PJM is pressing FERC to make a decision on the RTO’s “jump ball” capacity filing, arguing that the commission is within its authority to do so and pointing out what it considers to be hypocrisy in opponents’ criticism of the filing (ER18-1314).
The RTO’s 38 pages of comments filed May 25 pushed back on widespread condemnation of PJM’s proposal that FERC choose between two plans to isolate subsidized resources within its capacity auction in order to prevent them from suppressing prices. (See PJM Capacity Proposals Widely Panned.)
PJM reiterated its claim that the “status quo is not an option,” arguing that either its own capacity repricing proposal or the MOPR-Ex developed largely by PJM’s Independent Market Monitor would be reasonable. It also addressed concern about asking FERC to choose between the proposals, contending that it could have filed its repricing proposal first and — if rejected — then filed the MOPR-Ex.
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
But PJM neglected to address the question of how it would have prioritized which of the proposals would’ve been filed first. The RTO received significant criticism for filing its own proposal — which would give subsidized units a capacity obligation but remove their influence from the calculation of the clearing price — without stakeholder support. MOPR-Ex, which would extend PJM’s existing minimum offer price rule to bar subsidized resources from receiving a capacity commitment, garnered more stakeholder support but ultimately failed in an endorsement vote.
PJM argued that the decision is within FERC’s authority and represents an important issue for the commission, noting the commission’s recent approval of “MOPR-style rules” in ISO-NE, a reference to its Competitive Auctions with Sponsored Policy Resources (CASPR).
“Ample precedent makes clear that PJM’s 2018 wholesale capacity market rules fall squarely within the commission’s exclusive jurisdiction, leaving no room for argument that changes to the offer price and clearing price rules somehow exceed the commission’s authority or rob states of their authority,” PJM wrote. “Restoring wholesale prices to just and reasonable levels — meaning a price higher than the price that would have resulted had the state program been ignored — is not an intrusion into state prerogatives.”
The RTO’s comments frequently cast the criticisms of its efforts as hypocritical.
“The commission should consider carefully each of these narratives, which in essence amounts to two sides of a single coin,” PJM said. “A curious outcome of all the advocacy around price consequence is discovery that the same parties claiming PJM’s prices are too low, in the next breath, argue for state and federal subsidy programs because such programs will prevent PJM’s prices from rising.”
PJM identified those parties as “several companies owning legacy coal and nuclear generation.” The RTO also disparaged a Brattle Group report on the price impacts from closing nuclear plants in Ohio and Pennsylvania as “so astonishingly incomplete they leave no doubt as to the political calculation behind their preparation.”
PJM noted that clearing prices were higher in its Base Residual Auction for delivery year 2021/22 and that roughly 7,000 MW of nuclear power failed to clear. The higher prices helped the resources that did clear.
“The nearly 20,000 MW of nuclear resources that did clear this year’s auction, along with legacy coal, gas, and renewable resources, all had their future financial picture improve markedly based on weaker units failing to clear and clearing prices responding,” PJM said.
PJM suggested that they could pay “subsidized resources a different price, recognizing their different circumstances … to alleviate the price objections some have leveled against capacity repricing.”
PJM also disputed an Exelon argument that FERC should factor in environmental externalities such as carbon, saying FERC “is not an environmental regulator.”
“Let’s be honest, or at least more direct. The PJM state programs in question are designed to retain particular nuclear resources,” PJM fired back at critics. “If the more generic goal was to reward resources for their carbon free attributes, these programs would compensate all (not just financially challenged) nuclear plants, traditional renewable resources, demand response, and new investment, including new nuclear, that furthered the carbon free goal.”
FERC on Tuesday rejected a MISO proposal to streamline the RTO’s process to define and qualify its network resources, saying the changes would cause Tariff discrepancies.
“MISO’s proposed revisions … lead to inconsistencies in its Tariff,” FERC said in denying the filing without prejudice (ER18-502).
MISO filed the change in December to eliminate a requirement that Network Resource Interconnection Service (NRIS) generators must be qualified as a designated network resource in the RTO’s Open Access Same-Time Information System (OASIS). MISO also proposed to remove a provision requiring network customers to “un-designate” extra capacity on OASIS before offering it into the RTO’s markets and annual capacity auction.
The revisions would have reduced the information customers have to provide on Network Integration Transmission Service applications, including maintenance records and whether a unit will be an internal resource. MISO characterized the requirements as nothing more than “administrative steps.”
MISO said NRIS resources already demonstrate their deliverability publicly, adding that it generally doesn’t perform an additional study when network load designates a resource with NRIS. The RTO said the move would cut down on the amount of “duplicative information” it receives and increase efficiency for itself and market participants. MISO added it had “no downstream processes that rely on the designation information of NRIS resources.”
But FERC said MISO’s plan as worded could introduce confusion among its customers.
The commission noted MISO’s proposed changes interchangeably use the terms “network load,” “transmission provider’s network load” and “network customer’s network load.” FERC had originally asked for clarification on the filing in February on similar use of the terms, and MISO responded by taking out some, but not all, of the language.
“These changes could lead to a misunderstanding of the ownership of network load,” the commission said in the May 29 order.
The Missouri Joint Municipal Electric Utilities Commission and WPPI Energy protested MISO’s filing, saying the proposed changes appeared to “erode” and “hollow out” the RTO’s current obligation to plan and provide for the firm delivery of network resources to network load economically dispatched and regulated by network customers who pay MISO’s load-ratio network service charge.
FERC said it would not address those concerns since MISO could not demonstrate its revisions were just and reasonable. MISO had contended that the two organizations misunderstood its revisions.
Trees contacting Pacific Gas and Electric distribution lines caused four Northern California wildfires last year that burned about 9,400 acres, state investigators said.
After “extensive and thorough investigations,” the California Department of Forestry and Fire Protection (CalFire) determined PG&E lines sparked the LaPorte Fire in Butte County (which burned 8,400 acres), the McCourtney Fire in Nevada County (76 acres), the Lobo Fire in Nevada County (821 acres) and the Honey Fire in Butte County (76 acres).
CalFire determined that trees contacted PG&E power lines, causing the LaPorte, McCourtney, Lobo and Honey wildfires
Tree limbs contacting lines caused the Lobo and Honey fires, and a tree falling onto power lines caused the McCourtney Fire, CalFire said in statement. The LaPorte Fire occurred after branches fell onto a PG&E power line.
While CalFire found no violation of state law related to the La Porte Fire, the other three fires were allegedly due to the utility not adequately trimming vegetation near its lines.
“The McCourtney, Lobo [and] Honey investigations have been referred to the appropriate county district attorney’s offices for review,” CalFire said.
The agency said the fires, which were among the smaller of the more than 170 fires that burned about 245,000 acres in Northern California last October, were the first to be investigated. The four fires caused structural damage but injured no civilians or firefighters.
Map showing locations of 2017 California wildfires
Wildfire liability has become a major issue for PG&E as it fights civil lawsuits and lobbies the state for a change in laws related to blazes stemming from utility equipment. The utility, as well as Southern California Edison and San Diego Gas & Electric, said they cannot be held solely responsible for increasingly high-risk fire conditions, including climate change and drought. (See Profits Down, PG&E Fights Wildfire Liability, Edison International Presses Wildfire Cost Recovery.) Aside from civil lawsuits faced by the utilities, the California Public Utilities Commission has denied SDG&E recovery for some wildfire costs.
Last month, state Sen. William Dodd (D) introduced a bill (SB 1088) that would allow utilities to recover wildfire costs if they conform to state-regulated safety plans. (See Calif. Legislation Shields Utilities from Wildfire Costs.) The Senate Appropriations Committee issued a “do pass” recommendation for the legislation on May 25. The bill was recently amended with provisions requiring that utility safety plans include a program to evaluate technological solutions such as distributed energy and allowing a utility to contract with a distributed energy operator if the operator meets insurance requirements to cover direct damages caused by failure of the distributed facilities to comply with contractual terms.
NERC: ERCOT, CAISO Face Summer Reliability Concerns
By Tom Kleckner
NERC said Wednesday that its annual summer reliability assessment indicates ERCOT and CAISO will face operational challenges and potential reliability concerns this summer, thanks to the two ISOs’ respective loss of baseload generation and lack of fuel assurance.
According to the agency’s summer assessment, ERCOT faces a generation shortfall “due in part” to the retirement of about 4.5 GW in coal-fired generation last fall and construction delays of about 2.1 GW in new resources. California is facing a limit on natural gas output due to Aliso Canyon storage facility constraints, NERC said.
“It’s very important to focus on the operational aspect,” said Thomas Coleman, NERC’s director of reliability assessments, during a conference call with reporters Wednesday. “We can’t do much at this point [about resource adequacy]. We want to draw attention to how we are prepared … from an operational standpoint.”
FERC earlier this month said it would be closely monitoring ERCOT and Southern California for reliability issues this summer. Both regions lie in a portion of the Western United .States. expected to be warmer than usual. (See FERC Keeps Eye on ERCOT, CAISO as Hot Summer Approaches.)
Coleman said the majority of NERC’s assessment areas “maintain sufficient resources” to meet their reference planning reserve margins this summer. The exception is ERCOT, which saw its reserve margins drop from 18% last year to a projected 10.9% this year with the coal plant retirements and delay in new resources. Given the ISO’s 13.75% planning reserve margin, ERCOT faces a capacity shortfall of 2 GW, NERC said.
No Cause for Alarm?
A Texas Reliability Entity assessment expects the ISO could be required to deploy ancillary services and contracted load control programs during peak demand periods. NERC’s study cautions that “typical generator outages expected under normal conditions” could limit ERCOT’s ability to maintain operating reserves.
Coleman said NERC took it one step further and ran an operational risk analysis that looked at typical maintenance or forced outages, extreme forced outages, extreme weather and a low-wind scenario.
“Any one of those events would drop [ERCOT] below its operating reserve margin” (of 2.3 GW) and lead to energy emergency alerts,” Coleman said, noting that operational challenges occur during times of peak demand, low wind output, and generator outages.
“When we don’t have the wind available, those are the types of scenarios we want to pay attention to,” he said.
NERC’s study finds the risk of load shedding caused by insufficient reserves in ERCOT’s footprint would increase under extreme summer conditions, such as above-normal temperatures and higher-than-expected generation outages.
However, the Texas grid operator has assured stakeholders there is no reason for alarm, and said it plans to address the projected generation shortfall by seeking voluntary load reductions from utilities, if needed. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Asked about a repeat of severe weather, as ERCOT experienced last August with Hurricane Harvey, Coleman said NERC was “encouraged by the level of resilience in the system last year.”
“We’ve gotten better about handling those types of events,” he said, noting most outages occur at the distribution level and don’t affect the bulk electric system. “During hurricanes, when we have distribution outages, there’s less load, so that doesn’t necessarily pose challenges.”
California Challenges
Coleman said NERC feels “very comfortable” about CAISO’s reserve margins, but also noted the Aliso Canyon operational constraint continues to affect the availability of natural gas in Southern California, increasing ramping requirements. Below-normal hydro generation is also projected to exacerbate the potential reliability concern, according to the NERC assessment.
“If we don’t have [the] ability to get the fuel there, we could have operational challenges,” Coleman said.
NERC said the need for fast-ramping gas generation and other flexible resources across California also presents a reliability challenge for the bulk power system this summer because of the state’s high penetration of renewables. CAISO in March set an all-time record when 49.95% of demand was served by transmission-connected solar.
The California grid declared its first stage 1 emergency in 10 years last May. In October, it activated demand response measures, but did not require any load shed.
NERC’s study saysid MISO has a summer reserve margin of 19.1%, above its target reserve margin of 17.1%, due to increased forced outage rates. It is expected to increasingly rely increasingly on emergency operating procedures to access resources needed to meet load and operating reserves.
MISO’s actions are anticipated to provide sufficient energy or load relief to cover the normal forecasted system conditions, the agency said. Coleman said the ISO acknowledges a 79% chance it will experience at least one level 1 emergency this summer.
NERC conducts its reliability assessments to “provide a high-level view of resource adequacy and to identify issues that have the potential to impact bulk power system planning, development and system analysis over the summer months.” The summer assessment covers June through September.
FERC last week granted Brookfield Energy Marketing a one-time NYISO Tariff waiver allowing the company to avoid paying a penalty for a clerical error related to its external capacity resource interconnection service (CRIS) rights offer obligation (ER18-1177).
External CRIS rights provide their holder with a long-term ability to import capacity into the New York Control Area but require the holder to commit to supplying a specified number of megawatts of external installed capacity (ICAP) to the NYCA for a period of at least five years through one of NYISO’s auctions.
Brookfield’s 296-MW Holtwood Hydropower Station in Pennsylvania.
Any entity failing to offer capacity in accordance with Tariff requirements incurs a financial penalty equal to 1.5 times the ICAP Spot Market Auction clearing price, multiplied by the number of megawatts committed.
Brookfield said that an employee submitting the company’s offer for the ISO’s January 2017 ICAP auction inadvertently omitted a detail that would have automatically associated the offer with the company’s CRIS rights and satisfied the remainder of its offer obligation. The company contended that it discovered the error too late to be remedied by other means.
Brookfield claimed it acted in good faith and that the waiver would be limited in scope. The ISO did not oppose Brookfield’s waiver request, stating the problem did not affect market outcomes or impair other market participants’ capacity import offers.
The commission agreed but reminded “Brookfield, and other entities holding external CRIS rights, of the importance of fulfilling NYISO’s Tariff requirements in a careful and timely manner.”
FERC last week ordered Entergy and the Louisiana Public Service Commission to provide it with more information to determine whether its past decision not to order refunds in the ongoing dispute over the company’s equalization of production costs remains appropriate.
FERC’s voluntary remand of its decision revives the possibility that Entergy may be required to issue refunds over its multistate system agreement (EL01-88-019).
Galvez Building housing the Louisiana Public Service Commission | LA.gov
“Having re-examined the matter, the commission seeks further submissions by the parties on whether refunds are appropriate given the circumstances presented in this case,” FERC said in a May 22 order.
The commission set the matter to a paper hearing and ordered Entergy and the Louisiana PSC to submit initial briefs and evidence on refunds within 30 days.
The issue dates to 2001, when the PSC and the New Orleans City Council filed a complaint with FERC, arguing that Entergy’s allocation of production costs among its operating companies in its 1982 multistate system agreement had become unfair.
In the past, the operations of Entergy’s subsidiaries were more integrated, with different transmission and generation facilities functioning as a single electric system. Entergy’s system agreement consisted of several service schedules that allocated costs among the operating companies according to a responsibility ratio.
In a 2005 order, FERC found that Entergy’s allocation of production costs across its subsidiaries was no longer in rough equalization. And while the commission required Entergy to employ a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average, it declined to order refunds for the years prior to the bandwidth calculations.
The commission originally found that the Federal Power Act prohibits refunds among electric companies of a registered holding company “to the extent that one or more of the electric companies making refunds cannot surcharge its customers or otherwise obtain retroactive cost recovery.” FERC also said that there was no evidence in the record that the operating companies making refunds could receive a retroactive recovery of their costs and rejected the PSC’s request for a rehearing over refunds.
The D.C. Circuit Court of Appeals in 2008 remanded the case back to FERC, questioning whether the commission had adequately supported its decision not to order refunds. However, by 2014, FERC had again declined to order refunds in another rehearing requested by the PSC.
FERC now says the PSC’s past arguments are influencing its decision to revisit the possibility of refunds.
In March, the D.C. Circuit decided that no refunds were necessary in a closely related case involving Entergy’s multistate system agreement. In that case, FERC also determined Entergy’s practices were unfair because the company’s formula for determining peak load responsibility included interruptible load in addition to firm load. (See No Refunds in 20-Year-Old Entergy Rate Complaint.)
Public Service Electric and Gas appears to be out of targets to help it pay for its $1.2 billion Bergen-Linden Corridor (BLC) project. FERC last week denied a complaint from the New Jersey Board of Public Utilities to reallocate the project’s costs, leaving PSE&G to pay for most of the project meant to support the “wheeling” arrangement Consolidated Edison terminated in April 2017 (EL18-54).
For decades, Con Ed paid to wheel 1,000 MW of power through PSE&G’s facilities in northern New Jersey for delivery to New York City. But Con Ed terminated the deal after PJM attempted to allocate $720.4 million of the project’s costs to it through the RTO’s Regional Transmission Expansion Plan. Two merchant transmission facilities that connect northern New Jersey to New York City — Hudson Transmission Partners and Linden VFT — were allocated $103.2 million and $9.6 million, respectively, and PSE&G was assigned $88.4 million.
FERC initially approved reassigning $530.8 million of Con Ed’s allocation to Hudson and $122 million to Linden. But that was nixed after the merchants successfully petitioned FERC to amend their interconnection service agreements and reduce their responsibility. (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)
| PJM
The BPU filed its complaint just days after FERC allowed the ISA changes, arguing that PJM’s Tariff and its joint operating agreement with NYISO don’t properly allocate the costs of some RTEP projects to merchant transmission facilities and other transmission customers.
After the “wheel” was canceled, PJM and NYISO agreed to maintain a smaller 400-MW version, called the operational baseflow (OBF), until the separate systems were stabilized to operate without the flow. The BPU argued that the way the grids interact provides a benefit to NYISO for which PJM customers, specifically those in New Jersey, aren’t being compensated.
“NYISO continues to model flows over the lines previously used for the Con Edison wheeling arrangement for purposes of determining its resource adequacy requirement, while PJM models its system with little or no support from NYISO,” the BPU told FERC.
Therefore, NYISO doesn’t need to maintain as much capacity while New Jersey must procure more. PSE&G’s zone often clears separately from the rest of the RTO in PJM capacity auctions. In last week’s Base Residual Auction for the 2021/22 delivery year, for example, it cleared at $204/MW-day versus $140/MW-day for much of the RTO. (See Capacity Prices Jump in Most of PJM.)
The BPU complaint said that without the relief the regulators requested, the PSE&G locational deliverability area’s capacity costs will jump by as much as 78.6%, “or an increase of $275 million in a single year and reoccurring annually for the foreseeable future.”
Because the Bergen-Linden project was meant to address reliability issues created by the “wheel,” it’s only fair those beneficiaries should pay for them, the BPU said.
“Parties have sought to escape those costs by terminating or otherwise amending contracts,” the BPU told FERC.
NYISO responded that costs can’t be allocated in New York because the project is fully within PJM’s boundaries, and that it no longer relies on the facilities for reliability. PJM said that “it is the physical features of the transmission system in northern New Jersey that are driving the need for the BLC project.”
Con Ed, Linden, Hudson, the New York Power Authority and several other New York stakeholders argued against the complaint. PSE&G, the New Jersey Division of Rate Counsel, the Public Power Association of New Jersey, PJM’s Independent Market Monitor and other RTO stakeholders supported the complaint.
The commission agreed with opponents of the complaint that the BLC was planned solely through PJM’s RTEP, that NYISO never agreed to pay for any of it and that the PJM-NYISO JOA “does not preclude the sharing of these benefits without compensation, even if those benefits are not equal at a given point in time.”
It also said the merchant transmission facilities can have their service curtailed for reliability or economic reasons now, so they can’t effectively replicate the firm priority benefits they had before and therefore shouldn’t be held accountable for any upgrades that support that priority.
FERC declined to rule on whether those facilities should be eligible to sell capacity in NYISO, saying that was out of the scope of the complaint.
VALLEY FORGE, Pa. — PJM doesn’t plan to contest a FERC ruling that may have contributed to the increase in demand response clearing in last week’s Base Residual Auction, Senior Vice President of Operations and Markets Stu Bresler told Thursday’s Markets and Reliability Committee meeting.
On May 8, the commission rejected rule changes PJM developed to discourage market participants from selling capacity in the BRA and buying back their obligations at lower prices in Incremental Auctions, a practice that has led to concerns that arbitrageurs are offering capacity they have no intention of providing. The Independent Market Monitor says DR providers disproportionately replace BRA commitments in the IA. (See FERC Closes Book on PJM’s ‘Paper Capacity’ Concerns.)
“At this point, PJM does not intend to seek rehearing,” Bresler said, noting FERC’s “strongly worded” rejection of the filing to revise IA rules, which also terminated a related Section 206 proceeding.
PJM plans to allow the 30-day rehearing window to expire and then meet with FERC to discuss the RTO’s next steps, he said. FERC staff had told PJM that they wouldn’t entertain a prefiling meeting on the IA revisions because of the outstanding 206 proceeding on the issue. By letting both expire, Bresler said he believes FERC will be willing again to discuss the issue.
“We do intend to bring this back to stakeholders about how to move forward,” he said. “We think a discussion with FERC would be very valuable.”
FERC’s May 8 ruling may have played a role in why more DR cleared as annual resources in the BRA for delivery year 2021-22. DR offered into the auction increased almost 21% to 11,887 MW, nearly 94% of which cleared. Of the 11,126 MW of DR that cleared — up 3,305 MW from last year — 96% cleared as annual Capacity Performance and 452 MW cleared as summer-only resources that were aggregated with other products to meet CP’s requirement for year-round commitment. (See Capacity Prices Jump in Most of PJM.)
DR participants have complained that they can’t receive a capacity commitment because they struggle to meet CP’s year-round requirement and have requested seasonal products. But several MRC members speculated they might have been more emboldened to take the risk because FERC’s decision ensured at least one outlet remains. PJM’s IA revisions were meant to close a loophole that allows market participants to receive higher prices for supply obligations in the BRA and pay less in subsequent IAs to offload those commitments.
VOM Remanded
Stakeholders at last week’s MRC meeting were spared an expected showdown on variable operations and maintenance (VOM) cost accounting after Rockland Electric’s Brian Wilkie indicated an interest in deferring the vote. The idea ended up being motioned and seconded by others, but stakeholders were happy to endorse it and return the issue to the Market Implementation Committee.
Monitor Joe Bowring was prepared to make a presentation in defense of his proposal on the issue, but stakeholders preferred to address it at the lower committee, where the proposal earlier failed to receive an endorsement to be considered at the MRC. (See “VOM Proposal,” PJM Market Implementation Committee Briefs: April 4, 2018.)
Offer Cap Revisions Stalled Again
Two sets of changes to Manual 11: Energy & Ancillary Services Market Operations were approved by acclamation, but a third set dealing with offer caps was sent back to the MIC for additional review.
The approved changes focused on bidding and unit-parameter submissions. The first set includes conforming changes regarding bidding locations for virtual transactions. The second set expands the window for when generators can make intraday offers. (See “Intraday Offers,” PJM Market Implementation Committee Briefs: May 2, 2018.)
The revisions returned to the MIC were developed to ensure consistency between the manual and Operating Agreement regarding price-based offers over $1,000/MWh. The change was necessitated by FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. (See “Offer Cap Resolution,” PJM Market Implementation Committee Briefs: May 2, 2018.)
PJM’s Susan Kenney said the discrepancies occurred because the Order 831 compliance filings failed to appropriately update the Tariff and OA, so the manual’s $1,000/MWh cap conflicts with the OA, which permits price-based offers to exceed $1,000/MWh if they are less than a verified cost-based offer. As an immediate fix, PJM is proposing capping all offers at $1,000/MWh by default and allowing higher offers to submit a request for verification. The system will be automated once the capability has been developed.
For price-based offers, PJM is “strongly” suggesting operators allow a “switch to cost” option that excludes price schedules from dispatch. Otherwise, they can request the ability to submit price-based offers in line with verified cost-based offers, but they are then on the hook to ensure price-based offers at each segment remain compliant with verified cost-based offer caps.
The Monitor argues the solution should be holistic to include a full implementation in PJM’s offer submission software and related manual changes. Until then, PJM should seek an exception from FERC to use the revised “switch to cost” method, which includes the $1,000/MWh cap, the Monitor said.
Last month, Manual 11 revisions to correct inconsistencies with PJM’s governing documents regarding offer caps failed to receive MRC endorsement and were sent back to the MIC as well.
Long-term FTRs
PJM and the Monitor presented members with separate proposals to revise the long-term financial transmission rights market.
The proposals are meant to correct current processes that allow participants in the long-term FTR market to obtain the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. Both proposals would do away with the “year all” product in the market and only offer annual products for each of the next three years.
PJM’s proposal would model all ARRs that clear in the annual model as fixed injections and withdrawals in the long-term auction model. Any transmission outages that would impact the ARRs would be removed. PJM argues this would accurately represent any residual capability left on the system.
The Monitor’s proposal would set the residual capability for the auction at zero and require all prevailing-flow capability to be generated from counterflow FTRs. The Monitor’s Howard Haas argued this would eliminate the risk of any overallocation between the long-term auction and annual auctions and establishes counterparties in the market.
“We think it’s going a little too far,” PJM’s Tim Horger said of the Monitor’s proposal.
“We think PJM’s going in the right direction … but it does not go far enough,” Haas said in response.
Horger said he was interested in seeing what the “true capability” is in the long-term model.
Members will be asked to endorse one of the proposals at the June MRC.
Stakeholders Approve Changes to Manuals, Operations
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 36: System Restoration. Revisions developed as part of the manual’s annual review; includes clarifications regarding synchro-check relays, blocking governors and black start generators.
Manual 3: Transmission Operations. Biannual review to update operating procedures. Revisions update remedial action schemes, sectionalizing schemes and definitions for the Cleveland and Eastern interfaces; designate voltage limits for Ohio Valley Electric Corp.’s impending integration; add language regarding reactive reserve check submittals; and clarify notes on load shed activity.
Manual 14A: New Services Request Process. Annual review. Revisions developed to introduce the Queue Point software for submitting data for feasibility and system impact studies.
Manual 7: Protection Standards. Revisions developed by the Relay Subcommittee to add clarity, update terms and add reliability requirements.
OA revisions allowing PJM to share member confidential information with the Eastern Interconnect Data Sharing Network (EIDSN) in addition to NERC and other reliability entities. EIDSN was created in 2014 to develop industry tools that NERC has decided it no longer wants to create and maintain.
Comments filed with FERC last week indicate most stakeholders oppose ISO-NE’s Tariff waiver request to keep the Mystic generating plant running despite Exelon’s plans to retire the facility (ER18-1509).
Commenters also questioned the RTO’s rationale that an out-of-market mechanism is needed to financially support the nearby Distrigas LNG terminal being acquired by the company.
Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.
Massachusetts Attorney General Maura Healey raised “significant questions regarding the legality of using the commission waiver process in the expansive way ISO-NE seeks to do here.”
The RTO is asking to do something it has never been allowed to do before, Healey said, namely to “retain a generation facility pursuant to the [Forward Capacity Market] process not for capacity needs but to ensure ‘fuel security,’ a term that is not defined in the Federal Power Act, and a concept for which there is no settled or universally accepted definition.”
Healey also opposed the request as “sweeping in its breadth” in seeking to waive for one generator almost all of the Tariff’s FCM retirement requirements and existing retirement deadlines, and take away its existing limits on Exelon’s ability to recover costs under a cost-of-service agreement.
New England local distribution companies supported the waiver request in order to maintain reliability in the region and took no position on the cost-of-service representations made by Mystic.
“The lack of sufficient natural gas infrastructure makes facilities that rely on LNG particularly valuable in the region,” the LDCs said. “There is no immediate, viable replacement should the [Distrigas] terminal shut down and efforts to replace the products and services provided from Distrigas would be lengthy and difficult.”
ISO-NE’s Reasoning
| ISO-NE
ISO-NE last month announced the plan to keep Mystic running after Exelon said in March that it planned to retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022. (See ISO-NE Moves to Keep Exelon’s Mystic Running.) On May 1, the RTO filed a motion to waive its Tariff to retain resources to address fuel security risks — an option currently allowed only in response to local transmission security issues.
The RTO said the loss of Mystic 8 and 9’s 1,700 MW of combined cycle capacity that don’t rely on pipeline gas would lead to it depleting 10-minute operating reserves — a violation of NERC standards – “on numerous occasions” and shedding load during the winters of 2022/23 and 2023/24.
Shuttering Mystic also would mean the loss of the Distrigas LNG facility’s biggest customer, raising doubts about its financial viability, the RTO said.
Exelon’s proposed cost-of-service agreement for Mystic, filed May 16, seeks an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24 (ER18-1639).
ISO-NE asked the commission to approve the waivers by July 2 to meet market participants’ deadlines for committing to Forward Capacity Auction 13.
Exelon said it would continue operating Mystic 8 and 9 only if it receives a two-year reliability-must-run contract ensuring it can recover its full cost of service for 2022/23 and 2023/24.
While ISO-NE will not implement the full payments and penalties under its Pay-for-Performance program until 2025, even then the program “cannot be expected to resolve the region’s fuel security challenges by itself, particularly in light of the significant opposition in the region to investments in fuel supply infrastructure,” the RTO told FERC in its waiver petition.
ISO-NE could implement a market-based fuel security solution as early as 2020, if it is decoupled from the FCM, or as late as 2024 if it’s included in the capacity market, but it’s still unclear what form the solution will take and therefore difficult to predict when the market will mature enough to resolve the fuel security issues that require Mystic 8 & 9’s retention, the petition said.
Market Failure?
New England Power Pool said it took “no substantive position” on the RTO’s request and that its “keen interest is in ensuring that ISO-NE engages fully with its stakeholders before seeking any change to the New England Tariff or market rules.”
NEPOOL said it expected the RTO to honor its commitment that the full participant processes would be completed prior to any filing of a longer-term market-based approach to fuel security issues.
The Environmental Defense Fund said in its filing that “the need for cost of service is indicative of market failure. Cost of service for the purpose of ensuring fuel availability (i.e., maintaining Distrigas’ natural gas supply capability), compels the commission and New England stakeholders to assess whether the market elements relevant to fuel supply for electric generators are functioning effectively. It is clear they are not.”
Distrigas Terminal | ENGIE
EDF recognized the Mystic/Distrigas units play a critical reliability role in the region but asserted that the “out-of-market workaround runs counter to ISO-NE’s dual mission of ensuring reliability and the long-term sustainability of competitive markets.”
The Northeast Gas Association said that while the waiver is a short-term solution supporting market reliability, “a longer-term remedy still needs to be enacted.” It urged the commission to consider “the importance of maintaining regional LNG access” over the coming capacity commitment periods.
Price Suppression
The Electric Power Supply Association said the “premature and overbroad” request should be rejected without prejudice, allowing the RTO to submit another short-term proposal if it is unable to develop a market-oriented solution.
The RTO “is being too quick to give up on such a solution for the nearer term and, specifically, for the 2022-2023 and 2023-2024 commitment periods,” EPSA said. “Additionally, this near-term fix may have the adverse effect of hastily establishing a new reliability criteria to be used to underpin RMR-type arrangements going forward, in the absence of any formal process, stakeholder input or Tariff revision proceeding.”
While the two-year term of the proposed RMR or cost-of-service agreement “is both unprecedented and will severely suppress capacity prices over that longer term,” EPSA said it also risked, by artificially dampening capacity prices, creating “the very dynamics” that cause the fuel security concerns raised by the RTO.
The New England Power Generators Association said allowing the RTO to offer the Mystic units as $0/kW-month price takers in FCA 13 would suppress prices by $214 million to $652 million, displacing 1,050 to 1,285 MW of other resources, “with the potential for even greater price suppression and displacement in FCA 14.”
Instead, NEPGA said ISO-NE should conduct a Substitution Auction to reprice Mystic, the same way it plans to reprice state-sponsored renewable resources under the Competitive Auctions and Sponsored Policy Resources design approved by the commission. The trade group made the same arguments in a Section 206 complaint (EL18-154) also filed last week.
Why Hurry?
Calpine said it did not oppose the RTO’s request but questioned the need for action now, as the Mystic units have capacity supply obligations through May 31, 2022.
Nevertheless, Calpine said the waiver request “is a symptom of broader price formation issues that are preventing” the FCM from attracting sufficient investment in new and existing resources to maintain reliability.
Until these issues are resolved, Calpine said, it is likely that New England “will continue to experience premature retirement of resources critical to ensuring fuel security and that ISO-NE will increasingly be forced to rely on out-of-market procurement to maintain reliability.”
NRG Energy said waiver of the RTO’s capacity market rules “is not the appropriate approach to address the lack of fuel security in New England” and that the commission should order the RTO to develop a market response to procuring the necessary attributes.
Rejecting the waiver “does not mean blacking out New England,” NRG said. “Even should efforts to develop a market-based solution to the fuel security conundrum fail, the Federal Power Act includes a reliability ‘fail safe.’”
NRG concluded that the reliability product the RTO wants is not what the waiver aims to procure: “ISO New England argues that the waiver will allow it to procure additional winter energy production from non-pipeline gas-fired resources; yet the waiver is focused on allowing Mystic to continue selling a capacity product.”
Pipeline Constraints
The Industrial Energy Consumer Group said the RTO has warned of the danger of gas pipeline constraints since 2001. “Despite the obvious nature of this need, ISO-NE has repeatedly either brought forward market-based solutions that have failed to provide sufficient financial support to promote the construction of necessary pipeline facilities or offered interim out-of-market solutions, such as its Winter Reliability Program and the waivers requested in this proceeding,” the group said. “None of these have succeeded in causing pipeline capacity to be built.”
It asked FERC to order ISO-NE to file Tariff amendments allowing electric utilities to collect gas pipeline capacity costs.
“In addition, the commission should open a proceeding to facilitate new gas pipeline capacity resources into and within the New England region,” the group said. “Such a proceeding could also address, if necessary, the apparent refusal of New York to issue federally delegated permits for pipelines from Pennsylvania to New England.”
The Eastern New England Consumer-Owned Systems said the proposal could cause “permanent, structural damage” to ISO-NE’s capacity market.
“The waiver requested by ISO-NE is actually a stalking horse for injecting an untested, undefined and undebated construct of ‘fuel security’ into the pricing of capacity in New England,” the group said.
It said it believes Exelon is overstating Mystic’s financial problems and that the company’s planned acquisition of Distrigas from ENGIE raises competitive concerns because of the facility’s role in providing east-to-west gas when high heating demand constrains west-to-east capacity.
“The market power implications of consolidating that kind of critical-period capability with significant regional generation ownership deserve careful evaluation before the consolidation occurs,” the group said.
California will need between 229,000 and 279,000 electric vehicle chargers at locations other than single-family homes by 2025 to meet the state’s goals for adoption of zero-emission vehicles, the Energy Commission said in a new report.
The higher range of the estimate includes 133,000 workplace and public chargers, 9,000 to 25,000 fast chargers and 121,000 chargers at multifamily dwellings, the commission said. The numbers do not include chargers in single-family homes.
There is a projected need in California for up to 279,000 non-single family home chargers by 2025.
A March 2012 order by Gov. Jerry Brown directed the commission to support the goal of 1.5 million zero-emission vehicles on state roadways by 2025. Another January 2018 order by Brown called for the construction and installation of 250,000 zero-emission vehicle chargers, including 10,000 DC fast chargers, by 2025.
According to the new CEC study, the state’s goal is to allow drivers to maximize the number of electric miles they can drive, provide guidance on plug-in electric vehicle (PEV) and plug-in hybrid charging, and ensure the effectiveness of private and public sector investments. As of the end of last year, the state had about 14,000 public chargers — 1,500 of them DC fast chargers — serving 350,000 PEVs.
For the study, CEC staff worked with the National Renewable Energy Laboratory to develop a computer simulation tool known as the Electric Vehicle Infrastructure Projection Tool (EVI-Pro). The commission plans to add an EVI-Pro portal to its website to allow users to view charging station quantities, load shapes, infrastructure cost estimates and other information.
At a CEC workshop on Tuesday, analysts discussed three central questions around charging infrastructure: how many chargers to deploy, what kind of chargers and where to locate them. A big part of determining where to place chargers is understanding the behavior of vehicle operators and studying patterns such as worker commutes and rural versus urban settings.
“What we’re really talking about is trying to reduce range anxiety as a barrier to increased PEV sales,” NREL’s Eric Wood, one of the study’s authors, said at the workshop.
EVI-Pro focuses on behaviors of mainstream drivers, such as origins, destinations and schedules, as opposed to those of early EV adopters. Mainstream drivers are more likely to favor convenience and less likely to alter driving habits, for example. The modeling also studied how different charging locations such as home or work might be chosen based on the price of electricity, and how users charging for free at work might block other chargers and drive up costs of workplace charging.
The study used four major inputs: vehicle attributes, charger attributes, county-level household travel data and composition of the vehicle fleet. It calculated several charger-per-1,000-PEVs ratios under differing technology and market scenarios.
The transportation sector is the largest polluter in California, responsible for 80% of nitrogen oxide emissions and 90% of diesel particulates. Including indirect emissions from fuel refining and production, transportation accounted for “nearly half” of the state’s greenhouse gas emissions as of 2015, the report said.
The study showed that weekday charging peaks occur when vehicles arrive at work in mornings and when they arrive home in evenings. By 2025, workplace chargers on weekdays will draw more than 200 MW at 9 a.m. and residential chargers nearly 900 MW at 8 p.m. By 2025, aggregate demand from residential, workplace and fast-chargers will push up demand by 500 MW from 4 to 7 p.m., with a maximum demand of nearly 1,000 MW before 8 p.m.
The commission said that an important conclusion of the study is assuring drivers that charging infrastructure will be visible, accessible and reliably maintained, with real-time networking technologies being a valuable tool. Networked technologies will enable shared usage of chargers and reduce the size of the network needed to support the growing electric fleet.
