbaumer, in one of his final comments before assuming the board’s chairmanship, told directors and members to plan on making a decision during their next meeting in July.
“If you have ideas to improve the process, you’ve got a quarter to make that decision,” he said.
In bringing forward the revision request, the Market Working Group said it would increase reliability and market efficiency through the reduction of manual out-of-merit energy orders to mitigate constraints.
The proposal applies to about 6 GW of NDVERs, which are generally older wind resources. However, it exempts about 2 GW of resources that don’t have direct interconnection agreements with SPP or are registered as qualifying facilities under the Public Utility Regulatory Policies Act (PURPA).
MMU Executive Director Keith Collins argued for the change, saying it’s a “global market efficiency issue” and would help reverse the recent growth of negative real-time pricing in SPP’s markets.
“To the extent resources are not flexible and capable of availing themselves to the system, we see an increase not only in frequency but [also] the magnitude of prices when we are unable to dispatch those resources,” Collins said. “Operators have to skip over the NDVER and find another resource.”
He pointed out that recent SPP analysis has found that dispatchable resources classified as non-dispatchable have “significant effects on the market congestion we’re seeing.”
The measure found resistance from stakeholders with renewable interests who said the rule change would add costs to existing power purchase agreements.
“If we can address the rule change, we’re taking a negative from the system, and that has a lot of global benefits,” Collins said. “We don’t deny some resources will face increased costs, but we believe the whole market can benefit from that.”
SPP Operations Vice President Bruce Rew said the rule would lead to a more efficient market through better management of congestion.
“It’s a much smoother operation for us to be able to dispatch those resources that may be down at the time, rather than the generator making that decision when to come on and off,” Rew said.
While the board was forced to table one voting item, it took another one off the table when it approved a sponsored upgrade of an OG&E transmission line that MOPC was unable to take action on.
OG&E requested MOPC delay a vote until it could address its concerns about the upgrade with SPP. The project is sponsored by EDF Renewable Energy, which wants to upgrade terminal equipment and rebuild an 11-mile, 138-kV line near Ponca City and its 154-MW Rock Falls wind farm, which became operational in December. (See “OG&E Raises Concerns over Third-party Tx Line Upgrade” in SPP Markets and Operations Policy Committee Briefs: April 17, 2018.)
SPP answered all 23 of the questions submitted to it by OG&E, but the utility said it still has questions about the project’s cost allocation and asked for additional time to get answers.
“This is a small project, in and of itself. It’ not going to break the bank for anybody,” OG&E’s Greg McAuley said. “The precedent here is what some of the [transmission owners] are concerned about. If you had a $100 million to $200 million project, you would see a much different amount of concern. We’re continuing to work to close the gaps in the Tariff we think exist, so we still ask for additional time to get those questions answered.”
EDF has said it will seek cost recovery through SPP’s Attachment Z2 revenue crediting or incremental long-term congestion rights. Attachment Z2 of SPP’s Tariff assigns financial credits and obligations for sponsored transmission upgrades, with directly assigned Z2 network upgrades allocated to SPP’s base plan.
“A project like this, if it just remains between EDF and OG&E, I don’t think it will have impacts,” said Nebraska Public Power District’s Paul Malone, who chairs the MOPC. “But to the extent this project qualifies for Z2 credits, we’re all going to end up paying for that. Thus, the vested interest.”
Attorney Dan Simon represented EDF and said he saw no legal reason for members to delay their endorsement of the project.
“We’ve gone through the process as dictated by the Tariff and the staff,” Simon said. “We understand OG&E has a number of important questions,” but “all of those questions are things that are already dictated by the current language in the Tariff,” and therefore do not provide a justification to delay the request.
Simon said EDF worked with OG&E to develop a cost estimate before it submitted its official upgrade request to SPP, noting OG&E did not raise concerns until the MOPC meeting.
“It’s been based on that information that we’ve continued to proceed through the transmission process to submit this request. We don’t think it’s appropriate to allow these questions coming so late in the process to delay our upgrade request,” he said.
“This project is time-sensitive. The sooner this gets placed into service, the sooner it will relieve congestion, and we all realize economic benefits from that,” Simon said.
The measure passed the Members Committee by a 14-3 margin, with OG&E, American Electric Power and the Omaha Public Power District voting in opposition. The Oklahoma Municipal Power Authority abstained.
MMU Shares Draft of State of the Market Report
Collins shared the MMU’s draft of its annual State of the Market Report with the board and members. He declared the market to be “competitive and efficient,” citing low energy prices, declining mitigation and make-whole payments, along with declining levels of excess online capacity and the alleviation of a congestion bottleneck.
Collins said total market costs last year approximated $24/MWh, a 7% increase from 2016, driven by a 14% rise in natural gas prices. As an example, the MMU pointed to the Panhandle hub, where the average gas price increased from $2.32/MMBtu in 2016 to $2.65/MMBtu in 2017.
Wind resources accounted for about 70% of the SPP footprint’s 2.2 GW increase in nameplate generation capacity last year, but the rate of new additions has declined significantly. SPP added about 11.4 GW of generation in 2015 and 3.9 GW in 2016.
“Even so, wind generation continued to increase as it represented almost 23% of system generation, up from 18% in 2016 and 14% in 2015,” the MMU said. In contrast, coal-fired units saw their share of total generation continue to slide, from 55% or more before 2016 to 46% last year.
Collins said SPP has a reserve margin of about 30%. “That can contribute to the high levels of competition we see,” he said.
He noted several issues that bear watching in the months ahead:
Self-commitment has declined but is still high overall.
Wind generation is under-scheduled in the day-ahead market.
The frequency of negative prices has doubled.
Real-time price volatility has increased.
Congestion has increased significantly.
Very few resources are being retired.
The final report will be released later in May.
Director Josh Martin, who chairs the Oversight Committee that oversees the MMU, said the monitor is fully staffed “for the first time in a long time.” The MMU added CAISO’s Adam Swadley as its lead economist to reach its full staffing level.
Finance Committee Looks to Engage Stakeholders
Finance Committee Chair Larry Altenbaumer told the board and members the committee has been studying a recovery mechanism that “appropriately” reflects the administrative fee as it tries to maintain a simple rate-design structure.
The committee has determined membership’s “full engagement” is necessary, Altenbaumer said, and will work with MOPC’s leadership in July to involve a broader stakeholder group.
The board unanimously approved three recommendations from the Finance Committee:
Accepting BKD’s 2017 financial audit, which noted “no issues or material/significant weaknesses.”
Engaging BKD to perform the 2018 financial audit and Thomas & Thomas to audit the employee benefit plan’s financial statements.
Taking out an $80 million bank loan with a 5-year maturity and floating rate pricing on outstanding balances under the guidance line.
SPP RE Tying Up Loose Ends
“As you all know, we’re going out of business,” said Dave Christiano, chairman of the SPP Regional Entity’s board of trustees, as he delivered what is likely to be the final RE update to the board.
Christiano said the RE will cease its compliance and enforcement activities by the end of June and be officially dissolved by September. The RE has already successfully transferred 25% of its data to NERC, the Midwest Reliability Organization and the SERC Reliability Corporation, he said, but it still has a number of loose ends to resolve.
“It’s pretty complicated, as you can guess,” Christiano said
SPP said last July it would dissolve the RE, ending a reliability oversight role that has been a source of concern at NERC and FERC. NERC approved the dissolution in February. (See NERC Board Approves Dissolving SPP Regional Entity.)
The RE’s staff of two dozen has dwindled to 17 employees, with all but five either having already found work within the RTO and other organizations or having decided to retire.
Christiano also recommended members read a joint report from the FBI and Department of Homeland Security, “Russian Government Cyber Activity Targeting Energy and Other Critical Infrastructure Sectors.”
SPP’s 2017 Annual Report: ‘Focus’
As it does every April, SPP handed out copies of its 2017 annual report during the meeting.
The report, titled “Focus,” highlights the “people, milestones, accomplishments, and challenges that made 2017 another exceptional chapter in [SPP’s] story.”
SPP’s 2017 Annual Report | SPP
The report includes comments from a broad section of SPP staffers and how they work with their members.
Last Board Meeting for Westar’s Harrison
The board meeting was the last for Westar Energy’s Kelly Harrison, who represents public transmission-owning members on the Members Committee.
Harrison, who is nearing 60 years of age, said he is taking advantage of the Westar-Great Plains merger to take retirement. He said he would miss the SPP meetings, as well as the people who attend the meetings — who treated Harrison to a standing ovation.
“I, for one, am extremely appreciative of the care and the intellect Kelly has brought to the Members Committee,” Brown said, singling out Harrison’s financial acumen and participation on the Oversight Committee. “I couldn’t begin to count all the task forces and working groups Kelly has worked on over the years. Thank you, Kelly, from the bottom of my heart.”
Members unanimously approved the consent agenda, which included the re-baselining of a Nebraska Public Power District 69-kV and 161-kV project from $37.8 million to $27.5 million; a sponsored upgrade with the addition of a second 161/69-kV transformer at City Utilities of Springfield’s (Mo.) James River Power Station; funding the SPP retirement and post-retirement healthcare plans; and seven revision requests.
GIITF RR267 eliminates the “standalone scenario,” which considers each interconnection request by itself, from the definitive interconnection system impact study process. This will free SPP resources to focus on binding cluster study results, permitting their earlier availability. Staff will provide the standalone equivalent study models through existing confidentiality provisions to customers seeking to conduct a standalone scenario of their own.
MWG RR252 assigns an out-of-merit energy (OOME) cap and/or floor, allowing staff to economically dispatch the resource down or up within the ranges.
MWG RR259 modifies the market settlement posting and dispute timelines being implemented with the new settlement system, reducing the number of resettlement postings and manual processes resulting from revisions to meter and bilateral settlement schedules.
MWG RR273 automates several of the market settlement system’s charge types that are not yet part of revenue neutrality uplift processing, resulting in rounding/residual amounts that must be manually processed and distributed through miscellaneous charges. The new system is scheduled to go live in May 2019.
ORWG RR268 clarifies or removes outdated language from the operating criteria, improving SPP’s ability to perform reliability coordinator, balancing authority, transmission service provider and reserve sharing group functions.
ORWG RR269 clarifies language and removes antiquated and redundant language in SPP’s operating criteria and describes the existence of multiple standalone documents.
ORWG RR270 converts the operating criteria Appendix OP-2 to a standalone document, clarifies language and adds formatting improvements.
DTE Energy is focused on plans to double its renewable energy capacity by the early 2020s and build a new, controversial $1-billion gas-fired plant recently approved by regulators, company executives told analysts during an earnings call last week.
First-quarter earnings fell nearly 10% to $361 million ($2.00/share) compared with 2017, but operating earnings jumped $20 million to $342 million. The utility posted revenue of $3.75 billion for the period.
During an April 25 call, DTE Energy CEO Gerard Anderson revealed more detail about the company’s plan to double its current renewable energy capacity primarily through new wind projects built over the next few years. DTE filed its plan with the Michigan Public Service Commission (PSC) last month.
“If approved, this will drive increased investment in new wind and solar projects,” Anderson said.
DTE last year said it would transition to cleaner energy sources and to reduce carbon emissions by more than 80% by 2050.
The company’s $1.7-billion proposes about 1 GW of new wind and solar projects in Michigan to be completed by 2022.
DTE Pinnebog wind park in the Michigan thumb region | DTE Energy
“ …This plan is another significant step toward our carbon emission reduction goals, and those goals can be met in a way that continues to deliver reliable and affordable power for our customers as well,” Anderson said.
The plan includes two central Michigan wind farms providing 330 MW of new capacity: Pine River, set to be completed later this year, and Polaris, slated for completion by 2020.
Anderson said the two wind farms will be DTE’s largest and most efficient to date.
The plan also includes an additional 300 MW of new wind capacity by 2020 to support a new voluntary renewable energy program for DTE’s large business customers interested in reducing emissions, Anderson said.
Finally, DTE will complete another two wind farms in 2020/21 that will provide a combined 375 MW of capacity, Anderson said.
He also expects DTE to begin investing in more solar generation in the coming years.
“Along with the increased wind capacity, we’re also planning on adding 15 MW of solar power. Wind today is clearly lower cost than solar in Michigan, and thus we’re really concentrated on wind capacity in the near-term. But solar costs are improving, and we expect that by the mid-2020s, solar will be ready to play a more prominent role in our mix,” Anderson said.
He added that DTE plans to add more renewable energy generation beyond that outlined in the plan submitted with regulators.
Anderson’s comments on solar development come at a time when DTE has twice been accused of withholding interconnection data from independent solar developers seeking to connect new generation to DTE’s grid, as well as overcharging for studies requested to start on new projects. Both Cypress Creek Renewables and a Geronimo Energy subsidiary this month filed similar complaints with the Michigan PSC, claiming DTE’s responses violate a provision of the Public Utility Regulatory Policies Act (PURPA) that qualifying facilities have a right to interconnect with the host utility’s grid (U-20151, U-20156).
DTE representatives did not respond to a request for comment on the complaints.
Regulators Approve Controversial New Gas Plant
Still, DTE’s renewable plans will not match the output of its proposed $1 billion, 1.1-GW natural gas plant to be built in St. Clair County near the Canada border, which Michigan regulators approved Friday after concluding it “was the most reasonable and prudent means of meeting DTE’s future energy needs” (U-18419). The company wants to begin construction in 2019.
“DTE Electric’s recent and planned investments in energy waste reduction, renewable energy and energy storage, when coupled with this highly efficient gas plant, demonstrate that Michigan is a great example of an ‘all of the above’ strategy to meet our energy needs in a reliable, affordable manner that protects the environment,” Michigan PSC Chairman Sally Talberg said in a statement.
During the earnings call two days ahead of the approval, Anderson said he expected a “constructive outcome” in the proceeding.
Environmental advocates such as Sam Gomburg with the Union of Concerned Scientists have questioned the need for the plant, saying DTE’s commitment to the environment rings hollow when pushing such a large fossil fuel plant.
“There is plenty in the record to justify not approving this. [This was] a matter of how much backbone this commission has,” Gomburg said in a telephone interview with RTO Insider.
Gomburg said a combination of renewable generation and storage, energy efficiency measures and demand response could meet DTE’s needs more efficiently and inexpensively. He said DTE’s assessment in justifying the natural gas plant failed to explore alternatives.
“Even using their own tools, we find ways to meet their goal with cheaper options,” Gomburg said.
Gomburg warned about a future spike in natural gas prices or new regulations putting more emphasis on staving off the effects of climate change, making the plant costlier.
“I see a very high risk that ten years from now, as we’re paying this off, we’re [going] to regret this,” Gomburg said. “I see putting all your eggs into this billion-dollar basket as very risky.”
While Gomburg said DTE seems “disingenuous” in its goal to double renewable capacity while planning a large natural gas plant, he didn’t want to denigrate DTE’s goal of reducing emissions by 80% in little more than 30 years.
“I don’t want to say that the goal they’ve put forward is meaningless, but we can do more sooner. What matters is what carbon dioxide and mercury we emit now until 2050,” Gomburg said.
Power Up Michigan, a coalition of nine clean energy groups, said the plant is unnecessarily expensive, fails to create the level of jobs that new renewable sources could generate and is a “failure of innovation” to transition to clean energy sources.
However, in filings leading up to the approval, DTE said those who “suggest that there might be some other combination of resource options that might somehow be preferable from their self-interested perspective” ultimately failed to submit an alternative proposal.
“It again bears emphasis that DTE Electric presented the only specific proposal to meet the power need … established on the record,” the company wrote.
DTE said its analysis found that the gas plant would “appropriately” balance six characteristics, including reliability, affordability, cleanliness, compliance, reasonable risk and flexibility.
MILFORD, Mass. — ISO-NE’s 10-year Capacity, Energy, Loads and Transmission (CELT) forecast predicts 2026 annual net load will be about 3.7% lower than estimated in the 2017 forecast, Load Forecasting Manager Jon Black told the Planning Advisory Committee (PAC) on Thursday.
Net load forecasts, developed by subtracting energy efficiency and behind-the-meter solar from gross forecasts, are intended to be representative of energy and loads observed in New England in real-time.
The final 2018 CELT forecast update was changed slightly from the draft version presented at the March 15 PAC.
The behind-the-meter solar photovoltaic (PV) forecast is approximately 0.4% lower in 2026, slightly higher than the draft 2018 forecast, while the energy efficiency (EE) summer forecast is approximately 12.9% higher in 2026, down from the draft 2018 EE forecast. (See ISO-NE Planning Advisory Committee Briefs: March 15, 2018.)
2018 CELT Energy Forecast | ISO-NE
Compared to last year’s forecast for 2026, the 2018 CELT gross load forecasts show annual energy approximately 0.3% higher, gross summer 50/50 load about 2.7% lower and gross summer 90/10 load about 2.8% lower.
Net load forecasts, updated since March 15, show the net summer 50/50 forecast approximately 5.4% lower in 2026, with the net summer 90/10 forecast approximately 5.3% lower.
All forecast data will be posted on the RTO’s load forecast website by May 1.
Winter Review Highlights Fuel Security Issues
The RTO’s review of 2017/18 Winter operations showed stress on the grid from a severe cold snap around the turn of the year and from an exceptional chain of four nor’easters in March.
System Planner Mark Babula said the RTO avoided initiating emergency capacity deficiency procedures but did declare “Master/Local Control Center 2” procedures in early January and for each March storm, making them “hands-off” periods for regular generator maintenance or unnecessary outages.
As natural gas prices spiked, generators that could turn to oil did so, rapidly depleting the entire season’s oil supply.
Sea and river ice hindered ship and barge deliveries to fuel oil terminals in New Hampshire and Maine and on the Hudson River, so the RTO “monitored ice with the U.S. Coast Guard, trying to get those ice-breakers up the rivers to keep the natural gas supply lines open,” said Babula.
Winter natural gas (left in thousand MCF) versus oil consumption (in barrels) and net generation (thousand MWh) | ISO-NE
The Winter 2017/18 Reliability Program started Dec. 1, 2017, and 86 generator units participated in the oil program for a total of 3.9 million barrels of oil. Approximately 2.9 million barrels of the total inventory on Dec. 1 are eligible for compensation according to winter reliability program rules, with total oil program cost exposure projected to be $29.62 million (at $10.33/barrel).
The reliability liquified natural gas (LNG) program had no participants this winter, while three assets providing 7.5 MW of interruption capability participated in the demand response (DR) program, with the total program cost exposure projected to be around $23,000.
Babula said daily communication with suppliers and pipeline operators is key to ensuring adequate fuel supplies, whether of oil, natural gas or LNG. (See ISO-NE Sees Growing Fuel Security Risks,RTO Resilience Filings Seek Time, More Gas Coordination.)
Natural Gas Rules Home Heating in Northeast
New England and neighboring states have seen household natural gas customers grow by 1 million since 2010, with gas increasingly fueling energy generation as well, Tom Kiley, president of the Northeast Gas Association, told the PAC.
Kiley’s regional gas market update highlighted recent market growth, pipeline development and lessons learned from the winter cold snap from around the holidays.
| Northeast Gas Association
The United States set a new gas sendout record of 150 Bcf on Jan. 1, 2018, while most local gas distribution companies in the Northeast set multiple sendout records in the first week of the year. New England natural gas utilities set three new sendout records that week — with a new all-time peak near 4.4 Bcf set on Jan. 6.
LNG played a key role in supplying generators during the cold snap, with the Distrigas terminal importing six cargoes totaling about 16 Bcf. Canaport LNG provided input into the Maritimes and Northeast Pipeline during the same period, with three cargoes in January, totaling about 9 Bcf.
Kiley cited a FERC report issued Apr. 19 that said “natural gas prices in New York City, New England and the Mid-Atlantic all set all-time record highs, with next-day trades reaching as high as $175/MMBtu in New York City on January 4. Although Operational Flow Orders limited shippers’ flexibility to exceed their contractual obligations to meet varying natural gas demand, there were no pipeline outages or firm service curtailments.”
The Natural Gas Act’s (NGA) gas supply task force has good communication protocols in place between gas pipeline control rooms and the power grids, Kiley said.
While gas utility demand continues to rise, New England has added nearly half a billion cubic feet per day of new pipeline capacity since November 2016, he said, with multiple projects planned to go into service through 2019. The Northeast region currently produces about 27 Bcf/d, with further growth expected; Pennsylvania is the second largest gas producing state in the U.S.
Updating Needs Assessments to Reflect Latest Forecasts
The RTO presented an update on the transmission Needs Assessments for Maine (ME), New Hampshire (NH), Southwest Connecticut (SWCT), Western and Central Massachusetts (WCMA) and Southeastern Massachusetts and Rhode Island (SEMA/RI).
Brent Oberlin, director of transmission planning, said the assessments attempt to balance the benefits of incorporating the latest load forecast against adding delays to each of the studies from including the data. A preliminary review shows the new forecasts could potentially eliminate some system needs.
The RTO has already posted a draft scope of work reports and intermediate study files for SEMA/RI and WCMA and will publish the SWCT scope of work in early May, with a finalized Needs Assessment due to be complete in September.
Maine and New Hampshire updated scope of work reports will also be published in early May, with final Needs Assessment reports slated to be delivered in October.
Cost Recovery in Flood Hazard Areas
Michael Drzewianowski, an ISO-NE lead engineer, outlined the RTO’s new recommendations for regional cost recovery for transmission resources built in flood hazard areas. Large storms and other weather-related events in the past several years have changed the RTO’s thought process on designing for flood hazard areas, he said.
Drzewianowski’s report said the relevant Tariff clauses are defined on the Federal Emergency Management Agency (FEMA) Flood Insurance Rate Map (FIRM).
In inland locations (defined as areas that have no chance for “wave action”), the RTO is now recommending cost recovery for infrastructure constructed to withstand the higher of the 100-year flood level plus two feet or the 500-year flood level.
For coastal locations, the RTO recommends adding another foot to the inland figure to account for sea level rise. For existing equipment that needs to be raised, the recommendation is to the bottom of sensitive equipment.
The RTO’s previous recommendation was to construct to the 100-year flood level, plus an additional one foot, developed after review of national information available, including recommendations from FEMA and the American Society of Civil Engineers (ASCE).
Comments on the plan can be submitted to PACMatters@iso-ne.com by May 10, ahead of the Reliability Committee review process anticipated to begin in June.
Eastern Conn. 2027 Needs Assessment Update
Jon Breard, associate engineer for transmission planning, presented an update on the Eastern Connecticut Needs Assessment results showing non-transmission options are not adequate to relieve the area’s reliability criteria violations.
All updated needs are time-sensitive and based on the location of the reliability criteria violations; the RTO will work with participating transmission owners as needed. The final Needs Assessment report will be posted by May 31, and the PAC will be presented solution alternatives in the third quarter.
In addition, Kannan Sreenivasachar, principal engineer for transmission planning, presented an update on preferred solutions for SEMA/RI.
FCA 13 Zonal Boundary Determinations
Al McBride, director of transmission strategy and services, presented a review of interface transfer capabilities for a proposed capacity zone construct for the 13th Forward Capacity Auction (FCA-13, Capacity Commitment Period 2022/23).
The review showed no change to the interface transfer capabilities as a result of the new certifications for FCA-13.
The electrical limit of the New Brunswick-New England (NB-NE) Tie is 1,000 MW but drops to 700 MW when adjusted for the ability to deliver capacity to the greater New England control area.
The Hydro-Quebec Phase II interconnection is a DC tie with equipment ratings of 2,000 MW. Due to the need to protect for the loss of this line at full import level in the PJM and NY control areas’ systems, the ISO-NE has assumed its transfer capability is 1,400 MW for capacity and reliability calculation purposes.
New York interface limits were modeled without the Cross Sound Cable and with the Northport Norwalk Cable at 0 MW flow and show that simultaneously importing into New England and SWCT or CT can lower the NY-NE capability by around 200 MW.
The Maine Load Zone will be evaluated as a potential export-constrained capacity zone, and a significant backlog of requests exists in the interconnection queue in Maine. FERC’s Nov. 1, 2017, approval of the RTO’s clustering proposal will enable the queue to move forward in Maine, which will allow more resources there to qualify for the FCA.
Northern New England will be evaluated as a potential export-constrained capacity zone that could be modeled either with or without Maine. The zone’s potential boundaries will be tested and presented to the Power Supply Planning Committee in May.
Transmission Planning Technical Guide Update
ISO-NE is continuing to revise the Transmission Planning Technical Guide, which it reorganized last year into a new format. Revision 2 was posted on the ISO website on Nov. 14, 2017.
Steve Judd, lead engineer for system planning, presented the technical guide report and said staff is now updating the following sections for consistency with the RTO’s style guide and publication template:
All Sections – Changes to terminology with Price Responsive Demand (PRD)
Section 2.2 – Clarification to system load level definitions and what is tested
Section 2.8 – Simplified generic interface transfer levels section and moved detailed methodology to Section 4
Section 2.11 (New) – Moved power flow solution settings to assumptions from methodology subsections
Section 3.1.2.5 – Added maximum bus voltage limits for nuclear units to Table 3-2
Section 4 – Split transmission Needs Assessments and Solutions Studies into a separate subsection 4.1 and Proposed Plan Application Testing into subsection 4.2 to allow for clarification in differences between study methodologies
Section 4.1 – Detailed review to reflect current process for transmission Needs Assessments and Solutions Studies
Section 4.2 – Moved previous description of stressed transfer levels from Section 2.8 to new subsection of PPA studies
Proposed revisions to the Transmission Planning Technical Guide are to be posted to the PAC website, and stakeholders can provide comments by May 13 to PACMatters@iso-ne.com. Further detailed review of the guide will continue, with future revisions planned for 2018.
A bill allowing utilities to recover wildfire costs if they conform to state-regulated safety plans moved through the California legislature last week, but it faces heavy opposition from some who say it lets utilities off the hook for their contribution to wildfires.
Dodd | U.S. Army Corp. of Engineers
The relevant language in SB 1088, introduced by Sen. William Dodd (D), requires each electrical and gas utility to submit a biennial safety, reliability and resiliency plan to the California Public Utilities Commission (CPUC), beginning Jan. 15, 2019. It would require the CPUC to review the plans in a single consolidated proceeding and verify the plans comply with all rules, regulations and standards. The initial plan must be limited to addressing fire risks, with subsequent plans addressing risks associated with routine operation and all major events.
If utilities are found to be in “substantial compliance” with the plan, “the utility’s performance, operations, management and investments addressed in the plan must be deemed reasonable and prudent for all purposes,” a bill analysis said. The legislation would not protect utilities from civil lawsuits, which represent a separate area of liability for the fires.
The cost recovery issue is front and center for California investor-owned utilities, regulators and ratepayer interests as utilities try to recover costs of the devastating disasters. The CPUC last December denied San Diego Gas and Electric’s (SDG&E) request to recover $379 million from ratepayers for 2007 wildfires. (See Besieged CPUC Denies SDG&E WildfireRecovery.) Commissioners at the time said the decision turned on a specific case of whether SDG&E had reasonably maintained its facilities, not on the cost recovery issue.
The La Tuna Fire burns near Los Angeles in early September 2017
California law requires that any costs ratepayers incur on behalf of a utility must be just and reasonable, but the CPUC found SDG&E’s management and control of its facilities prior to the 2007 Witch, Guejito and Rice Wildfires were unreasonable, mentioning poor vegetation management and other activities.
Seeing the writing on the wall for future cost recovery of last year’s fires, the state’s two other large investor-owned utilities, Pacific Gas and Electric (PG&E) and Southern California Edison joined SDG&E in requesting a rehearing of the CPUC decision and launched a fierce response on legislative, regulatory and legal fronts. (See Sempra Joins ‘Three-Pronged’ Wildfire Front; PG&E Vows Fight over Wildfire Cost Recovery.)
PG&E and other investor-owned utilities are being investigated for causing the 2017 fires, but utilities say they cannot be held solely responsible for the increasingly high-risk fire conditions in California, which most observers attribute to climate change. Sempra Energy CEO Debra Reed told shareholders in February she expected legislative action on the issue. And state lawmakers such as Assembly Utilities and Energy Committee Vice Chair Jim Patterson (R) are sounding the alarm about IOU bankruptcies after utilities lobbied in Sacramento earlier this year for a legislative fix. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)
In his author’s comments on SB 1088, Dodd said that climate change will cause more frequent and intense storms, floods, mudslides and wildfires, and eight of the 20 most destructive wildfires in state history have happened since 2015, with five occurring in 2017. “Many scientists predict the 2017 fire season is not an anomaly, and similar wildfires are likely to continue into the future,” he said.
Opponents of the bill include California Large Energy Consumers Association, California League of Conservation Voters, Consumer Attorneys of California, Consumer Federation of California, Environment California, Environmental Defense Fund, Silicon Valley Leadership Group and The Utility Reform Network (TURN).
TURN said the bill “would enrich utility shareholders at the expense of vulnerable households who would be forced to pay large rate increases for bloated programs of unproven benefit to safety risk reduction. TURN fully recognizes the increased risk of wildfires poses new challenges and financial threats to both ratepayers and utilities. Unfortunately, SB 1088 is fundamentally flawed and offers no such constructive solutions.”
The Senate Governmental Organization Committee cleared the bill on April 24 on an 11-1 vote, and it now goes to the Senate Appropriations Committee. The Senate Energy, Utilities and Communications Committee passed the measure on April 17 with a 9-1 vote.
VALLEY FORGE, Pa. — Although FERC has required almost all new generating units to provide primary frequency response, PJM stakeholders are strongly opposing any move by the RTO to require existing units to follow suit.
That disapproval became clear last week at a meeting of the Primary Frequency Response Senior Task Force (PFRSTF), during which staff reviewed the results of a nonbinding poll that revealed stakeholder support for the only PFR proposal that does not impose a mandate on units that don’t increase their output.
The proposal from American Electric Power (AEP) would apply PFR capability requirements on new units and existing units that modify their interconnection agreement to increase their output. Units that already provide PFR would be “encouraged to continue to do so” and can seek compensation at FERC. Units would annually confirm whether they will continue to provide the service, and PJM and transmission owners would revise system restoration plans accordingly.
A 10% dip in the system-wide aggregate PFR would trigger reconvening the task force “to analyze and suggest, if necessary, possible solutions.”
Stakeholders strongly opposed all three other proposals, two of which came from PJM and the third from the Independent Market Monitor. They all applied PFR capability on existing units but differed on minimum size or use thresholds and cost-recovery mechanisms.
“Part of the hang up we have with PJM’s initial proposal is the universal requirement for all. Where we get concerned is … if there’s compensation involved, we’ve got to foot the bill here,” explained Dave Mabry, who represents the PJM Industrial Customer Coalition (ICC). “I think the AEP proposal gets us a little bit closer to looking at: Does it make sense for a unit to have it?”
The PJM ICC believes existing units already have an avenue to be compensated for PFR costs through the capacity market, Mabry said, and would support provisions that develop a cost-benefit analysis for whether units should make those investments.
Carl Johnson, who represents the PJM Public Power Coalition, said he was “a little confused” by the lack of support for PJM’s “option B” proposal, which would require PFR only for units involved in system restoration plans and would offer them a one-time capital recovery method.
“On behalf of my members who both represent load but also self-serve load and have a lot of generation … we have concerns about anything that’s going to add costs for a service that we think maybe you should be providing anyway, but at the same time we have concerns about being audited and reported for failure to provide it, [including] the possibilities of selective enforcement. So, we’re of two minds on this,” he said. “I think we still need to work out a lot of issues with regard to what a broad requirement for PFR would be.”
GT Power Group’s David Pratzon and Tom Hyzinski voiced concerns about “retroactive ratemaking” and unfair demands on generators.
“If you take a look at those existing resources, a lot of them are resources that are financially challenged in the market right now. So, on one hand, to say they’re absolutely critical to the integrity of the system but then to turn a blind eye to the fact that they’re challenged in the market and to not make any attempt to compensate the vast majority of them for this critical value that they bring to the table” is unfair, Hyzinski said.
Package Criticism
PJM’s Glen Boyle said staff heard feedback that the proposals weren’t aligned with FERC Order 842, which some stakeholders believe specifically exempts existing resources from PFR requirements — the opposite of PJM’s interpretation. Stakeholders also said that exempting nuclear units — in harmony with the exemption of any new nuclear units in FERC’s order — was discriminatory.
The requirement would be an “unfunded mandate” and wouldn’t support capital cost recovery, stakeholders said. Calpine’s David “Scarp” Scarpignato agreed.
“If you have to go through a complex, very expensive, tedious process in order to get paid back for something, and there’s no kind of internal rate of return, I think some people might view those as unfunded,” he said.
Finally, RTO staff heard they did not satisfactorily make the case for the requirement, a criticism they attempted to address with presentations on a recent report from the Lawrence Berkeley National Laboratory and the importance of PFR in system restoration. PJM’s presentation detailed the many uses of PFR during such events, while the laboratory study emphasized the importance of having as many generators as possible provide the service.
Pratzon noted the possibility that some units may find it’s not worth the investment to provide PFR if they’re required to do so, weighed against a related concern that, without such a mandate, those who continue to provide PFR will be unfairly overcompensating for those who don’t.
“There are problems going down either direction,” he said.
Next Steps
Johnson noted that FERC is awaiting a report from NERC in July on the availability of existing facilities to provide PFR and suggested that discussions should continue but hinge on the report’s publication.
Scarp said he plans to offer an alternative package based on the feedback from the meeting.
PJM staff decided against moving for a binding vote until the group comes to a consensus or FERC responds to a request for rehearing of Order 842. The task force’s next meeting is May 23.
