Nuclear Energy Institute CEO Maria Korsnick on Thursday expressed support for FirstEnergy Solutions’ request that the Department of Energy declare an emergency in PJM to prevent the shutdown of the company’s three nuclear plants.
Korsnick | NEI
But she called the request — along with state zero-emission credit (ZEC) programs — a “bridging strategy” for the industry: temporary measures to keep the plants afloat until RTOs/ISOs and FERC reform wholesale market price formation.
“Ultimately, the fix that’s needed is that recognition [of nuclear’s emissions-free output] in the marketplace. That recognition has been a bit slow in coming, which is why you’re seeing the level of activity that you’re seeing at the state level,” Korsnick said. “The long-term answer is going to be one that’s market-driven.”
Korsnick was responding to a question submitted through a Facebook Live webcast of NEI’s Annual Briefing for the Financial Community. After giving a speech on the state of nuclear industry, she answered questions, which were also submitted by email, relayed to her by NEI spokeswoman Monica Trauzzi.
In both her speech and answers to questions — some submitted by NEI staff, Korsnick was nonspecific about the issue of price formation. She instead consistently came back to the value of nuclear as a contributor to states’ carbon-reduction goals and a “resilient” source of electricity. She praised ZEC as an example of good state policy and noted that Maryland and Washington are considering carbon taxes.
Monica Trauzzi (left), Nuclear Energy Institute senior director of external communications, relayed questions submitted by Facebook and email to CEO Maria Korsnick during a webcast. | NEI
“The pursuit of clean energy can threaten our nuclear plants if we don’t do it thoughtfully. If the goal is to reduce emissions, then all zero-emission technologies must be part of the solution. We must recognize what we already have in place and build on that. Replacing zero-emitting technology with other zero-emitting technology won’t help.”
She also applauded Congress’ extension of nuclear production tax credits to allow the construction of Georgia Power’s Plant Vogtle Units 3 and 4 to be completed.
But Korsnick warned that generation owners plan to prematurely close 12 reactors and that “if nothing is done to save these plants, the impacts will be devastating.”
“If all of these 12 plants close, we will lose over 120 million MWh [per year] of carbon-free generation,” she said. “That’s equal to half of all the megawatt-hours of wind electricity generated last year in the United States.
“We can stick with a myopic focus on short-term prices. Or we can strive to preserve a resilient, robust electricity system, jobs, tax revenues, clean air and healthy communities.”
To counter the grim warnings, Korsnick highlighted positive developments in the industry. She pointed to NuScale’s small modular reactor design, which she said is “progressing well” through the Nuclear Regulatory Commission, and to the Trump administration’s support for Saudi Arabia’s plans for as many as 16 nuclear reactors.
“The export market is growing, and our success there will strengthen the U.S. supply chain and its support of the existing U.S. fleet,” she said.
WASHINGTON — Panelists at day 2 of FERC’s technical conference on distributed energy resources (AD18-10, RM18-9) debated whether electric distribution companies (EDCs) should serve as gatekeepers or facilitators for resources seeking to participate in energy markets.
EDCs and their allies said they should have control over DERs on their systems, while DER supporters called for strict criteria on utilities’ ability to block DERs.
The first day of the conference focused on how RTOs and state regulators can craft policies that encourage DER to participate in wholesale markets while minimizing the burden on grid operators. (See RTOs, Regulators Set Course for DER Market Participation.)
Conflicts of Interest?
Audrey Lee, vice president of energy services for residential solar and storage provider Sunrun, said EDCs should only be allowed to block DERs through a showing that they would endanger system reliability.
“I think we need some specific examples [of problems] before creating any rules on this,” she said, adding that utilities seeking to install their own resources could have conflicts of interest. She noted that CAISO’s Tariff gives EDCs a deadline for reviewing DER applications and reserves the final decision for the ISO.
Maria Robinson, director of wholesale markets for Advanced Energy Economy, said distribution companies “should be facilitators, not a gatekeeper … preventing the ability of [DER] aggregators to enter.”
She suggested EDCs identify zones that can absorb DERs without reliability problems. If they are to review DER applications, EDCs should be given deadlines requiring them to act quickly, and rejected applicants should have the right to appeal to the RTO/ISO or FERC, she said.
“The vast majority of issues should be worked out with the interconnection agreement” between the resources and transmission operator, she said, adding that reviews should be done only once for each interconnection.
Pete Langbein, manager of demand response operations for PJM, also said interconnection studies should consider DERs once, as opposed to “iteratively.” The studies “may evolve over time” to provide the information needed to evaluate DERs’ impact, he acknowledged.
Interconnection Agreements not Enough
But David K. Owens, retired executive vice president of the Edison Electric Institute, said EDCs need to know DERs’ attributes to understand which ones could cause system disturbances. “Just having a list of aggregators is not sufficient,” he said. “[Distribution] utilities have to know when DERs are deployed. … Interconnection agreements alone will not do it.”
Jeff Taft, chief architect for Pacific Northwest National Laboratory, said DERs become potentially more disruptive as their density increases and that the effects are more significant on distribution lines. “The closer you get the edge of the distribution system, the more you see the volatility caused by DERs,” he said.
Taft said that although distribution lines are generally designed as radials rather than the “mesh” network of transmission, they are “dynamic” because EDCs reconfigure their systems daily. “A resource that may be running through substation A, a few minutes later may be running through substation B.”
State ‘Opt-out’
David Crews, senior vice president of power supply for East Kentucky Power Cooperative, said EDCs must have authority to protect their systems to avoid imbalances on distribution feeders. He disagreed with projections that DERs will be evenly distributed, saying they are more likely to be clustered in wealthier areas where residents can afford solar panels and storage. “It can cause problems; I’m not saying it will.”
Crews also said state regulators should have the ability to “opt out” from allowing retail customers to participate in wholesale markets. EKPC joined PJM in 2013 based on an agreement with Kentucky regulators that state residents would not be able to participate in the RTO’s markets, he noted.
Crews said there is little use of solar and storage among EKPC’s 16 distribution utilities, which use five different makes of meters. “For us to go through the administrative cost of developing a tariff is burdensome to our members” at current penetration levels, he said. “If our members have enough [resources] out there that they want it, we’ll do it.”
Cross Purposes
Mark Esguerra, director of integrated grid planning for Pacific Gas and Electric, warned of conflicts between DERs transacting with RTOs/ISOs and ones providing services to distribution companies. “You could have a situation that none of the parties — the ISO and the distribution utility — get the response they’re looking for.”
Esguerra said the 10-day EDC review deadline suggested by some “could be a challenge without more sophisticated modeling tools.”
Missouri Public Service Commission Chairman Daniel Hall, vice president of the Organization of MISO States, said state regulators should set criteria for DER registration and that EDCs must have authority to approve DERs on their systems. “All distribution systems are unique and the people who know them best are the people on the ground, which is the utility and the utility’s regulator.”
Hall said clear criteria on when EDCs can reject DERs will keep EDCs honest. “That gets us beyond the gatekeeper/facilitator” debate, he said.
There was general agreement that RTOs/ISOs, EDCs and aggregators will need to develop new communication protocols to manage higher levels of DERs. Hall urged FERC to allow regional differences by allowing each RTO and its stakeholders to develop their own rules, subject to commission approval.
Gerald Gray, the Electric Power Research Institute’s (EPRI) program manager for information and communication technology, said that although some utilities do not have supervisory control and data acquisition (SCADA) at all substations, the expansion of advanced metering infrastructure means “there is a lot of granular data providing visibility” on distribution systems.
But Matthew Glasser, a director at Consolidated Edison, said his company and other New York utilities do not have the visibility they need to manage DERs. “Communication with DERs now is low-tech. It’s phone and emails.”
Joseph Ciabattoni, PJM’s manager of markets coordination, said the RTO typically communicates — via phone — with transmission operators, which do the same with their DERs.
Brandon Middaugh, senior program manager for distributed energy for Microsoft, said ISOs and RTOs have “very limited visibility into distribution.”
Visibility also was the subject for the first panelists of the morning — five of eight of whom were from grid operators or utilities. As Portland General Electric Vice President of Transmission and Distribution Larry Bekkedahl put it, system operators “can’t manage what you don’t measure.”
Bekkedahl said the information would allow utilities to avoid overbuilding capacity to the “worst-case scenario,” as is done today, and instead “put in as much capacity as necessary.”
Jens Boemer, the principal technical leader of EPRI’s Transmission Operations and Planning Group, said he learned from experiences in his native Germany that any data that can be collected “relatively easily” should be done “as early as possible” because it becomes more expensive to do it later. He also said it’s important to stop combining DER performance with load because it masks the additional services it provides.
Clyde Loutan, a principal on renewable energy integration for CAISO, said DERs contribute to the unpredictability of load. “We have system operators trying to control a grid with unpredictable demand and variable supply, so we’re always in reactive mode,” he said.
Donnie Bielak, PJM’s manager of reliability engineering, called that “a scary thought,” because the RTO watches CAISO as a barometer of what’s to come on DER issues. “We need an absolutely accurate load forecast to operate the system and operate it economically,” he said.
Ganesh Velummylum, a senior manager of system analysis at NERC, placed the responsibility with transmission owners. He said they should ensure they have the necessary data before they agree to interconnect the resources.
“It starts with the TO,” he said. “Once we have the data, we can do studies. … We have to start with collecting the data through the interconnection process.”
Lack of data can create wider issues, as Boemer illustrated through what he called the “52-Hz problem” in Germany. Many DERs were programmed to trip off at frequency thresholds that are very close to normal frequency, which meant that small and normal frequency variations could cause widespread loss of DERs on the system.
It’s an issue PJM is currently looking at by increasing resources’ “ride-through” requirements. (See “Implementing DER Ride Through,” PJM Operating Committee Briefs: March 6, 2018.)
None of Germany’s transmission operators had modeled that problem in its studies, Boemer said. But the industry was able to identify the risk through published research and knowledge of system operations and operating standards. A catastrophic trip never occurred, but the German government set up a retrofit program to reprogram the trip settings for more than 400,000 distributed photovoltaic resources, he said.
Panelists also said DERs have the potential to benefit systems by addressing reliability issues and perform important grid services. In fact, the variability is useful, Bekkedahl said.
“What used to be very stable generation is moving on us,” he said. “Now that we’ve got variable generation going on, it’s really nice to have variable load.”
“The technology is there” to set up support for power, frequency ride-through and voltage support on the system, Velummylum said.
“They all interact,” he said. “I think it’s important that we look at the collective support DER can provide.”
DERs can also provide non-wires solutions, Bekkedahl said, noting their role in the cancellation of the Bonneville Power Administration’s I-5 Corridor Reinforcement Project. The 80-mile, $1.2 billion, 500-kV line would have helped Oregon utilities manage summer peaks when they were receiving no generation support from south of Portland.
“If Oregon was hot, California was hotter,” Bekkedahl said.
But subsequent DER development in California has changed the situation and eliminated the need for the transmission project. “Can we find non-wires solutions? I think absolutely,” he said.
Unlocking such solutions will require encouraging DERs to participate in wholesale markets so they are committed and required to provide information, Bielak said. “The only way you can determine if you can rely on them is with enough data,” he said.
FERC staff also asked panelists to discuss how to develop long-term projections, and many panelists looked to state policies because they drive development. Marcus Hawkins, the director of member services and advocacy for the Organization of MISO States, noted that a MISO study ended up relying on publicly available data because a voluntary survey of DER owners performed by a consultant received low participation.
“I think it starts with having a good understanding of the status quo” of what’s on the system today, Boemer said. He outlined “hosting capacity” studies that analyze distribution systems to identify potential thermal issues that could limit DER deployment on feeder lines. The analysis creates a heat map “that can indicate how much DER may be able to interconnect to certain areas on the distribution grid,” Boemer said.
The morning’s second panel focused on including DERs in system planning. Velummylum, who remained for the second panel, had a quick response. He held up two reliability guideline studies NERC has published that discuss DERs. “Folks, it’s out there,” he said.
Ning Kang, a staff scientist at Argonne National Laboratory, said the lab is working on improving its models through analysis it performed by studying smart inverter functions and focusing on how applicable standards impact performance.
Brant Werts, Duke Energy’s lead engineer for DER technical standards, said his company only considers the impact of losing DERs in specific areas. During the recent solar eclipse, he said the company lost a significant amount of DER but also knew it was coming and prepared for it. “We don’t believe that we would lose all of our DER at one time,” he said.
Delaware-based trading company ETRACOM agreed to pay $1.9 million to settle allegations that it manipulated CAISO markets in a scheme that netted the company $315,000 in profits.
But the company also issued a statement Tuesday dismissing the allegations by FERC’s Office of Enforcement as “absurd theories.”
An April 10 FERC order approving a consent agreement (IN16-2) with ETRACOM shows the company and principal trader Michael Rosenberg — also a respondent but not listed as paying the fine — neither admitted nor denied the accusations. ETRACOM agreed to pay the fine for submitting virtual supply transactions intended to reduce the day-ahead LMP and increase congestion at the New Melones intertie in 2011.
FERC in 2016 sought a $2.4 million civil penalty from the company and a $100,000 penalty from Rosenberg in addition to disgorging profits. (See FERC Seeks $2.5M Fine in CAISO Market Manipulation.) ETRACOM said Tuesday that FERC had “dropped its long-standing position that an individual trader in this case be assessed a civil penalty.”
The commission said the agreement “is a fair and equitable resolution of the matters concerned and is in the public interest, as it reflects the nature and seriousness of the conduct and recognizes the specific considerations” stated in the agreement, which is not subject to appeal.
The decision specifies disgorgement by ETRACOM of $315,000 plus interest of $84,000 to be paid to CAISO for distribution to market participants impacted by the company’s trading.
In the order, the commission noted it had filed a lawsuit in U.S. District Court for the Eastern District of California to request an order affirming the penalties. In its statement, ETRACOM said it had opposed the lawsuit and been victorious in winning full discovery rights under a de novo standard of review, entering mediation with FERC to produce the settlement.
ETRACOM said it “opposed Enforcement’s brazen misinterpretation and manipulation of the record; absurd theories which rest on reverse engineering of conclusions to produce a ‘fraud by hindsight;’ reliance on circumstantial inferences unhinged from the facts; ignoring of significant exculpatory evidence; and inappropriate ‘sandbagging’ in reply to ETRACOM filings.”
It added that “regardless of the outcome of our case, ETRACOM remains optimistic on the role of FERC in regulating and enforcing energy markets and on long-term reform of the enforcement process.” The company agreed to develop and implement a compliance program based on FERC’s November 2016 “Staff White Paper on Effective Energy Trading Compliance Practices.”
FERC Enforcement alleged that in May 2011, ETRACOM submitted and cleared uneconomic virtual supply transactions intended to artificially lower the day-ahead LMP and create import congestion at New Melones. ETRACOM’s virtual supply offers resulted in a $42,481 loss, while FERC staff estimate the company earned $315,000 in profits on its congestion revenue rights positions. Staff estimated the alleged scheme resulted in the market overpaying all New Melones CRR source holders, including ETRACOM, $1.5 million. The overpayment was funded by New Melones CRR sink holders and revenue inadequacy.
The company has long contended that the losses were because of market flaws and that it had rationally attempted to profit from a record hydro event in May 2011 that caused congestion at the New Melones intertie node. But FERC argued that market flaws were irrelevant to the case. (See FERC: Market Flaws Irrelevant to Case.)
FERC alleged manipulation at the New Melones intertie | Armin van Buuren/Wikimedia Commons
ETRACOM pointed to an investigation that “dragged on for over five years and which saw a kaleidoscope of lead attorneys and their bosses with the diffusion of individual responsibility becoming the norm at Enforcement.” The company’s legal and subject matter team was also extensive, including Robert Fleishman of Morrison & Foerster, Matthew Connolly of Nutter McClennen & Fish and former FERC Chairman William Massey, now of Covington & Burling.
The agreement represents one of a series of high-profile challenges by market participants to FERC Enforcement against alleged market manipulation, including a case against Powhatan Energy Fund that resulted in the agency having to conduct a de novo review. (See FERC Settlement Cuts Barclays Market Manipulation Fine.)
CRRs have been a major subject of debate in CAISO in recent years as the ISO moves to restructure its markets over what it says are hundreds of millions of dollars in payment deficiencies being footed by electricity consumers. CAISO’s Board of Directors approved one package of CRR reforms last month and the ISO has additional phases in development. (See CAISO Developing New CRR Proposal.)
RENSSELAER, N.Y. — NYISO power prices averaged $29.91/MWh in March, down from $33.83 in February, and $34.97 the same month a year ago, Nicole Bouchez, ISO principal economist, told the Business Issues Committee (BIC) on Wednesday.
The ISO’s year-to-date monthly energy prices averaged $60.06/MWh in February, up 59% from a year earlier. March’s average sendout was 413 GWh/day, down from 426 in February and 419 a year earlier.
NYC Power Station | janifest / 123RF Stock Photo
New York natural gas prices for the month averaged $2.85/MMBtu at the Transco Z6 hub, down from $3.14 in February and off 18.2% from a year ago.
Distillate prices were mixed compared to the previous month but gained 19.3% year over year. Jet Kerosene Gulf Coast averaged $13.76/MMBtu, up from $13.72 in February. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.78, down from $13.86 the previous month.
The ISO’s local reliability share was 19 cents/MWh, higher than 14 cents the previous month, while the statewide share of -51 cents/MWh was up from -64 cents. Total uplift costs were higher than in February.
Broader Regional Markets
Reviewing the Broader Regional Markets report, Bouchez highlighted two sections updated since the previous BIC meeting.
Item No. 23 covers a PJM proposal to develop pro forma pseudo-tie agreements that would apply to New York Control Area (NYCA) generators that sell all or a portion of their capacity to PJM. The agreements would provide commitment and dispatch instructions to those generators to meet PJM’s — rather than NYISO’s — needs.
NYISO has expressed concerns that the removal of an in-state generator from the ISO’s commitment and dispatch process limits its ability to manage the generator to ensure NYCA reliability. The removal also introduces compliance issues regarding New York State Reliability Council rules and decreases the efficiency of the ISO’s least-cost solution in its day-ahead and real-time markets.
The ISO is working with PJM to find solutions acceptable to both grid operators.
Item No. 27 concerns how NYISO determines locality exchange factors, which became an issue in 2015 when the ISO’s Market Monitor, Potomac Economics, raised concerns about the treatment of capacity exports from import-constrained localities.
The ISO in February 2017 deployed FERC-approved capacity market changes and asked General Electric to identify possible ways to refine the current methodology using a probabilistic approach. That effort proved unsatisfactory to stakeholders, and the ISO has engaged GE to work further on a formula-based methodology for determining locality exchange factors.
Public Website Redesign
Dave O’Brien, a NYISO project manager, provided an update on the project to redesign the ISO’s public website.
O’Brien said the new design will debut in the fourth quarter with a more intuitive layout and navigation, better mobile device interoperability and an improved search function.
| NYISO
Stakeholders also expressed hopes that the website would better meet their needs. Howard Fromer of PSEG Power New York noted an example of spending minutes locating a document, being asked to sign in for access, then being redirected back to the homepage and to restart his search from scratch.
The New York task force charged with determining how to price carbon emissions into NYISO’s markets on Monday tackled the complex issue of avoiding the pitfall of “carbon leakage.”
The term refers to when carbon market participants evade caps and prices by shifting electricity production to bordering areas outside the market.
The Integrating Public Policy Task Force (IPPTF) on April 9 heard two presentations on seams and leakage, part of issue “Track 2” in its five-track effort. The task force is jointly run by NYISO and the state’s Department of Public Service.
“It’s not an option at all to put a sizeable carbon charge on New York production and not do anything at the borders; that’s just not an option,” Brattle Group’s Sam Newell said during a presentation on applying carbon charge border adjustments to the ISO’s external transactions. “The reason you can’t is it creates a very unlevel playing field and would shift production to out of state in a very big way.”
Status Quo or Green Power
Newell presented two carbon pricing options to avoid market distortions. The “status quo” model would not consider carbon content in energy trades, while the second “green power” option would evaluate marginal emissions rates from out-of-state imports.
The status quo option could shift generation serving up to half New York’s load to out of state and also increase emissions regionally while only reducing them in state, Newell said.
| Brattle Group
“We’re talking about something that could be on the order of $50/ton, could be $20/MWh,” Newell said. “Imagine putting a $20 penalty on internal generation and not external. Again, you’ve really unleveled the playing field.”
The second option would factor into the prices for imported electricity the estimated difference in the carbon content of emissions based on the region (PJM versus Quebec, for example), “and it does think about carbon content in terms of exports and what are you displacing on the other side,” Newell said.
In response to questions from several stakeholders, Newell said the carbon charge on imports would not be unit-specific, noting that neighboring regions do not identify their exports by generating unit.
He contrasted New York’s situation with the Energy Imbalance Market (EIM) administered by CAISO.
“That’s an integrated market, and if you just said these units in California have to buy allowances and the others don’t, you’d have the same leakage problem,” Newell said. “They had to build into the [EIM] some sort of border treatment. … Unlike New York when it’s thinking about its neighbors, the EIM actually is dispatching the region on a unit-specific basis.”
Other stakeholders asked about charging imports from neighboring regions based on their average — rather than marginal — emissions rates.
“In economics, for price signals, marginal is what matters, not average,” Newell said. “This is a whole topic in ratemaking. If you charge based on average, you’ll have unintended consequences and inefficiencies.”
Marginal emissions rates differ from region to region, he said, but the types of marginal units may be more uniform across neighbors than assumed. For example, “energy limited resources” in Hydro-Quebec and Ontario (often limited to shorter run times because of local environmental restrictions) are more likely to produce and export at the margins of the market.
“If you get it right, you incentivize cost-effective abatement everywhere,” Newell said, noting that approach is consistent with New York’s objective to reduce global emissions.
Specifying Emissions and Costs
Julia Frayer and Gabriel Roumy of London Economics International (LEI) presented a study commissioned by Hydro-Quebec Energy Services (Hydro-Quebec’s U.S. subsidiary) on potential methodologies to address leakage of emissions to and from neighboring areas.
Like the Brattle report, LEI stated that improper implementation of a carbon charge mechanism could derail decarbonization objectives and distort underlying market signals.
| Brattle Group
LEI believes that a more granular approach to assessing carbon emissions rates for imports, based on resource- or area-specific emission rates, is superior in terms of economic efficiency, market impacts and reduction incentives.
“It’s all a matter of consistency, and it’s important when you look on the regional scale [that] you really need to look at unit-specific emission rates and what are these resources contributing to the overall Northeast markets,” Roumy said. “And the contribution is the lack of emissions that they are doing.”
Howard Fromer of PSEG Power New York said, “We want to know what the cost and price impacts are going to be to end-use consumers. If they’re a lot, then we’re probably not going to be very supportive. If they’re modest … then the next question we’re going to ask is: What are we getting for that extra cost? Are we getting significant carbon reductions, or are we just reshuffling the deck and making it look good?”
Warren Myers, DPS chief of regulatory economics, summed up the two political approaches represented in both the Brattle and LEI studies.
“One is keeping, as best as you can, interactions with other control areas on the same playing field that it’s currently on,” Myers said. “The other one is — do you want to take New York’s policy, or what the value of carbon is, and apply it beyond New York’s borders to address its consumption.”
In wrapping up the meeting, IPPTF co-chair Nicole Bouchez, NYISO principal economist, noted that the group will move a discussion on carbon charge implementation from May 7 to its next meeting on April 16 in response to stakeholder concerns.
MISO Chairman Michael Curran last week denied an RTO Insider story quoting him as saying that the RTO should “burn down” the 3,000-MW limit on flows between its North and South regions if necessary to prevent load shedding.
The comment — and one attributed by Megawatt Daily to MISO Independent Market Monitor David Patton — led to a series of tense communications between MISO and SPP and a request for FERC to intervene over how MISO managed a maximum generation event in MISO South on Jan. 17.
RTO Insider’s April 2 story reported on an exchange between Curran and Patton at MISO’s Board Week in New Orleans over the RTO’s actions to replace idled generation in its South region during the record cold on Jan. 17.
At a Markets Committee meeting March 27, Patton said if the RTO had not made emergency power purchases for South, regional supply would have dipped below load for several hours, referring to the possibility of the “lights going out in MISO South.”
RTO Insider reported that Curran “rebuked Patton’s use of such dramatic language, while also responding that MISO should ‘burn down’ SPP’s transmission on the contract path before it allows MISO South to shed load.” (See MISO Markets Committee Talks Winter, Spring — and Beyond.)
MISO agreed to the 3,000-MW Regional Dispatch Transfer (RDT) limit in a 2016 settlement agreement with SPP, the Tennessee Valley Authority (TVA), and Southern Co.
Denial
Kari Bennett, MISO executive director of stakeholder affairs and communications, asked RTO Insider for a retraction of the quote on April 6, saying Curran denies using the words “burn down.” She also denied Curran said that MISO would violate the SPP agreement to ensure sufficient power to meet South’s load, as RTO Insider reported.
Rather, she said, Curran was indicating the RTO would invoke a clause in the agreement allowing it to exceed the 3,000-MW North-South limit. The settlement, which was approved by FERC in May 2017, set a 2,500-MW South-North limit. (See FERC Greenlights MISO Cost Allocation for SPP Settlement.)
MISO exceeded the 3,000-MW limit on North-South transfers for more than an hour on Jan. 17 before emergency purchases from the South allowed it to reduce transmission to below the limit. | MISO
MISO’s load hit 106.1 GW on Jan. 17, its peak for the winter, with South setting a record winter peak of 32.1 GW. The RTO called a maximum generation event in South after outages there hit 17 GW.
The RTO compensated for South’s shortfall with generation from Midwest, exceeding the 3,000-MW limit for about an hour (see chart). MISO dropped below the limit after making emergency purchases of 1,100 MW — mostly from Southern Co. — south of the North-South constraint. It was the first such emergency purchase from Southern, Patton said.
Some stakeholders who attended the meeting said privately they considered Curran’s comments surprising and inflammatory, though they could not recall use of the phrase “burn down.”
RTO Insider requested to review a recording of the meeting to address the dispute over Curran’s words. However, MISO said although the meeting was webcast, it was not recorded.
‘Run Over’
Patton said Monday that neither he nor his staff who listened to the meeting recalled Curran using the term “burn down.” Based on notes made by his staff, Patton indicated Curran said “ … if we have to run over RDT, we will to prevent turning lights off in the South.” Patton said he interpreted Curran’s “run over the RDT” statement as meaning to schedule more transfers than 3,000 MW, which is allowed on a temporary basis.
Patton said the agreement allows MISO to exceed the limit for 30 minutes after a contingency and to request a longer waiver from the other parties to the agreement.
Patton said he agreed with Curran that avoiding load shedding in South must take precedence over exceeding the RDT, adding that “the idea that you would shed load [rather than exceed the limit is] just such an absurd outcome.”
SPP Letter
SPP declined to comment. But in an April 4 letter, SPP CEO Nick Brown complained about Curran’s comments, as reported by RTO Insider, and Patton’s comments as reported by Megawatt Daily.
The letter, which was obtained by RTO Insider, quoted Patton as saying, “SPP has been saying [MISO] created reliability problems on their [SPP] system. We don’t believe this is true.”
“I take these comments very seriously as they are totally false as SPP did face a significant reliability event and took actions necessary to preserve the integrity of our system and the bulk electric system as a whole,” wrote Brown, who said he was pleased that MISO President Clair Moeller had assured SPP that the RTO didn’t agree with Patton’s comments.
But Brown said he found Curran’s quote, as reported by RTO Insider, “very troubling.”
“I view this incident as a grave matter related to protecting the integrity and reliability of the bulk electric system,” Brown continued. “Rather than debating this incident in the press, I believe it best for the parties involved to elevate our discussions to FERC and NERC so [that] everyone can better understand what occurred on that day and why. Therefore, I have asked Paul Suskie, SPP general counsel and executive vice president for regulatory affairs, to contact FERC to request their scheduling of a meeting in Washington, D.C., to take place expeditiously.”
SPP spokesman Derek Wingfield said in a statement late Tuesday: “We disagree with the assessment of MISO’s Market Monitor, as reported in RTO Insider and Megawatt Daily, regarding the severity of MISO’s actions as they relate to the reliability of SPP’s system during the Jan. 17 event. To ensure the continued reliability of all our systems, we have asked for a meeting with principals from MISO and the joint parties to clarify the parameters by which we coordinate operations, as defined in our settlement agreement.”
MISO’s Bennett said Tuesday, “MISO system operators were in constant contact with real-time operators from all of our neighboring systems regarding system conditions on Jan. 17, including the transfer limits per the settlement agreement as well as our request for emergency purchases per MISO’s emergency protocols.
“The settlement agreement between MISO, the Southern Companies, SPP, and TVA establishes a Regional Transfer Directional Transfer Limit (RDTL) of 3,000 MW (north to south) and allows for temporary changes (increases or decreases) to the RDTL to avoid a system emergency, so long as the change does not create a system emergency for SPP, the Southern Companies or TVA.”
Grid operators and regulators on Tuesday hashed out the complexities of integrating distributed energy resources (DER) during the first session of a two-day FERC technical conference on boosting the role of energy storage in wholesale electricity markets.
FERC ordered the conference in February after issuing Order 841, which requires each RTO/ISO to develop a “participation model” allowing storage resources to provide any energy, capacity and ancillary services of which they are capable and be eligible to set clearing prices as both buyers and sellers. (See FERC Rules to Boost Storage Role in Markets.)
A morning panel brought together RTO/ISO representatives who discussed the operational intricacies of integrating DER into wholesale markets, focusing on approaches to aggregating the market participation of the small-scale resources to make them manageable for grid operators.
“DER aggregation requires a level of cooperation you don’t see to this point, not even in demand response, because of the impact DER can have on the system,” said John Goodin, CAISO manager of infrastructure and regulatory policy. “It’s important if you’re going to establish DER aggregation, that you impose both size and boundary constraints; that’s something that the ISO has done.”
University of Delaware Vehicle to Grid (V2G) cars parked at the Science, Technology, and Advanced Research (STAR) Campus. 15 V2G vehicles act as a mini power plant, drawing energy during off-peak times and delivering it back to the grid when it’s most needed. In partnership with NRG Energy Inc., the University has created the world’s first revenue-generating vehicle-to-grid project using technology developed by Professor Willett Kempton of UD’s College of Earth, Ocean, and Environment. | University of Delaware
CAISO set a 20-MW size limit on aggregations participating in its market, although individual resources can range from 0.5 to 1 MW. Any resource exceeding 20 MW becomes a participating generator subject to a different set of requirements, Goodin noted.
Nodal vs. Zonal
Pointing to the dual nature of DER as both transmission and distribution resources, Jeff Bladen, MISO executive director for market services, said it’s important to distinguish between the challenges of taking load off the system and putting supply onto the system.
“As we think about aggregation groups, it needs to be more than how do we do security-constrained aggregations for the transmission system, but how are we going to manage potential restraints at the distribution level,” Bladen said.
“Let’s remember we are a nodal system,” cautioned Joe Bowring, president of Monitoring Analytics, PJM’s Independent Market Monitor. He encouraged industry stakeholders to think about developing a sustainable model for significant expansion of DER.
“It’s critical to think about how [aggregation] works in a nodal system,” Bowring said. “It’s not possible to predict congestion; it’s not possible to predefine constraints that exist or don’t exist in a zone.” Any configuration larger than a node is “way too big for aggregation,” he said.
| NYISO
Michael DeSocio, NYISO senior manager for market design, said while New York does allow zonal aggregations, none is participating in the market today.
“So as much as we hear it’s important, we don’t see much of that actually occurring in New York,” DeSocio said. “As we thought about making sure the values were there for DER and making sure the price signals incentivize DER to locate in the right places, it occurred to us that nodal made the most sense.”
| FLS Solar
Henry Yoshimura, ISO-NE director of demand resource strategy, noted resources coming into the New England system are primarily solar and energy efficiency and the RTO’s settlement-only construct allows any resource up to 5 MW to participate in the wholesale market. “Because there’s no size limitation, there’s no real need for aggregation,” he said.
Goodin said CAISO sees significant benefits to aggregation.
“We don’t have a single node,” Goodin said. “You can have an aggregation across the [sub-load aggregation point], across multiple nodes, and why is it advantageous? One, it allows for the providers to actually go out and solicit and pull together, aggregate, meaningful-sized customers, meaningful from the ISO’s perspective … the key thing is that aggregations allow for the right sized resource.”
Andrew Levitt, PJM senior market strategist, said, “We think there are benefits to aggregation in ensuring open market access to resources of all sizes, including resources smaller than our 100-kW minimum highest threshold.”
National Solutions?
Commissioner Cheryl LaFleur asked why there should be different processes among the different regions.
“Shouldn’t we try to solve the coordination process once and then sort of spread that, as opposed to developing six ways to do it?” LaFleur asked. “Maybe we should standardize more. Can we skip a step and figure it out?”
“I don’t know that the rules are the issue,” DeSocio said. “I think really what the main difference that we’ve observed in New York is what is the posture of each of the different distribution utilities, what is their ability to actually see into their own grids.”
Goodin added, “If we are going to enable DER to really flourish, you have to address some of the things that are outside the walls of the ISO and the authority of an ISO through FERC.”
He enumerated three priorities: access to capacity markets and capacity payments; reducing interconnection barriers and cost; and creating more clarity around allowing DER to tap multiple value streams and simultaneously provide grid services to the both ISO and distribution domains.
“In my opinion, those are the much more weighty issues — resource questions, interconnection, multiuse — than sort of the day-to-day functionality of managing these DER and settling these DER resources in the wholesale market,” he said.
Yoshimura said the primary issue is a lack of “consensus in the industry as to how distributed energy resources ought to be operated, if at all. And the struggle that any ISO would have is, whereas we model transmission constraints, I don’t think any of us model distribution constraints.”
MISO’s Bladen said, “We like to think of ourselves as a service provider, to the states in many respects, that our job is to take the fleet that regulators are designing and implementing through their integrated resource plans and to optimize that, to get the most value you possibly can out of that fleet across a broad region.”
“We don’t know yet what best practices are going to look like, don’t know what the dominant DER technologies will be, and that what you have in front of you are a number of companies interested in identifying best practices,” Bladen said.
Bowring said: “We should have the same rules. The fact there’s all this complexity doesn’t mean we shouldn’t have the same set of rules. They will evolve, but we to need start in the same place where everyone is facing the same issues.”
Head Banging
During the afternoon panel, regulators from California, Ohio, Pennsylvania and D.C., as well as others, carried on the discussion of DER aggregation, including issues around reliability and markets. The conversation illustrated the newness of the technology and the many challenges of coordinating state regulations, markets, and the requirements for utilities.
FERC commissioners noted the difficulties for states developing separate policies and approaches that will need to be integrated into wholesale and retail markets. The panel covered how federal and state regulators — and others — can better coordinate on the issue.
“This is a case where all the technology might be ahead of the regulators,” LaFleur said.
FERC Chairman Kevin McIntrye put it simply, telling the state regulators, “We want to avoid messing anything up.” He asked about the negative impacts of individual and aggregated DER on states and said the discussion should help build a robust evidentiary record.
California Public Utilities Commission (CPUC) President Michael Picker recommended a “DER roadmap” similar to one developed by his agency, which looks at grid architecture, DER planning, and developing appropriate rates and tariffs. California is a leading state in DER integration, including efforts by the CPUC and CAISO.
UC San Diego Microgrid | UC San Diego
“There are a lot of challenges here,” Picker said, adding that the CPUC’s effort has uncovered issues around safety for workers and emergency responders who have to deal with DER equipment. The effort has also identified operational issues around DER integration, including congestion in the distribution system, and is mapping the distribution system similar to how RTOs map transmission systems.
“We have a grid system that was never designed for a lot of two-way flow,” Picker said. The CPUC effort is “acknowledging that these are trends that are going to happen,” he said. He noted that other states will be able to learn from and “leapfrog” California’s efforts.
Invenergy’s 31.5 MW Grand Ridge Energy Storage project | Invenergy
“I would recommend you let us bang our heads against those brick walls,” he told FERC, pointing to CAISO’s Energy Storage and Distributed Energy Resources program, now in its third phase. (See CAISO Storage, DER Plans Progressing.)
Different States, Different Rules
The regulators noted their states have different policies with different cost impacts that will need to be integrated into markets. They also hold differing views on allowing DER to participate in wholesale and retail markets.
Public Utilities Commission of Ohio Chairman Asim Haque discussed an issue raised by several regulators: that DER should not be compensated twice — in retail and wholesale markets — for providing the same services.
But Haque added that DER owners and operators should be left to decide how they choose to be compensated for behind-the-meter DER, such as staying on a net metering tariff or participating in the wholesale market through aggregation if that is more profitable.
“Their goal is to maximize the value of that resource,” he said. “That is acceptable to us as well.”
Ben D’Antonio, counsel for the New England States Committee on Electricity, said distribution utilities in New England are going to drive many of the outcomes as DER resources are added, but “the operational impacts are not known at this time.”
“We are actively working on it, but some of ours states have some pretty ambitious goals and others do not,” D’Antonio said. He said it’s unclear how quickly DER will grow in New England, but he thinks the integration effort will need to be consistent with the integration and interconnection requirements of the distribution utilities, who have a “critical gatekeeping role.” Utility decisions will be driven by the tariffs, requirements, and incentives that federal and state regulators put in place, he said.
”We support the idea of DER being able to take part in both wholesale and retail markets,” said Tammy Mitchell, deputy director of the New York State Department of Public Service. But she thinks much work remains to develop the rules and protocols, including the double-payment issue, which could increase ratepayer costs.
D.C. Public Service Commissioner Willie Phillips said he thinks the city can benefit from DER, but “it’s really a resource-by-resource analysis.” The city has seen no negative impact from its load control programs, for example, he said.
“Here in the district, people are dying to get at this,” but the compensation issue must be solved first, Phillips said.
PJM’s Independent Market Monitor scored a victory Monday after the RTO announced it filed with FERC to consider both its two-stage capacity repricing proposal and the Monitor’s plan to expand the minimum offer price rule (MOPR) (ER18-1314).
As part of the filing, PJM requested that the commission choose one proposal — even if that requires more information for full approval — and to identify what aspects of it need to be revised, rather than send the issue to “trial-type proceedings.” The RTO instead suggested establishing settlement judge procedures, if necessary.
“PJM anticipates that if the commission makes the outstanding issues more manageable by accepting one of the two tariff alternatives, a good faith consensual effort could be the most productive means of resolving those outstanding issues,” the RTO said.
The RTO requested an effective date of Jan. 4, 2019, to be in place for the 2019 Base Residual Auction for delivery year 2022/2023. To that end, the RTO asked for an order be issued prior to July so that any necessary follow-up could be completed in time for January.
“Based on PJM’s showings in this filing, the commission has substantial evidence on which it could fully accept either of the two alternatives in an order issued by June 29, 2018,” the RTO said.
The filing is what former FERC Chairman Norman Bay called a “jump ball” on Twitter, as it asks the commission to settle a disagreement that divided the grid operator, its Monitor and stakeholders throughout 2017. PJM campaigned from the beginning for its plan to accept bids from subsidized resources in its capacity auctions, but then isolate them during a second stage and reset the price without them. The Monitor’s MOPR-Ex proposal would extend the MOPR to all units indefinitely, but in alternative versions included carve-outs for states’ renewable portfolios and public power self-supply. (See PJM Board Punts Capacity Market Proposals to FERC.)
Stakeholders, who saw the Monitor proposal as having the least impact on the current construct, backed it all the way to the Markets and Reliability Committee, but all its different versions stalled after PJM CEO Andy Ott announced he would be recommending the RTO’s plan to the Board of Managers no matter the outcome of the committee vote. Still, subsequent pressure from stakeholders forced staff to offer both proposals to the board, which in the end punted the decision to FERC.
The Monitor had vowed to file his proposal if it wasn’t recommended to the board, even though it would have meant meeting the tougher standards under Section 206 of the Federal Power Act of demonstrating not only that the proposed changes are just and reasonable, but that the existing rules are unjust and unreasonable. That’s a higher hurdle than proposals that receive board approval, which only have to show the proposal is just and reasonable under the standards of Section 205.
“The question raised by PJM’s filing in this case is not whether states have the right to [encourage development of preferred generation resources within their borders] but instead how the wholesale market should respond to such actions so that the goal of ensuring just and reasonable rates is not frustrated by an individual state’s actions,” PJM said in the filing.
However, some stakeholders remained unsatisfied with either option. Jennifer Chen, an attorney with the Natural Resources Defense Council’s Sustainable FERC Project, said PJM’s proposal “would funnel more money from consumers to power plants for no additional benefit” while the Monitor’s proposal “would discriminate against offshore wind and force consumers’ utilities to over-procure generation.”
“Either of PJM’s two competing pricing proposals will drive up the utility bills of 65 million electricity customers in 13 Mid-Atlantic and Midwestern states,” she wrote. “The proposals also ignore the real issue — that PJM’s capacity market commitment to supply electricity in the future forces utilities to purchase a specific amount today, but without the opportunity to choose the kind of energy customers want to power their homes and businesses tomorrow.”
CAISO last week issued its proposal to offer reliability coordinator (RC) services in the West, including a plan to charge rates that appear to dramatically undercut rival Peak Reliability.
But when asked about the figures Monday, Peak told RTO Insider that “a true and accurate side-by-side comparison is not possible.”
The ISO on Friday provided more details on the planned Tariff changes and rates it will charge after its planned departure from current RC service provider Peak Reliability in September 2019. It plans to become certified as its own RC provider. (See CAISO to Depart Peak Reliability, Become RC.)
CAISO will develop an RC funding requirement — which includes the operating budget and reserve, as well as an annual revenue adjustment — to determine what it will charge per megawatt-hour. The ISO estimates its annual funding requirement will range from $5 million for only the ISO area to $12 million for all potential balancing areas in the region. Dividing those amounts by projected volumes yields a rate of 2 to 3 cents/MWh. CAISO said the monthly service charge will be derived by multiplying the RC rate by the megawatt-hour volumes submitted, citing an example of $51,000 monthly and $614,000 annually based on a monthly customer with a volume of about 2 million MWh.
By comparison, Peak said it charged customers nearly $44.6 million for its RC function in both 2016 and 2017 and will maintain the same level of funding for 2018.
“Yes, we can do it that much cheaper,” CAISO spokesman Steven Greenlee confirmed.
But Peak spokeswoman Rachel Sherrard said a comparison is not possible, “as the depth and breadth of the services Peak RC provides for its current rate of around 5 cents per retail customer per MWh is significantly more than we believe will be offered by CAISO.” She said that price includes the core RC function and several enhanced tools and technologies such as the WECC Interchange Tool, the Enhanced Curtailment Calculator and the Peak Synchrophasor Project.
“These additional value-adding tools, requested by our funding parties over the past nine years, have been consistently modified and refined to meet the reliability challenges posed by the changing landscape,” Sherrard said. “Our understanding is that CAISO is going to offer the basic NERC-compliant RC services, which doesn’t directly correlate to what we provide.
“In addition to switching costs associated with a transfer from Peak to any other RC, there is risk in transitioning from an entity with a strong operational track record, exceptional talent with an immense knowledge of the Western Interconnection and skills to an entity that is not yet an established RC,” Sherrard said.
Next Steps
CAISO has scheduled an April 12 meeting at its headquarters to discuss its RC rate design straw proposal, which it will develop into a final plan submitted to the ISO Board of Governors and then FERC.
CAISO’s planned milestones for development of RC services | CAISO
“All transmission operators within the CAISO balancing authority (BA) area will become reliability coordinator service customers of the CAISO at that time,” the ISO said. The RC services will also be offered to balancing authority areas outside of CAISO area and to transmission operators in those BAAs.
The RC is the highest level of reliability authority under the NERC model and has the widest view of the bulk electric system, with authority to prevent or mitigate reliability problems in both next-day analysis and in real-time.
The ISO said it also will be working with transmission operators in CAISO and others that have provided a letter of intent for RC services and signed non-disclosure agreements to develop operating procedures, technical requirements and other facets of the RC proposal.
CAISO’s model is based on seven ratemaking principles used to determine its other rates, including grid management charges and Energy Imbalance Market (EIM) administrative fees: cost causation, use of services, transparency, predictability, ability to forecast, flexibility and simplicity.
The ISO will require RC customers to initially commit to 18 months of services and will not penalize for withdrawals provided that six months of notice is given. The ISO estimates it will need 28 full-time employees that will work solely on the RC function.
CAISO in January initially announced its intent to depart Peak and offer its own RC services.
The ISO cited as the reasons for the move Peak’s decision to partner with PJM to provide market services and Mountain West Transmission Group’s likely departure from Peak after it joins SPP. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)
CAISO is also developing a plan to extend its day-ahead market across the EIM, setting up competition for developing the market that could possibly develop into a new Western RTO. (See Multiple Entities, Markets Now Beckon in West.)
VALLEY FORGE, Pa. — PJM’s Eric Hsia told attendees at last week’s Market Implementation Committee meeting that the RTO plans to salvage the non-compensation portions of its proposal to revise its regulation market that FERC rejected last month. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.)
PJM had filed for approval of revisions that included four interdependent components. The commission denied the proposal outright because it would have paid units a formula rate that didn’t specifically compensate for the actual amount of regulation work they provided, but its order didn’t address the other three components. Hsia said PJM plans to ask FERC to reconsider those components separately as the RTO determines how to address the commission’s issues with its compensation plan. He confirmed that PJM wouldn’t change the language describing the three components in its reconsideration request.
Direct Energy’s Marji Philips asked if PJM plans to consolidate its regulation signals into a single signal as FERC pointed out in its order is the process that all other grid operators follow. Hsia said the RTO is considering that option.
VOM Proposal
Stakeholders endorsed proposed revisions for how operations and maintenance costs are recovered that would allow “major” maintenance to be included in variable operations and maintenance (VOM) calculations. Both PJM’s and a default proposal received overwhelming support. The RTO’s proposal received 169 votes in favor, or 75%, and 57 opposed. The default package received 178 votes in favor, or 81%, and 43 votes opposed.
A follow-up vote found that 71% of voters preferred one of the packages over the status quo. The revisions will impact how units calculate their cost-based offers and have implications for other market and operational issues, such as frequency response. (See PJM SHs Debate Frequency Response Rules.)
The Independent Market Monitor’s Catherine Tyler provided context for the Monitor’s proposal, which would have replaced “incremental” with “short-run marginal” in the Operating Agreement and assumed that all maintenance and labor costs are included in a unit’s capacity offer. It fell well short of the votes needed, receiving 11% favorability, or 24 votes out of 224.
“The cost-based offer should be set at a competitive level, and that is short-run marginal cost,” Tyler said.
She said that while every unit provides a cost-based offer, which is only applied if the unit fails its market power test, it isn’t used frequently because price-based offers are often lower than cost-based ones, which she said is a particular concern when cost-based offers are overstated. A unit has incentive to pad cost-based offers because it provides more room to adjust price-based offers when the unit fails its market power test.
PJM’s Gary Helm said the quadrennial analysis of how unit-type net cost of new entry (CONE) is determined will evaluate both including and excluding major maintenance from the VOM calculation. PJM hired the Brattle Group to do the review, which will be presented later this month and is slated for filing for approval at FERC on Aug. 1.
The last review in 2014 became mired in infighting at FERC over details in the engineering portion of how costs could be determined.
FES Bankruptcy
PJM staff did not offer any specific comment on FirstEnergy Solutions’ bankruptcy announcement and plans to shutter its three nuclear facilities, but they agreed to field stakeholder questions on the issue.
Stu Bresler, senior vice president of markets and operations, confirmed that the plants’ “must-offer requirement is retained” absent an exemption. Because the period for seeking such an exemption has closed, it would require a FERC waiver granting it.
CFO Suzanne Daugherty said, “PJM is still ready for June 1,” referring to the target date for Ohio Valley Electric Corp.’s integration into the RTO. But she said staff would accommodate a delay if requested. She said that all PJM members are in compliance with credit requirements but clarified that any without investment-grade ratings wouldn’t be eligible for unsecured credit.
It remains unclear how the deactivations will impact prices.
“I can’t imagine the analysis resulting in any other [locational deliverability area] model than what’s already been modeled,” Bresler said. But Monitor Joe Bowring said he can’t tell if an additional LDA would clear the Base Residual Auction above the RTO-wide capacity price unless it’s modeled in the auction.
SOM Revisions
Bowring announced that several calculations have been revised in the IMM’s annual State of the Market Report that paint a less rosy picture for nuclear facilities than originally thought. (See IMM Report Says PJM Prices Sufficient.)
The Monitor revised its calculations on forward-looking profitability for nuclear plants, reducing the numbers by tens of millions of dollars. It now predicts a revenue shortfall of $11 million this year for the Perry generating station, which is one of the facilities FES plans to close, instead of the previous $500,000 profit. Perry also overtook Three Mile Island, which Exelon has threatened to close, for the grimmest long-term outlook, expected to hemorrhage $79.5 million in 2020 alone.
Exelon’s Dresden facility in Illinois overtook the company’s Limerick facility near Philadelphia as the plant with the best outlook, with about $58.8 million in profit expected for 2020.
Nodal Mapping
Stakeholders are working on several initiatives involving financial transmission rights.
Proposed revisions to address the nodal remapping issue are expected at the May MIC meeting to target a Sept. 1 effective date that coincides with the 2018 LMP bus modeling likely for mid-September, PJM’s Brian Chmielewski said.
The revisions are in response to concerns highlighted by Direct Energy about replacing nodes where FTRs begin or end and are terminated based on changes in load, generation or system topology. When that happens, an “electrically equivalent” node must be identified to replace the terminated one, but stakeholders who have experienced that issue have been unsatisfied. The proposal would create a “dummy” pricing node at the same location as the terminated one where only “sell” bids would be allowed. After all connected FTRs are sold or expire, the node would be terminated. The same process would work for incremental auction revenue rights.
Long-Term FTR
PJM also plans to bring a proposal to the May MIC meeting for addressing long-term FTRs, with a target effective date by June 1 in time for the 2020/23 auction, Chmielewski said. PJM’s plan would eliminate the current “year all” offering, leaving only the one-year options that are one, two or three years in the future.
PJM said interest was low in the “year all” option that included all three years and eliminating it would improve FTR software performance. The proposal would also limit ARR modeling. Instead of including all planning period ARRs as fixed injections and withdrawals, it would only include those that cleared based on the annual model with all transmission outages removed. Chmielewski said the plan better represents the residual capability on the system and preserves capability for ARR holders in the subsequent annual allocation.
