MISO still has a handful of details to address before fully complying with FERC Order 845, the commission ruled last week.
FERC on Thursday directed the RTO to submit another compliance filing within 60 days to clear up its study process related to technological advancements, partial service requests and contingent facilities (ER19-1823-001, ER19-1960).
The commission found that MISO only partially complied with its directive that a customer be able to request interconnection service below its full generating facility capacity. It said the RTO omitted mandatory Tariff language showing that while interconnection service will be studied at the requested level, a project could be “subject to other studies at the full generating facility capacity to ensure safety and reliability of the system, with the study costs borne by the interconnection customer.”
| MISO
FERC also directed MISO to explain why it gave itself 60 days to decide whether to conduct additional studies when an interconnection customer seeks to include technological advancements in its project prior to an interconnection facilities study agreement. The commission had previously prescribed 30 days to settle on any new studies and told MISO to either justify the two months or halve the timeline.
“While we understand that MISO has a large number of projects in its queue and a wide variation in studies that may be needed, we find that MISO has not justified its proposal to allow it 60 days from the date of receipt of additional information from an interconnection customer or merchant HVDC connection customer to conduct further studies,” the commission said.
Finally, MISO must include a fuller description of how it determines which projects in its annual Transmission Expansion Plan are “contingent facilities.” FERC Order 845 defines those facilities as a generation project’s unbuilt interconnection facilities and network upgrades that, if delayed or canceled, “could cause a need for restudies of the interconnection request or a reassessment of the interconnection facilities and/or network upgrades and/or costs and timing.”
Surplus Interconnection Proposal Just Fine
FERC found that MISO easily complied with a directive that RTOs establish an expedited queue process allowing interconnection customers to use or transfer surplus interconnection service at existing facilities.
MISO submitted a partial compliance filing in May to address the surplus interconnection directive. It proposed to rename its existing net zero interconnection option to “surplus interconnection service” and include interconnection and steady state analyses, while removing an existing competitive solicitation process for surplus interconnection service and clarifying that the original interconnection customer or affiliates have priority rights to any surplus service. (See Little Work Needed to Comply with Order 845, MISO Says.)
ISO-NE on Friday announced its first competitive transmission solicitation to address reliability concerns associated with the upcoming retirement of the Mystic Generating Station in Everett, Mass.
The request for proposals seeks to address transmission facility overloads under peak load conditions in the Boston area, as well as system restoration concerns with the underground cable system in the area.
The RTO will review all the proposals in a two-step process before selecting the preferred solution. The deadline for phase 1 proposal submissions is 11 p.m. on March 4, 2020.
ISO-NE and its Planning Advisory Committee will review the proposals to ensure they address the identified needs and are feasible and cost competitive. The RTO will then identify finalists, who will be required to provide additional details to guide its selection of the preferred solution.
Greater Boston area electrical distribution map | ISO-NE
Exelon announced last year that it would retire Mystic in 2022, but FERC approved a cost-of-service agreement between the company and ISO-NE to keep Units 8 and 9 operating through May 2024.
Under the competitive process, any qualified transmission project sponsor (QTPS) may submit a phase 1 proposal, while NSTAR Electric and New England Power are required to submit a joint backstop transmission solution for consideration in response to the RFP.
According to the ISO-NE 2019 Regional System Plan (RSP) posted on Oct. 31, “the peak load needs were found to be non-time-sensitive because the needs were present in the study horizon cases of 2028 but were not observed in the time-sensitive cases of 2022.”
Greater Boston area generating units over 100 MW | ISO-NE
In addition, the system restoration need for reactive support is considered a non-time-sensitive need because the retirement date of Mystic 8 and 9 is beyond the three-year time-sensitive period, the RSP said.
The competitive solution process is detailed in Attachment K, Section 4.3 of the Tariff.
The pro forma agreement between the RTO and the selected QTPS spells out the development, design and construction of the project, including project milestones, status reports and cost-containment measures.
The RTO modeled its agreement on the designated entity agreement that PJM uses in its competitive transmission solicitation process.
NYISO’s Management Committee on Wednesday recommended that the Board of Directors approve creating a short-term reliability process (STRP) to evaluate and address reliability impacts.
Keith Burrell, the ISO’s manager of transmission studies, presented the proposal and said the STRP may result from both generator deactivation and transmission facility reliability needs identified in a quarterly short-term assessment of reliability (STAR) study.
The new setup would enable NYISO to respond to changes on the system in a timely fashion while providing a better structure than the ad hoc generator deactivation process to address observed needs, and improve workload management for the ISO and responsible transmission owners, according to Burrell.
Revisions would be applied to Tariff sections 23.4.5.6 and 30.4, which were posted on the ISO’s website on Dec. 17 at the request of the Independent Power Producers of New York.
Related Tariff changes would expand the generator deactivation rules to apply to non-market participants that possess the authority to decide whether or when to deactivate a generator. To address non-market participants, the revisions include changes to the generator registration documents and the creation of a new responsible generator party certification.
The proposed revisions include a de minimis threshold of 1 MW to excuse generators with a lower nameplate rating from the obligation to comply with the generator deactivation rules in the STRP before they are permitted to deactivate.
The ISO anticipates February 2020 board approval and would file revisions with FERC requesting a May 1, 2020, effective date. With FERC acceptance, the first STAR would commence July 15, 2020.
The 2020 Reliability Needs Assessment would incorporate the effects of the Tariff changes.
NYISO Strategic Plan 2020-2024
Executive Vice President Emilie Nelson presented NYISO’s Strategic Plan for 2020-2024, saying that stakeholders want the ISO to continue to be an authoritative source of information for policymakers.
“We heard that we need to focus on our planning processes and that the class year work needs to be streamlined,” Nelson said. “Passage of the Climate Leadership and Community Protection Act further emphasized the need to continue to think through strategic priorities for the next five, 10 and even 20 years.”
The new law (A8429) requires 70% of the state’s electricity to come from renewable sources by 2030 and for power generators to be zero-emitting by 2040. It also raises the installed solar target to 6 GW by 2025 and calls for the state to procure 9 GW of offshore wind by 2035.
CEO Rich Dewey said the board concluded that “we’re working on all the right stuff but wanted us to think about the pace of change.”
“Given CLCPA, there’s going to be tremendous pressure on the schedule, and we need to move more deliberately and quicker than we have in the past,” Dewey said. “If you look at how much renewable and distributed energy resources are going to need to come online to achieve the goals, the pace of change will be faster than anything we’ve ever seen.”
EMS Update, New Reliability Metrics
Dewey said NYISO is working to deploy by Feb. 1 a new energy management system and business management system, both delayed in October because of problems related to stability and synchronization of data. (See “New System Software by March,” NYISO Management Committee Briefs: Nov. 20, 2019.)
To enhance reliability performance metrics, NYISO has begun to measure daily and monthly net load forecast performance against 30-minute and hour-ahead forecast errors. | NYISO
“We moved into our parallel test window today and are running two systems side by side,” Dewey said. “We want to be ready for deployment as early as possible in 2020, as early as Feb. 1, if the weather permits.”
COO Rick Gonzales highlighted the use of new graphs in the monthly operations report to reflect enhanced reliability metrics, with the ISO now measuring daily and monthly net load forecast performance against 30-minute and hour-ahead forecast error.
“Significant and rapid change” will cause short-term challenges with resource adequacy in some regions, but utilities should be able to turn the evolving resource mix to their advantage with appropriate planning, NERC said last week.
NERC’s 2019 Long-Term Reliability Assessment reported that most regional entities had sufficient resource capacity to meet projected demand over the next 10 years. The two exceptions were ERCOT and Northeast Power Coordinating Council-Ontario, both of which were assessed as “marginal” because of anticipated shortfalls in generating capacity in the next five years.
In the case of ERCOT, the deficiency — about 4,900 MW by 2024 — is largely a result of the canceling of several planned wind, natural gas and compressed air energy storage projects, totaling about 3,900 MW, along with last year’s retirement of the 470-MW Gibbons Creek coal-fired plant. NERC also revised its summer peak demand forecast in the region upward by about 1,300 MW per year from 2019 through 2023, widening the gap further.
TRE-ERCOT 5-year projected reserves (ARM and PRM) | NERC
Serious disparities between demand and capacity “could lead to an increased risk of entering emergency operating conditions” such as rotating outages during peak hours, NERC said. However, the organization noted that ERCOT has a large amount of Tier 2 resources — planned capacity that has completed a feasibility, facilities or system impact study, has requested an interconnection service agreement, or is included in an integrated resource plan — under development. These resources are projected to come online after 2023 and should be more than adequate to satisfy demand.
For NPCC-Ontario, the shortfall of about 600 MW is primarily because NPCC’s nuclear retirement and refurbishment program, which introduces the risk that planned upgrades may not be completed on schedule, leaving generating resources offline during periods of high demand. Here, the short-term deficiency is expected to be addressed by new market mechanisms to be introduced by Ontario’s Independent Electricity System Operator in the next few years that will allow additional resources such as off-contract generators and storage facilities to participate in auctions.
NPCC-Ontario 5-year projected reserves (ARM and PRM) | NERC
Wind, Solar, Gas Drive Resource Mix Changes
While long-term generating capacity is sound, the report did note that North American utilities will need to update their internal infrastructure to handle the developing resource mix.
More than 330 GW of installed capacity from wind and solar are planned to be added through 2029, growing their collective share of the grid to 26% from their current level of 15%, while nuclear and coal together decline from 29% to 23%. Natural gas is projected to decline as well, but at 36% in 2029, it will still hold the largest share of generating capacity.
This shift away from conventional synchronous generating resources will introduce new challenges, such as meeting demand shifts with intermittent renewables. NERC recommended that operators install additional system ramping capability to offset the variability of the sun and wind, along with upgrading their ability to forecast supply disruptions. Investment in transmission infrastructure is also needed in order to keep up with the spread of small-scale renewable energy projects, many of them in remote locations.
The report urged utilities to prepare for disruptions to the natural gas transportation system, such as line breaks and well freeze-offs, as well as identify how events in the electrical system itself — for instance, power failures to electric-powered compressors — might impact pipelines.
DERs and Storage Require New Thinking
Distributed energy resources, such as roof-mounted solar panels, will also play a growing role in the grid over the next 10 years, growing from 20 GW currently to more than 45 GW by 2029, accompanied by an expansion in grid-connected electric storage from less than 1 GW to nearly 9 GW (counting projects at all stages of construction). (See DOE’s Walker Sees Big Cuts in Storage Costs.) These projects have the potential to help maintain grid reliability and stability through decentralizing generation and locating it closer to demand. But utilities don’t always have visibility or control over the DERs, and their effects are “not fully represented in [bulk power system] models and operating tools,” NERC said.
“In areas with large or emerging DER penetrations, current operational models and system studies do not properly account for DERs. These models and studies will need to be improved to accurately represent the system’s behavior.”
The LTRA predicts utility-scale storage will grow from 708 MW as of 2017 to more than 8.5 GW by 2024.
“Before this storage is built and integrated into the BPS, the ERO should identify, assess and report on the risks and potential mitigation approaches to accommodate large amounts of energy storage on BPS reliability,” NERC said.
A senior NERC official suggested Wednesday that Standards Committee members could jeopardize the Electric Reliability Organization’s effort to win recertification by balking at inclusion of ERO staff on standard drafting teams.
“One of the things that is important for not just our process but also for our accreditation with ANSI [the American National Standards Institute] is that we have a completely open process; that it be open to all participants,” said Howard Gugel, NERC vice president of engineering and standards. “I’m concerned that some actions that … this committee has taken over the last couple months are beginning to get a little bit close to a line that you may not want to tread closely to, especially in a time when we’re trying to do our ANSI accreditation.”
Gugel made his comments after some committee members attempted to block a regional entity official from the standard authorization request (SAR) drafting team on a cold-weather standard requested by FERC and NERC (Project 2019-06). He responded after Dominion Energy’s Sean Bodkin offered a motion to remove the official — identified as only “Candidate 6” — from the team.
“This is a philosophical issue for me. I don’t think the people who enforce the rule should be making the rules,” said Bodkin, Dominion’s NERC compliance policy manager. “Having an individual from the ERO actually participating in voting and drafting rather than supporting development of the standards isn’t really appropriate.”
Bodkin also said the candidate was ill-suited for the team because he had been an auditor for 11 years “and hadn’t actually been out in the field dealing with cold-weather issues.”
Gugel insisted there was no risk of “undue influence” by the official, noting that any standard would be subject to votes by NERC stakeholders, the Board of Trustees and FERC. “It’s different than other regulations,” he said.
He said including RE officials on SDTs is a response to “consistent feedback from the Standards Efficiency Review advisory group and [Members Representatives Committee] that we need more compliance input into standards development and specifically in the standard drafting team.”
Bodkin said RE officials should participate but should not have a vote on drafting teams. “ERO isn’t part of industry. It’s industry oversight, and the team should be made up of industry members,” he said.
NERC attorney Lauren A. Perotti responded that “there is no requirement [in NERC rules] that standard drafting teams be members of industry,” noting that the team that developed the geomagnetic disturbance standard included a NASA space scientist.
“I also wanted to point out that regional entities do in fact vote on standards,” she added, noting that the REs are one of 10 sectors represented on the Standards Committee. “That is why Guy and Steve are with us today,” she said, referring to committee members Guy Zito, assistant vice president of standards for the Northeast Power Coordinating Council, and Steve Rueckert, director of standards for the Western Electricity Coordinating Council.
Bodkin’s motion to remove the RE official from the candidate slate failed by a voice vote, and the committee ultimately approved the complete slate.
Bodkin and others prevailed, however, in their bid to block reconsideration of the committee’s vote in November to reject a consultant from Utility Services Inc. from a drafting team considering changes to PRC-005-6 (Project 2019-04). (See “Consultants Removed from SDT Nominee List,” NERC Standards Committee Briefs: Nov. 20, 2019.)
Standards Committee Chair Andrew Gallo said members may have voted based on “false information.” He said Bodkin incorrectly said the committee’s nominee selection criteria only allow consultants on SDTs if they bring technical expertise that no other team members have.
“The actual criteria is that the person be a subject matter expert … and clearly we think that this person meets that criterion,” Gallo said.
Gallo also said some smaller entities unable to assign their own staff to SDTs use consultants as a “proxy.”
“We thought we should try to be sensitive to the needs of these small entities,” he said.
Gugel confirmed that NERC had vetted the consultant and found him qualified to serve on the team.
Need to Review Criteria
The meeting ended with an agreement that the Standards Committee Process Subcommittee, which is chaired by Bodkin, will review the criteria for team membership.
“We seem to be revisiting criteria for standard drafting team appointments frequently,” said Jennifer Flandermeyer, director of federal regulatory policy for Evergy, who said the review would provide “opportunities for us to align thinking.”
“There’s a lot of things for us to balance and a lot of things to be considered,” she continued, citing the Standards Development Process Participant Conduct Policy, which prohibits participants from using the process for “commercial purposes … including, but not limited to, advertising or promoting a specific product or service.”
“We’ve had a lot of dialogue about what does ‘commercial benefit’ represent from the vendor/consultant community. How they benefit from that participation I think needs to be vetted out further. There are some really potential politically charged, tough conversations that we’ve got to have to make sure that we as the Standards Committee, working with NERC, get this right.”
Evidence Retention
The committee also endorsed the recommendations by a Standards Efficiency Review sub-team to reduce NERC’s evidence-retention schemes to five from more than 50. An earlier draft of the recommendations had suggested eight schemes. (See “Evidence Retention Report Posted for Comment,” Standards Committee Briefs: Aug. 21, 2019.)
Susan Morris, of the FERC Office of Electric Reliability (OER), asked whether the team had considered evidence-retention requirements of other regulatory bodies, such as the Securities and Exchange Commission.
Michael Puscas of ISO-NE said the team did not look. “The rationale for that was this is something that is directly related to the NERC standards and that looking at evidence retention outside of the NERC standards world didn’t seem to apply. It was apples to oranges in our estimation.”
Morris also said OER preferred NERC require the retention of evidence for the full period between audits.
Puscas said only some of the schemes would require such retention periods. “When you get into the rolling evidence-retention schemes, that would not apply because some audits are greater than a 36-month period,” he said.
“If you’re a generation owner or generator operator, you may have to keep it for six or seven years or longer” under such a requirement, said Gallo, of Austin Energy. “The idea that you would have to keep it back to the last audit is crazy. That’s me, not Austin Energy, talking.”
It was the last meeting for Gallo as chair of the committee. He will be replaced by Amy Casuscelli of Xcel Energy.
approved the committee’s 2020-2022 Strategic Work Plan;
endorsed its 2019 Annual Accomplishments;
authorized the posting of proposed reliability standards CIP-004-7 and CIP-011-3 to clarify the requirements related to managing access to and securing bulk electric system (BES) cyber system information (Project 2019-02);
accepted modifications to the SAR for PER-003-2 (Project 2019-05);
appointed Dean LaForest of ISO-NE as chair of the SDT to revise the requirements for determining and communicating system operating limits (Project 2015-09); and
approved a correction of a typographical error in proposed reliability standard BAL-003-2 on frequency response requirements (Project 2017-01).
FERC voted 2-1 Thursday to extend PJM’s minimum offer price rule (MOPR) to all new state-subsidized resources, saying it was needed to combat price suppression in the RTO’s capacity market (EL16-49, EL18-178).
The long-awaited ruling, supported by Chairman Neil Chatterjee and Commissioner Bernard McNamee, both Republicans, provoked howls of protest from renewables advocates and a stinging 28-page dissent from Commissioner Richard Glick. A Democrat, Glick called the order an attack on decarbonization efforts and warned it would increase PJM capacity costs by at least $2.4 billion annually.
The ruling builds on PJM’s “MOPR-Ex” proposal, filed in response to the commission’s June 2018 order finding the RTO’s capacity market rules unjust and unreasonable because they failed to address growing subsidies. The RTO’s existing MOPR covers only new gas-fired resources. (See FERC Orders PJM Capacity Market Revamp.)
The order expands the MOPR to new or existing resources entitled to state subsidies. Exempted would be existing resources participating in state renewable portfolio standard (RPS) programs; existing demand response, energy efficiency and storage resources; and existing self-supply resources. Federal subsidies would not trigger the MOPR.
Resources not eligible for exemptions can seek unit-specific exemptions by demonstrating their individual costs.
The commission said it chose an expanded MOPR rather than PJM’s resource carve-out (RCO) and extended RCO proposals, which it said would distort the markets.
‘Level Playing Field’
In remarks at the commission’s open meeting Thursday, Chatterjee said the order will ensure the capacity market remains competitive “by establishing a level playing field and being resource-neutral.”
“I recognize, respect and support states’ exclusive authority to make choices about the types of generation resources that serve their communities. And nothing in this order prohibits them from exercising their jurisdiction over generation decisions. But there can be no question that those choices affect the wholesale markets that we oversee,” he said.
The order requires PJM to make a compliance filing in 90 days informing the commission of an updated timetable for its 2019 Base Residual Auction — which was postponed while the case was pending — and of the effect of the ruling on the 2020 auction.
Glick said the expanded MOPR ruling shows the Republicans’ preference for existing generation and desire to slow the transition to renewables.
He recalled that in June, he told the House Energy and Commerce Committee’s Subcommittee on Energy that “we need to do something, even if it’s the wrong thing” because the long delay in issuing a ruling was creating uncertainty. (See FERC Probed on RTO Governance, Market Issues.)
Glick then turned to face his colleagues and said, “Well, Mr. Chairman, Commissioner McNamee, you guys have exceeded my wildest expectations. This is definitely the wrong thing.”
He said the order’s definition of state subsidy is overly broad and would include all future self-supply generation and resources in states that participate in the Regional Greenhouse Gas Initiative, which include Maryland and Delaware in PJM. New Jersey is planning to rejoin RGGI and Pennsylvania is considering joining. (See Pennsylvania Governor Signs RGGI Executive Order.)
“From now on, every single time a municipal utility or electric co-op in the PJM region decides to build a generating facility, that facility will be subject to the MOPR,” Glick said. “This blows up the entire business model, as I understand it, of munis and co-ops.”
The order defined subsidies as including direct or indirect payments by states, subdivisions of states and co-ops formed under state law, related to the procurement of energy or capacity or used to support the construction or operation of capacity resources.
Glick said that although the order makes no attempt to quantify the impact of expanding the MOPR, his staff’s “back of the envelope” estimate is that the expansion will initially boost annual capacity costs by at least $2.4 billion, with larger increases in later years. A $2.4 billion increase would represent 25% over the 2018 BRA, which resulted in total procurement of $9.4 billion for the 2021/22 delivery year. The capacity market represented about 20% of wholesale electricity costs in 2018.
Glick said the estimate doesn’t include the impact of states continuing to sponsor resources that won’t clear in the capacity auction, resulting in more excess capacity than PJM — which expects a 15.5% reserve margin in 2020 — has today.
By requiring administratively determined minimum prices, Glick said, the commission is undermining competition and creating “opportunities … for generators to manipulate the prices.”
“If you are not MOPR’d, or if you’re not MOPR’d a lot compared to some of your other competitors, you’re going to increase your bid up to the level of everyone else’s MOPR,” he said. “But there’s nothing in this order that says we’re going to give the Independent Market Monitor or PJM or anybody else additional authority to ensure that you’re not manipulating the market. We’re just making sure we have a price floor and not a price cap.”
Glick said the commission’s rejection of the resource-specific fixed resource requirement (FRR) alternative means the commission is not trying to accommodate state policy preferences.
“It’s pretty clear that there’s a preference for existing generation versus new generation. … It’s a preference to maintain the status quo and stunt the transition to the clean energy future that states are pursuing and that consumers are pursuing.”
He acknowledged PJM’s 5,000 MW of existing renewables will be exempt from the MOPR.
“What they don’t tell you is there are another 38,000 [MW] of new renewable facilities that haven’t been built yet that won’t be exempt,” he said, referring to the amount of generation needed to meet PJM states’ RPS targets and renewable goals.
Won’t ‘Destroy PJM’
McNamee rejected Glick’s dire predictions. “Despite the rhetoric of the dissent, this is not going to destroy PJM,” he said.
He denied the Republicans were trying to protect uneconomic fossil fuel resources, noting that wind and solar power have become increasingly competitive even without state subsidies.
In a press conference after the meeting, Chatterjee said the idea that the order was intended to prop up coal plants was “completely unfair. … This is a market-based approach, not a partisan or a political one.”
Chatterjee also rebutted Glick’s contention that the order could result in states leaving PJM. “For folks who are concerned that this could potentially lead to unraveling the capacity markets, I will tell you this is an attempt on our part to protect and to save the capacity markets. I can almost assure you that had no action been taken, the capacity markets absolutely would have unraveled.
“[Glick] offers criticism to the approach that we have taken, but he has offered no solution other than the status quo, which PJM itself said was unsustainable,” he continued.
“I would love to have the opportunity to write the orders [rather] than them being presented to us as a fait accompli,” Glick responded in his own news conference. “But … I think the first thing you need to do is see if there’s a problem. … The chairman said the commission never even looked at cost: whether this proposal was too costly or whether the existing methodologies are price-suppressive. There’s nothing in the record … to show that there’s a problem.”
Glick also reiterated his concern about states pulling out of the capacity market. “I’d say the chairman maybe needs to spend more time … with state commissioners, because they are extremely worried about this, and they think this is a commission run amok.”
Reaction
PJM General Counsel Christopher O’Hara, who attended the FERC meeting, declined to comment on the ruling, as did Craig Glazer, the RTO’s vice president of federal government policy. The RTO later issued a statement saying it will discuss the order and its impact with stakeholders beginning at the Jan. 8 Market Implementation Committee meeting.
Stakeholders at Thursday’s Markets and Reliability Committee meeting were guarded in their reactions, noting they had not seen the order, which wasn’t released until late in the afternoon.
That didn’t stop others from weighing in, however.
The Electric Power Supply Association applauded the ruling, saying it “bring us closer to building a durable and sustainable market design that meets the needs of the 21st century.”
EPSA CEO Todd Snitchler said that despite complaints about PJM’s capacity market, “centralized procurement has delivered positive results for consumers and shouldn’t be minimized or abandoned.”
Glen Thomas, president of the PJM Power Providers Group (P3), said, “It is imperative that PJM, FERC and the PJM stakeholders work quickly to re-establish PJM’s capacity auctions so that stability and predictability can return to PJM’s markets.
“Regulatory direction related to the impact of state policy decisions on wholesale markets has been sorely missing, and P3 is optimistic that today’s order will provide that direction,” he said.
Coal lobby ACCCE called the order “a significant step in the right direction” but said it doesn’t fix other market flaws that it said were contributing to the loss of coal-fired generation, calling for ways to value “fuel security … and other resilience attributes.”
The American Wind Energy Association said the decision “threatens states’ rights and hinders their ability to bring more clean energy to their communities.”
The Sierra Club called it “disastrous,” saying it will “essentially exclude new renewable energy resources from the PJM capacity market” and increase fossil fuel emissions. It also said it would add almost $6 billion in annual costs, citing a Grid Strategies study. (See MOPR Impact Study Ruffles Feathers Ahead of FERC Ruling.)
“FERC’s decision doesn’t solve any problems; it creates more of them, and will likely lead to an exodus of states from the PJM capacity market for good,” said Mary Anne Hitt, senior director of the Sierra Club’s Beyond Coal campaign.
The American Council on Renewable Energy (ACORE) called the order “an early Christmas gift to the fossil fuel industry.”
“ACORE is reviewing the implications of this order and our available options, but what is clear today is that FERC overstepped its authority with a decision that will ultimately lead to more pollution and higher electricity rates for consumers,” CEO Gregory Wetstone said.
Exelon, which has won state subsidized zero-emission credits for two nuclear plants in Illinois and is seeking similar supports for four other nuclear plants, said the order “completely undermines state clean and renewable energy programs, and will cost thousands of jobs, increase air pollution and unnecessarily raise electricity bills by $2.4 billion annually. Given this stunning decision, it’s critical that PJM now give states enough time to react and protect families and businesses.”
The New Jersey Board of Public Utilities said the order “shows a callous disregard for the health and safety of the residents of New Jersey and the other impacted PJM states.”
“We anticipate it will make it more difficult for the state to affordably address climate change through the competitive markets. The state of New Jersey will not be deterred as we move forward to implement Gov. [Phil] Murphy’s vision for 100% clean energy by 2050 as we strive to do all we can to combat the climate change crisis.”
“FERC issued pretty much the worst-case order,” the Natural Resources Defense Council’s Tom Rutigliano tweeted. “PJM will now have to plan the power grid pretending state-supported renewable and nuclear resources don’t exist. This is the beginning of the end of capacity markets.”
Energy Secretary Dan Brouillette praised FERC for “strong action to support competition in electricity markets so all of America’s abundant energy sources compete on an even playing field.”
CAISO will have its work cut out for it next year, with more than a dozen major policy initiatives moving forward as well as efforts to head off predicted electricity shortfalls starting in summer 2021.
At Thursday’s Board of Governors meeting, staff provided a rundown of the policies expected to occupy the ISO in the months ahead.
A major focus will be on managing operational risk from a transforming grid, one that must integrate increasing amounts of renewable electricity and battery storage, said Greg Cook, CAISO executive director of market infrastructure policy.
Meeting California’s clean energy goals and expanding the Western Energy Imbalance Market from a real-time-only to a day-ahead market also occupy the 2020 agenda.
“We’re going through an unprecedented amount of change,” Cook told the board.
An initiative on hybrid resources promises to be one of the largest and most complex of the ISO’s 14 policy initiatives in 2020, Cook said. Because of California’s move toward carbon-free energy and the limits of solar energy to meet evening peak demand, developers have proposed 25,000 MW of projects that pair storage with existing or new generation.
Those projects won’t all materialize, Cook said, but “we could easily see 2,000 to 3,000 MW coming online in the next few years,” particularly to meet the impending capacity shortfalls in 2021. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
In his presentation on the ISO’s 2020 outlook, Mark Rothleder, vice president of market quality, focused on the prospect of shortfalls starting in 18 months and the need to get ahead of the problem. Among the challenges are dealing with increased ramping needs and prolonged weather events that diminish solar generation, he said. Currently, rapid increases in demand are met by natural gas generation and electricity imported from other Western states, he noted.
In one slide, Rothleder showed a three-hour ramp on Jan. 1, 2019, that started mid-afternoon and required more than 15,000 MW of additional power, most of it coming from natural gas and imports.
To put the figure in perspective, “that’s like ramping 12 Diablo Canyons over a three-hour period,” Rothleder said, referring to California’s last operating nuclear generating station. The two-unit Diablo Canyon Power Plant, owned by Pacific Gas and Electric, is scheduled to retire starting in 2024, further exacerbating the state’s need for reliable electricity supplies.
The same three-hour ramp is expected to grow to 25,000 MW by 2030, he said. By that time, solar combined with batteries should be contributing more to ramping needs. However, to make that work, improvements in dispatching solar power are required, as is increased visibility and control of commercial and residential solar generation, he said.
Shifting focus, Rothleder expressed concern about multiday weather patterns that limit solar generation. A common California winter weather pattern consists of multiple rainstorms rolling in from the Pacific Ocean, with short breaks between the storms, over the course of a week.
Rothleder cited a period from Jan. 13 to 18 when storms washed over California, reducing solar generation to 20% of expected capacity. Gas power and imports can make up the difference now, but Senate Bill 100, enacted in 2018, requires elimination of fossil fuels from the state’s energy mix by 2045.
As reliance on solar power increases, and dependence on fossil fuels decreases, the state will require storage resources capable of dealing with prolonged cloud cover, he said. Batteries with a four-hour run time, the main type used today, won’t do the job, he said.
A similar situation in July on the Hawaiian island of Kauai resulted in rolling blackouts, he noted.
“If we want to get off gas, we need a solution, including storage,” Rothleder told the board.
FERC on Thursday rejected a request to rehear its October 2017 ruling approving changes to the PJM–NYISO joint operating agreement reflecting a new operational plan for the ABC and JK interfaces between New York and New Jersey (ER17-905).
PJM and NYISO developed the JOA interchange scheduling and market-to-market (M2M) coordination provisions after Public Service Enterprise Group and Consolidated Edison terminated a wheeling arrangement that facilitated the flow of energy between congested areas in southeastern New York and northern New Jersey.
The revisions combined NYISO’s ABC and JK interfaces with the 5018 line and PJM’s western ties, creating an aggregate PJM-NY AC proxy bus. The grid operators said the changes would make use of existing interchange scheduling constructs and support the phase angle regulators on the interfaces. Pricing on the proxy bus was expected to reflect the impacts of imports and exports on the NYISO and PJM transmission systems, weighted by power flow distribution percentages. (See Rejecting PJM ‘Wheel’-related Requests, FERC Sets Inquiry.)
The PJM-NY AC proxy bus is intended to guarantee 400 MW of operational base flow between southeastern New York and northern New Jersey. | PJM
In approving the changes, the commission rejected a complaint by PSEG that the changes infringed on the rights of transmission owners and there was no reliability need for the 400 MW of operational base flow (OBF) provided by the arrangement. FERC instead said it recognized the OBF was necessary to address reliability concerns in northern New Jersey and to avoid additional power from being forced over the western ties and increasing flows over already congested transmission facilities.
In its Thursday decision, FERC denied a rehearing request by PSEG and the New Jersey Board of Public Utilities, saying the complainants were incorrect in their contention that the commission erred in approving JOA revisions that failed to allocate PJM Regional Transmission Expansion Plan costs to New York beneficiaries of the OBF arrangement.
FERC noted that PSEG concedes that the JOA “is an operational protocol and that it does not appear to meet the definition of firm point-to-point transmission service, transmission service or similar terms under the PJM or NYISO Tariffs.” Instead, the commission, said, the OBF is an operational protocol “that expressly does not provide firm transmission service and does not allocate costs to an entity like Con Ed.”
“This materially distinguishes the JOA from the now-terminated [wheeling transmission service agreements] to which Con Ed was a party and under which Con Ed was allocated costs due to its firm transmission service on both the NYISO and PJM systems,” the commission wrote.
FERC also disagreed with PSEG’s contention that the commission was wrong to rely on PJM and NYISO analysis showing the OBF was needed to maintain reliability. PSEG had argued the analysis was flawed because it combined an assumption of congestion during summer peak conditions with a level of interchange — 2,500 MW — that would never occur during the summer.
“PSEG does not address NYISO’s and PJM’s explanation that there were hours between 2014 and 2016 during which the net interchange between PJM and NYISO exceeded 2,500 MW. It was therefore reasonable for the commission to rely on PJM’s studies for demonstrating actual historical flows and a reasonable net interchange value,” FERC said.
The commission also said it found “unpersuasive” PSEG’s assertion that NYISO and PJM should rely on existing NERC transmission loading relief procedures instead of the OBF.
“As the commission explained in the October 2017 order, the NERC procedures are a less economically efficient outcome compared to the RTOs’ proposal to implement economic interchange over the ABC interface and JK interface and also utilize M2M PAR coordination at these interfaces,” FERC said. “PSEG does not disagree that transmission loading relief procedures are out-of-market mechanisms, and that in PJM they are specifically emergency in nature and in NYISO are used when necessary for maintaining reliability in NYISO.”
VALLEY FORGE, Pa. — PJM stakeholders endorsed manual language Thursday that memorializes the Independent Market Monitor’s role in analyzing competitive transmission proposals.
But incumbent transmission owners contend the revisions have no basis in Attachment M of PJM’s Tariff and undermine the yearslong vetting process stakeholders undertook to fine-tune cost-containment language for Manual 14F. (See PJM TOs Wary of Cost Containment Rules.)
Last week, PJM posted manual revisions that added two sentences outlining the Monitor’s ability to access data contained within competitive bids for transmission projects and to perform independent analysis using that information. Incumbent TOs took particular issue with the qualifying clause of the revisions that cite Attachment M of the Tariff as the prevailing source authorizing the Monitor’s involvement in the process.
“Attachment M is silent on what the Market Monitor has access to as it relates to the competitive process,” said Amber Thomas, PPL’s utility regulatory specialist. “Where in the Tariff does it say in Attachment M that the IMM has access to this data? The Attachment M does not say that. To make these big policy changes in Manual 14F to codify something Attachment M does not say does not sit well with PPL.”
The revisions, borne out of a stakeholder motion endorsed by the Markets and Reliability Committee last year, will codify the framework the RTO will use to evaluate competitive transmission projects. (See “PJM Unveils Flat Fee Cost-containment Plan,” PJM PC/TEAC Briefs: Aug. 8, 2019.) Since implementation of FERC Order 1000 in 2014, PJM has reviewed 850 competitive proposals, of which less than 20% included cost-commitment provisions.
Interim CEO Susan Riley clarified Thursday that the revisions represent a compromise about the Monitor’s collaborative role and don’t obligate PJM to share its project analyses, just the data used to support their conclusions.
“The intent is not to have an oversight process over the work that PJM is doing, merely to allow an independent review,” she said. “I don’t think it’s a big give. [The Monitor] does not have approval authority over these projects as to whether they go forward or not. He will just get the data.”
Monitor Joe Bowring said Attachment M, part V “makes clear that the IMM’s access to data is all inclusive.” he added.
“Attachment M is also quite clear and explicit that the IMM has authority to address issues of competition in PJM markets. Competition to build transmission facilities is clearly part of PJM markets,” Bowring added. “These sentences in the manual don’t reflect a compromise; they reflect what our duties are as defined by the Tariff. Under Attachment M, the IMM has the authority to look at competitive issues in the PJM markets.”
The overtures from PJM and the IMM did little to ease incumbent TOs’ concerns. Alex Stern, manager of transmission strategy and policy for Public Service Electric and Gas, questioned PJM’s “procedural gymnastics” in bringing the revisions forward with no opportunity for review or vetting and in defiance of a stakeholder vote overwhelmingly endorsing language that did not include reference to the Monitor.
Stern suggested the MRC instead approve an earlier version of Manual 14F language that excluded the two sentences regarding Attachment M. He said that language was properly vetted by the Planning Committee and through special sessions, as required by the original MRC motion, unlike the revisions PJM and the Monitor crafted and posted online just last week.
He added that expanding the scope of the revisions to include the Monitor’s role was not a part of the discussion until recently — and that it was not driven by stakeholder interest but rather by the Monitor itself. Even so, the recent conversations at the MRC never referenced Attachment M, Stern said.
“The marketplace is not made up by what PJM and the IMM come up with in agreement on their own,” he said. “It’s legally suspect and raises a whole host of questions.”
Bowring called Stern’s accusations “demonstrably false,” pointing to special PC sessions discussing his role in the process and corresponding manual language dating back to August.
“The role of IMM was identified explicitly by a vote of the MRC more than a year ago at the beginning of this process. The specific language about the role of the IMM has been discussed for months in this process,” he said. “In fact, language about the IMM role in the manual was jointly drafted by the IMM and PJM but was removed months ago at the insistence of the TOs.”
Ken Seiler, PJM’s vice president of planning, reiterated the RTO’s interpretation of the Tariff, even if it doesn’t spell out exactly what incumbent TOs say it should.
“As I understand it, there’s language in the Tariff in Attachment M that specifies [the Monitor’s] roles and responsibilities,” he said. “Is it explicit? No. The Tariff is high level. We would try to fulfill those [data] requests based on the spirit of what’s in the Tariff.”
PJM stakeholders overwhelmingly approved the PJM-Monitor language with a sector-weighted vote of 3.92 to 1.08.
FERC on Thursday denied a complaint by the Independent Power Producers of New York seeking to bar NYISO from allowing PJM resources to sell installed capacity into the ISO’s Zone J using unforced capacity deliverability rights facilities (EL18-189).
The ruling ended a year and a half of back-and-forth filings among IPPNY and intervenors. IPPNY contested the rights of several PJM-controlled merchant transmission facilities (MTFs) in New Jersey to export power to Manhattan and Staten Island, alleging that New York’s use of PJM capacity withdrawals threatened system reliability.
Con Edison’s Goethals Substation on Staten Island | Con Edison
NYISO argued that IPPNY incorrectly assumed that transactions across Zone J MTFs would be subject to curtailment on the same basis as non-firm service within PJM. (See NYISO Business Issues Committee Briefs: Sept. 12, 2018.)
The commission concluded that NYISO’s Tariff does not require that MTFs, as external capacity suppliers, have firm transmission withdrawal rights in the external control area to qualify to supply capacity to NYISO.
“Rather, the Services Tariff requires only that the external capacity supplier show to NYISO’s ‘satisfaction’ that its capacity is deliverable to NYISO and ‘will not be recalled or curtailed,’” the commission said.
