Search
`
November 5, 2024

Posted on

RF Urges Consultations on Generator Winter Preparations

Regional entities and utilities have a lot to gain by taking a collaborative rather than an adversarial approach to compliance with NERC’s new extreme winter weather standards, participants in a ReliabilityFirst webinar said on Monday.

The webinar was part of the RE’s regular “Technical Talk with RF” series. RF’s Brian Thiry said in his introduction that RF staff had jokingly dubbed the event “Christmas in July” because of its focus on “all things cold weather,” particularly the new standards that began to take effect earlier this year.

Topics included NERC’s first Level 3 alert, issued earlier this year after the ERO’s Board of Trustees approved it at its meeting in May. (See “ERO to Issue First Level 3 Alert May 15,” NERC Board of Trustees/MRC Briefs: May 10-11, 2023.) The alert requires registered entities to provide NERC an extensive set of information by Oct. 6, including their total net winter capacity and how they have prepared their systems for cold weather. It also identified eight essential actions for entities to take to prepare for cold weather, although implementing them is voluntary.

Darrell Moore, NERC’s director of situation awareness, emphasized the importance of abiding by the Level 3 alert in his presentation, stressing that “it has become increasingly important to understand how entities have taken steps to prepare for extreme weather conditions” in light of the storms that caused widespread power outages in the last two winters.

RF representatives also talked up their organization’s cold weather winterization (CWW) program, which is intended to help registered entities with their winter preparations by having RF consultants visit generating plants to check their weatherization measures personally.

Staff emphasized that despite the CWW program’s reliance on site visits and audits, it is not part of the RE’s compliance monitoring and enforcement program; nor is it intended to formally certify a generating facility’s preparedness for winter operations. Rather, the aim of the program is to inform and educate generator owners and operators in what RF’s Senior Reliability Consultant Joseph Jagodnik called “a more relaxed, constructive and forward-looking atmosphere.”

This year’s program will focus on plants commissioned in 2023, along with existing generation that has experienced a cold weather-related outage. The RE will send out a survey in late summer or early fall to identify site candidates, with visits to follow from late October through mid-December. Visits are expected to last a day with two to four RF staff members on site.

Nicholas Poluch, senior manager of NERC relations at Talen Energy, joined the webinar to describe a visit last year by CWW staff to the utility’s Lower Mount Bethel plant in Pennsylvania. He credited the RF team with helping Talen reorganize its winterization operations and consolidate its compliance program.

“I think overall, [there was] a lot of benefit, not only to this plant, but we took the ideas that RF gave us for this facility and rolled them out across the fleet, and I think it really upped our game,” Poluch said. “I think we as an organization [also] became more accountable [on] weatherization and more disciplined in implementing it. We were doing stuff [before], it just wasn’t to the same level as, say, our protective systems program.”

RF staff encouraged utilities to take advantage of the CWW program, describing it as a chance to put RF’s knowledge and experience to work for their benefit. Thiry said it fits into the RE’s goal of being a partner to the industry, rather than solely an enforcement mechanism.

“Our winterization program is … something we take a lot of pride in, and it’s something that we do want to continue to grow and expand upon,” Thiry said. “At the end of the day, what matters to ReliabilityFirst is that you are reliable, resilient and secure. So if there’s any consulting work that we can do with you before or after an audit engagement, we’d love to engage with you on that.”

Posted on

PJM Completes CIFP Presentation; Stakeholders Present Alternatives

PJM completed presenting its proposal to overhaul the capacity market, and stakeholders continued refining their own proposals, during the Critical Issue Fast Path (CIFP) process meeting last week.

Wrapping up a presentation that spanned multiple full-day meetings, PJM focused on its proposed changes to market power mitigation and fixed resource requirement (FRR) entities.

The proposed market power changes would create an explicit calculation of unit-specific Capacity Performance (CP) risk based on its parameters and reliability risk modeling. PJM’s Skyler Marzewski said the goal is to ensure that market sellers can fully represent the risks and costs of taking on a capacity obligation.

PJM’s package also would shift to using a forward-looking energy and ancillary services offset for the market seller offer cap (MSOC) and minimum offer price rule (MOPR). And the exemption that intermittent and storage resources currently have from the must-offer rule would be ended under the proposal.

Ken Foladare of the Tangibl Group said removing the must-offer exemption seems designed to impair intermittent resources by forcing their participation in the capacity market while they’re subject to penalties if there is an emergency while they’re unable to operate.

“I don’t see how this isn’t going to be a very large negative for renewable and intermittent resources in general,” he said.

PJM Senior Director of Economics Walter Graf said CP penalties currently don’t reflect the actual expectations of how a resource would perform, while the overall proposal aims to capture that in each unit’s accreditation and corresponding obligation. While the proposal would introduce more risk intermittent resources, he said the volatility would average out with the likelihood of them overperforming during other periods.

Calpine’s David “Scarp” Scarpignato said thermal resources are held to their capacity obligations even during weather conditions under which they weren’t designed to operate and questioned why intermittents should be treated differently if they were subject to the must-offer requirement.

“I could use the same logic and argue [combustion turbines] should be excused from penalties because it’s not designed to run in those conditions,” he said.

He added that intermittent resources are being built without participating in the capacity market, signaling that there aren’t market power concerns with those units and they might not need to be held to the requirement.

The PJM proposal also would rewrite the rules for planned capacity resources to enable net cost of new entry (CONE) values to be calculated on a unit- or default technology-specific basis.

The FRR changes would aim to align the regulated utility structure with the proposed capacity market rules by creating seasonal obligations for FRR plans, with corresponding accreditation and qualifications for those generation resources.

The option for FRR entities to elect a physical penalty would be removed, leaving them subject to a deficiency charge in the event their generators underperform during a performance assessment interval (PAI).

The charge rate would be set to the insufficiency penalty — which itself is based on the CONE — which raised questions among some stakeholders who said pegging the FRR penalty to CONE rather than the Base Residual Auction (BRA) clearing price — which is the basis for the penalty rate for capacity resources — strays from the goal of aligning the two structures.

PJM Shifts Timeline Within Fuel Security Presentation

PJM has revised its proposal to evaluate natural gas resources’ fuel security and incorporate those variances into their capacity accreditations to begin with the creation of a dual-fuel class of resources in the next Base Residual Auction (BRA). Director of Planning Operations Chris Pilong said including fuel assurance in accreditation would allow for the quantification and recognition of the value that enhanced availability brings and incentivize new investments that improve overall reliability.

Resources seeking dual-fuel status would be required to either demonstrate that capability or have plans in place to install the necessary equipment by the start of the delivery year. PJM expects that resources will attest to their status for the initial rollout, likely followed by inspections down the road.

PJM also plans to have generators submit their fuel transportation status prior to each BRA starting with the 2025/26 auction, with the aim of incorporating that into accreditation in the future as well once sufficient data have been collected.

Dual-fuel resources also must have access to enough secondary fuel storage to operate for 48 hours to qualify for the higher rating.

Old Dominion Electric Cooperative’s Mike Cocco said many resources have shared fuel storage and gave the example of two CTs that share a tank with enough fuel for one to operate for two days. The generation owner would be able to offer only one of those resources as having dual-fuel capability, which could limit dispatchers’ options during an emergency. He suggested that PJM instead offer more granular levels of storage, such as 12-, 24- and 48-hour categories.

“That’s precisely the wrong signal that PJM wants to support because you’re going to lose the ability to operate that CT on oil when you otherwise had it,” he said. “I think you’re really going to hit some unintended consequences if you just stick with the one value.”

Economist James Wilson, a consultant to state consumer advocates, said that while he is in favor of PJM’s proposal to create a seasonal capacity market, it has some shortcomings, and it may be beneficial for the RTO to work with stakeholders to create an alternative model that works toward a goal of being more transparent and understandable. Having a variable resource requirement (VRR) curve that’s known in advance of auctions would be one component he’d like to include.

Graf said PJM is willing to work with Wilson and others in drafting additional options in the proposal matrix, and it acknowledges that the complexity in its proposal is a downside.

Calpine Proposes Additional FRR Changes

Presenting for Calpine, Scarp said PJM’s proposal doesn’t go far enough to bring the FRR rules into alignment with the capacity market, with the largest issue being that there is no sloping demand curve for FRR entities, which only have to meet the reliability requirement identified by PJM.

This has led to the capacity that FRR entities are required to procure being an average of 6.7% lower than the rest of the pool over the past five years, he said, amounting to a difference of about 9,408 MW each year. Clearing long — above the reserve margin — has produced benefits for capacity market participants, which the FRR side has been able to “lean” on. He argued that FRR participants are receiving reliability benefits from the rest of the pool for which they aren’t paying.

Scarp proposed setting a FRR procurement requirement reflecting the amount of capacity that has cleared above the IRM over the past five years, with a rolling average.

Economist Roy Shanker agreed, saying that allowing certain parties to benefit from carrying a lower reserve margin is wrong.

“Fundamentally what is going on right now is discriminatory. … What they do is create a basis for rate-based resources to arbitrage against the rest of the pool,” he said.

Wilson said over-procurement is an undesirable aspect of the Reliability Pricing Model that has to be tolerated to get the benefits of a sloped demand curve.

Calpine also proposes that PJM expand the portion of its proposal that bars capacity sellers from substituting replacement capacity for resources that underperform during an emergency during the billing process to also be applicable to FRR entities.

Daymark and EKPC Propose Base and Emergency Capacity

A joint package from Daymark Energy Advisors and East Kentucky Power Cooperative also aims to expand on PJM’s proposal by further splitting capacity into two products differentiated by the type of system conditions the resource would be best suited to address.

Base capacity (BC) would center on meeting the needs of regular system conditions and wouldn’t include higher winterization than those already mandated by NERC — a requirement PJM’s proposal would include for all resources participating in its envisioned winter capacity market.

Emergency capacity (EC) would be designed to address extreme weather and would be required to have firm fuel or a technical equivalent, be available for dispatch within two hours’ notice and demonstrate the ability to pay any non-performance penalties if not able to operate. It also would be procured on a multiyear basis, while BC would follow the status quo annual auction schedule.

Daymark CEO Marc Montalvo said EC could be provided by resources that already are online, such as a steam unit, or by peaker plants. When energy is needed quickly during an emergency, he said having access to units that already are online and can ramp up or can start quickly is a valuable attribute.

All resources would be subject to the must-offer requirement, similar to PJM’s proposal, and their offers would be risk-adjusted under the joint proposal. Montalvo said BC resources would require little to no adjustment, while EC offers are exposed to higher penalty risk.

Independent Market Monitor Adds Detail to Hourly Approach

Independent Market Monitor Joe Bowring presented an alternative proposal during the June 28 CIFP meeting that features an annual capacity auction and clearing price paired with hourly matching of load and capacity throughout the delivery year.

Rather than using accreditation to define the amount of capacity a resource may offer and is obligated to deliver, the Monitor’s proposal would reduce its installed capacity by its modified equivalent availability factor, which is based on historical hourly availability and its location.

The market clearing engine also would take the hourly historical performance of resources into account, including ambient derates, planned maintenance and forced outages. Bowring said this would ensure that intermittent resources would not be dispatched at times when they would not be able to perform, such as solar at night.

Under the model, a capacity resource would be paid only for the times in which it is available to provide energy according to its capacity obligation. Contrasted against the accreditation and seasonal model in PJM’s proposal, Bowring said this ensures resources are paid only when they can meet their obligation and avoids the arbitrary nature of defining seasons.

Bowring’s concerns about a seasonal market also include the ability to represent an annual avoidable-cost rate and energy and ancillary service revenue offsets.

“PJM’s seasonal approach will create issues that it is not possible to solve analytically; for example, how to allocate avoidable costs across seasons and for annual offers,” Bowring said in an email. ”There is no magic to the definitions of seasons. Seasons are arbitrary. It’s great that PJM recognizes that there are risks in the winter. The logical end point is to recognize hourly differences in required and available supply. Hourly captures the winter issues and the summer issues and issues that may arise in any hour, as well as locational issues, without creating the unnecessary complexity of seasonal cost allocations.

“In addition, PJM’s approach to market power and the market seller offer cap is inconsistent with FERC’s order on the MSOC and inconsistent with the role of the capacity market. There is no reason that energy market net revenues should not offset all avoidable costs, without exception. Recognizing that the cost of mitigating risk is another cost that can be offset is essential, given that the role of the capacity market is to provide the missing money (the portion of avoidable costs not covered by the energy market) and not to add money that was never missing. Including the cost of mitigating risk as part of avoidable costs fully recognizes risk,” he said.

Speaking to RTO Insider after the June meeting, Bowring said the underperformance aspect of the Monitor’s proposal likely will be revised so that if a resource is called and does not start, it would not be paid its hourly capacity revenues back to the last time it did successfully start. If a generator fails one of its biweekly tests, it also would be required to return payments going back to the last time it successfully started.

Posted on

FERC Briefs: Orders Addressing Arguments Raised on Rehearing

FERC issued explanations for denying rehearing requests in several cases in the past week. Requests to rehear FERC orders are automatically deemed denied “by operation of law” unless the commission acts within 30 days. The orders below elaborate on why the commission declined to reconsider its prior orders.

MISO
NextEra Request for Rehearing of Canceled MISO Competitive Project

ER23-865-001

NextEra Energy asked the commission in April to stay its order terminating the only competitive regional transmission project in MISO. (See NextEra Asks for Rehearing of Canceled Competitive Project.) The commission’s March order allowed MISO to abandon the $115 million, 500-kV Hartburg-Sabine Junction project in East Texas. The RTO approved the project in 2017 but determined last year that the project’s benefits had evaporated due to recent generation additions in the region.

The commission reiterated its conclusion that MISO followed its tariff in the matter and said it disagreed with NextEra that no other parties would be harmed by granting the requested stay. “As the commission explained in the termination order, ‘the mounting delay in commencing construction’ of Hartburg-Sabine resulted in economic uncertainty for MISO stakeholders due to the modeling of a project that will not be built, which will eventually create reliability concerns,” FERC said. “Even if the threat of reliability issues was not concern enough, MISO asserts that requiring it to reinstate Hartburg-Sabine into its generator interconnection models would cause queue delays for a number of generator interconnection customers. In light of these findings, we find that granting the stay would harm third parties.”

Eliminating Schedule 2 Reactive Power Charges

ER23-523-001

Vistra, Invenergy and others sought rehearing on the commission’s January order approving MISO transmission owners’ request to eliminate Schedule 2 charges for reactive power within the standard power factor range. Opponents said FERC failed to consider the effects of eliminating reactive power compensation on the MISO markets, particularly regarding independent power producers’ reliance on such compensation.

In approving the MISO TOs’ proposal, FERC cited its policy “that the provision of reactive power within the standard power factor range is … an obligation of the interconnecting generator and good utility practice.” In its July 12 order, the commission rejected the challenges “as collateral attacks on that longstanding policy.”

Commissioner James Danly, who dissented from the January order, repeated his opposition, saying the MISO TOs failed to overcome “the record’s substantial unrebutted evidence of the rate impacts this proposal would have on generators not affiliated with the MISO TOs.”

PJM
PJM Interconnection Queue Procedures

ER22-2110-002

Petitioners challenged the commission’s Nov. 29, 2022, order accepting PJM’s proposal to transition from a serial first-come, first-served queue process to a first-ready, first-served clustered cycle approach. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

Lee County Generating Station complained that the commission failed to address arguments that the rule changes were unfair to existing generators making long-term firm transmission service requests. In its July 6 order, FERC acknowledged that the transition from a serial approach to a cluster approach “may present delays for existing customers that had previously been avoidable due to PJM’s pre-existing practice of removing from the interconnection process and advancing firm transmission service requests that did not contribute to the need for network upgrades.” But it said the generator “has not demonstrated that PJM’s proposal is unduly discriminatory.”

Hecate Energy, a Chicago-based renewable power developer and operator, challenged FERC’s acceptance of a $5 million cap on network upgrades for projects seeking to interconnect through PJM’s expedited process, saying it was arbitrary. “Despite Hecate’s disagreement with PJM’s observation that new service requests associated with network upgrades at or below the $5 million threshold are ‘fairly straightforward’ and that ‘the majority of new service requests do not proceed when they are assigned network upgrade costs … in excess of $5 million,’ Hecate provides no contrary evidence,” FERC said.

PJM Order 2222 Compliance

FERC defended its March approval of PJM’s Order 2222 compliance filing after rejecting rehearing requests by the Ohio and Pennsylvania public utility commissions, Advanced Energy United (AEU) and the Solar Energy Industries Association (SEIA) (ER22-962-003).

FERC responded to the Ohio and Pennsylvania commissions’ jurisdictional concerns by saying its order does not give PJM authority over disputes with state laws but found the RTO’s proposal “unreasonably restricts” a DER aggregator’s use of PJM’s dispute resolution procedures.

AEU and SEIA argued that the proposal’s provisions to prevent double counting of energy and capacity would prevent net energy metering programs from participating in PJM’s markets, pointing to narrower language from NYISO and ISO-NE. FERC said it was granting RTOs flexibility in their double-counting restrictions and that PJM’s proposal is sufficiently narrowly designed.

Commissioner Mark Christie concurred with the July 11 order, reiterating his dissent in Order 2222-A over jurisdictional concerns. “This fundamental issue raised by these two state commissions has, of course, been among the daunting practical challenges of implementing Order No. 2222 from the beginning because that order egregiously invaded the long-time authorities of the states and other relevant electric retail regulatory authorities (RERRAs) to regulate retail rates,” Christie wrote. “We are also beginning to see some of the other consequences, including the costs that consumers will now be forced to bear towards implementing Order No. 2222.”

PUERTO RICO

APPA Request for Rehearing or Clarification re: Alternative Transmission Inc.

EL23-14-001

The American Public Power Association sought rehearing or clarification of FERC’s March 16 order granting Alternative Transmission Inc.’s petition for a declaratory order regarding the jurisdictional consequences of a proposal to build one or more HVDC undersea transmission lines connecting Puerto Rico to the mainland. The commission said the interconnection proposed by ATI would result in Puerto Rico’s utilities becoming subject to the commission’s jurisdiction unless an exemption were granted under Section 201(b)(2) of the Federal Power Act. (See FERC Weighs in on Jurisdictional Questions over Puerto Rico Project.)

APPA responded that because Puerto Rico is considered a state under the FPA, “a utility owned by the government of Puerto Rico would not be a public utility as defined in the FPA.” Thus, the Puerto Rico Electric Power Authority would be considered a “municipality,” which is excluded from the definition of “public utility,” APPA said.

In its July 10 order, FERC said that whether a particular utility in Puerto Rico would be considered a public utility as a result of ATI’s proposed interconnection would be dependent on the company’s specific characteristics. “For example, if an electric or transmitting utility in Puerto Rico qualifies as a municipality under section 3(7) of the FPA, then that utility would not become subject to the commission’s jurisdiction as a public utility under section 201(e) of the FPA as a result of the interconnection proposed by ATI, although such utility would be subject to the commission’s jurisdiction under other provisions of the FPA, including, but not limited to, Section 215 of the FPA,” which created the Electric Reliability Organization to develop mandatory reliability standards.

SPP

City of Nixa, Mo., Annual Transmission Revenue Requirement

ER18-99-007

Numerous parties challenged FERC’s February order approving SPP’s proposal to include the annual transmission revenue requirement (ATRR) for the city of Nixa, Mo., (owned by GridLiance High Plains) in transmission pricing Zone 10. The commission said it was consistent with cost causation principles. (See “Order on GridLiance ATRR,” FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)

The order was challenged by several municipal utilities in Arkansas and Missouri and a group of SPP transmission owners, including Evergy and American Electric Power’s Public Service Company of Oklahoma and Southwestern Electric Power Co., which said the commission should have focused on the non-Nixa transmission customers in evaluating the impacts of including the Nixa assets in Zone 10.

In its July 5 order, the commission said the challengers’ arguments “focusing on the extent to which they derive benefits specifically from the Nixa assets are inconsistent with SPP’s zonal rate design.”

Empire District Electric Co. Generation Replacement Under SPP Rules

ER23-928-001

Empire District Electric challenged the commission’s March 29 order denying its request for a tariff waiver to allow Empire to replace its Riverton Unit 10, a 16.3-MW simple cycle facility damaged in a fire Feb. 8, 2021. The commission ruled that Empire’s waiver request was retroactive and prohibited by the filed rate doctrine because the company failed to file the waiver request within the one-year deadline in SPP’s replacement rule.

In its July 12 order, FERC rejected Empire’s contention that its request was “prospective” because SPP could modify its generator replacement process in the future. “Whether SPP will revise [its tariff] in the future is not only speculative, but … also irrelevant, given that Empire is requesting that the commission provide retroactive relief to excuse Empire’s failure to submit a generating facility replacement request by the Feb. 8, 2022, tariff deadline,” the commission said.

Posted on

NY State Reliability Council Executive Committee Briefs: July 14, 2023

NYISO Q2 STAR Report

NYISO CEO Rich Dewey presented findings from the ISO’s second-quarter short term assessment of reliability (STAR), which found a shortfall as large as 446 MW in New York City (Zone J) generating capacity by the summer of 2025.

The Q2 STAR report indicates that New York City’s reliability margin deficit will be driven by growing electrification, an expanding economy, the expected retirement of fossil fuel plants due to the state Department of Environmental Conservation’s (DEC) peaker rule and delays to the Champlain Hudson Express project from Hydro Quebec. (See  NYC Marginal Reliability Deficient by 2025, Finds NYISO Q2 STAR Report.)

Zone J’s deficiency could require certain emitting power plants to stay online longer than permitted by the DEC’s peaker rule and risk New York being unable to achieve many of its climate and energy goals.

However, Dewey noted that keeping peakers online was a last resort and he promised NYISO would return shortly with more information about the issue.

Demand Curve Reset

NYISO Senior Vice President Rana Mukerji told the EC that the ISO is finalizing the contract terms with the vendor selected to conduct the demand curve reset, though did not provide the company’s name because negotiations are ongoing.

NYISO conducts the reset every four years to review and update the parameters used to determine the ICAP demand curves, which helps the ISO procure the right volume of megawatts to meet demand.

Mukerji said NYISO would announce the chosen vendor in the next couple weeks.

EWE Impacts

Aaron Markham, NYISO vice president of operations, told the EC that recent extreme weather events had not significantly impacted ISO operations.

EC Chair Chris Wentlent asked whether the ongoing wildfires in Quebec or the recent flooding across the Northeast had resulted in emergency operations or loss of transmission as in ISO-NE.

“NYISO has actually been exporting to Quebec to help support them during these ongoing wildfires, and the recent flooding did cause some small level of distribution level outages but no impacts on the transmission or power assets in New York,” Markham said.

“We did also export some megawatts to New England to support them on the fifth of July due to forest fires,” he added. (See Canadian Wildfires Trigger ISO-NE Capacity Deficiency.)

PRR-152

Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, updated the EC about potential reliability rule changes, including creating a new rule for wind and solar resource lull conditions.

The rule, PRR-152, quantifies transmission facility performance metrics related to wind or solar lull periods and helps define the exact contingency plans that should be implemented during these periods of lower intermittent production.

Pointing to recent extreme weather events, Clayton said “we’ve seen how these lulls can cover all of the Northeast,” making it “important to understand these lull dynamics due to the increasing penetration of wind and solar.”

The RRS will continue developing PRR-152 with NYISO and gladly accept any submitted initial comments.

Posted on

PJM OC Briefs: July 13, 2023

Manual Revisions for Interconnection Process Overhaul Sent to MRC

PJM’s Heather Reiter updated the Operating Committee on the status of several manual revisions codifying the interconnection process overhaul during its July 13 meeting. Each manual was reviewed and endorsed by the relevant standing committee last week and will be moving on to the Markets and Reliability Committee on July 26. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

The manuals were endorsed by the Planning Committee, Market Implementation Committee and OC by acclamation throughout the week with minimal discussion. During first reads in June, stakeholders praised the cooperative nature of the manual revision process.

The manuals lay out a cluster approach to studying the grid impacts of generation interconnection requests that will begin the analysis on a first-ready, first-serve basis. In addition to grouping studies together, the new paradigm aims to speed more projects through the interconnection process by having project developers pay deposits increasing in scale as their studies progress.

The transitional phase leading into the new way of studying projects also began last week with the aim of clearing the backlog of projects that accumulated during the previous serial methodology. PJM states that it plans to complete analysis on over 260 GW of projects studied over the next three years, many of which will be renewable generation.

On July 10, PJM opened a 60-day window for developers participating in the transitional queue to post readiness requirements, and it plans to begin processing projects with minimal system impacts through a “fast-lane” process in September.

System Operations Report

Wildfire smoke causing lower-than-expected temperatures and elevated load on the Juneteenth holiday contributed to forecast load error in June peaking at 2.82% and having an hourly error rate of 1.79%, according to the July systems operations report PJM’s Stephanie Schwarz presented to the OC. (See RTOs Report Diminished Solar Output, Loads as Wildfire Smoke Passes.)

The 6 p.m. day ahead forecast for June 19 had the highest deviation with an error of nearly 9% for the peak hour. Following high forecast error on Christmas Eve, which has been credited as being a contributor to the impact of the December 2022 winter storm, New Year’s Eve and Easter, stakeholders have been discussing the role of holidays in forecasting.

Following the spread of wildfire smoke across the northeast on June 5 and 6, PJM said a drop in expected temperatures led to decreased load, which offset diminished solar output. Forecast error for June 6 was just over 6%.

Posted on

PJM PC/TEAC Briefs: July 11, 2023

Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards

The Planning Committee endorsed a quick fix proposal to rewrite portions of Manual 14B to align with NERC’s TPL–001-5.1 standard. The quick fix process allows for a problem statement, issue charge and proposed solution to be brought simultaneously and voted on in the same meeting.

The changes pertain to how PJM determines the maintenance outages in its planning horizon, its spare equipment strategy, planning and mitigation of single points of failure and administrative updates. The proposed language includes a target effective date of July 26.

PJM’s Stan Sliwa said NERC removed the requirement that outages of more than six months be included in the planning horizon and left it up to RTOs to select another rationale. PJM proposed to look at upgrades involving outages on the 230-kV grid or higher that would last more than five days.

Increased requirements around the spare equipment standards pertain to PJM’s process for reaching out to asset owners to see if they have a strategy for maintaining an inventory of equipment that could take a year or more to replace. If those owners don’t, PJM engages in a study to see what the impact would be if that equipment were to go offline.

The new NERC standards for single points of failure expanded the pieces that are considered part of a component protection system and expanded how RTOs study relays.

The quick fix solution was endorsed by the PC and is scheduled to be voted on by the Markets and Reliability Committee on July 26.

PJM Presents Recommended Load Model for 2023 RSS

PJM’s Patricio Rocha Garrido gave a first read of the recommended load model candidate to be used in the RTO’s 2023 Reserve Requirement Study (RRS). The analysis will be used to set the installed reserve margin (IRM) and forecast pool requirement (FPR) for the 2027/28 delivery year and inform any modifications to the previous three years’ values.

The selected load model includes data from 2003-09, which includes load levels that are higher than the model used in last year’s study.

Under all the shortlisted load models, the peak day for PJM would fall in July and overlap with the “world” — which it defines as MISO, NYISO, TVA and VACAR. PJM recommends the world peak be moved to a different week in July to avoid the overlap, which PJM historically has found unlikely and would lead to a decreased capacity benefit of ties (CBOT) value.

The PRISM software also treats each day as a week, which would present in the analysis as both PJM and its neighbors peaking for a week, exacerbating the effect.

Because of volatility in recent years’ CBOT values, PJM also is recommending taking the average of the past seven years.

Alongside the PRISM analysis, PJM will be using software developed for the hourly loss-of-load modeling used for ELCC studies in this year’s study. PJM says the ELCC software has the potential to produce better results and will generate two sets of data, which will be presented to stakeholders when the study is complete for endorsement of one set of outcomes. (See “Reliability Requirement Study to Use New Software,” PJM PC/TEAC Briefs: May. 9, 2023.)

The load model selection process is required only for the PRISM software, which requires normal distributions of data, whereas the PJM forecast data is empirical. The ELCC process models the monthly peak load uncertainty by deriving load scenarios and frequency weight for each delivery year between 2012 and 2021.

Transmission Expansion Advisory Committee

2023 RTEP Window 1 to Open this Month; 2022 RTEP Window 3 Selections in September

PJM’s Sami Abdulsalam discussed the timeline for the opening of the first window of the 2023 Regional Transmission Expansion Plan (RTEP), which is slated for July 24 and will remain open for 60 days. The window will focus on reliability constraints outside of the region currently being addressed by the 2022 RTEP window 3, which was opened in March 2023 to address concerns that available transmission may not be adequate for the pace of load growth in the Data Center Alley in Northern Virginia.

All individual proposals submitted in window 3, which closed on May 31, have been screened and baseline scenarios are under evaluation.

Supplemental Needs and Project Proposals

    • Commonwealth Edison said the majority of its oil circuit breakers in operation on its 345-kV Goodings Grove substation in Illinois are 44 to 57 years old and in deteriorating condition. One breaker failure has the potential to take out seven 345-kV lines and two autotransformers.
    • Dominion proposed three new 230-kV substations in Loudoun County, Va., to serve growing load in the region, which includes the data center alley near Dulles International Airport. The Lunar substation would be connected to the existing Sycolin Creek facility by two 230-kV lines at a $28 million total cost and an August 2026 in-service date. The proposed Starlight substation would be cut into the envisioned lines between Sycolin Creek and Lunar at a $28 million cost and a June 2028 in-service date. The third substation, Apollo, would be connected to Lunar by two 230-kV lines at a $28 million price tag with a January 2027 in-service date.
    • Public Service Enterprise Group (PSEG) said its Pierson Ave. substation in Perth Amboy and Meadow Road in Edison have run out of capacity, each serving more than 14,000 customers, while the Keasbey substation, serving more than 5,600 customers in the Perth Amboy region, is in poor condition and not in compliance with New Jersey construction codes.
Posted on

PJM MIC Briefs: July 12, 2023

Vote on Rules for Generation with Co-located Load Deferred

VALLEY FORGE, Pa. — The Market Implementation Committee delayed voting on five competing proposals to allow generators that provide a portion of their output to co-located load to retain their capacity interconnection rights (CIRs).

The discussion — brought by Brookfield Renewable and Exelon, later Constellation — explores the creation of rules allowing a generator to serve highly interruptible load not directly interconnected to the grid, while still being available to switch to serving PJM when called on to meet its capacity obligations. (See “Discussion Continues on Capacity Offers for Generators with Co-located Load,” PJM MIC Briefs: June 7, 2023.)

MIC Chair Foluso Afelumo made the determination to delay the vote based on stakeholder input and not hearing any objections during Wednesday’s meeting.

Constellation Vice President of Market Development Bill Berg said the company has been engaged in outreach with other package sponsors in the hopes that a compromise can be reached between the five options. The Advanced Energy Management Alliance (AEMA), PJM, the Independent Market Monitor and Exelon are the other four sponsors.

“I do think that it is in our stakeholders’ best interest to give it one more month to try to reach some compromise, because my fear is that this will end up at FERC,” Berg said. “…we are reaching out to anyone and everyone we can talk to, particularly some of the package sponsors to see if there’s a path forward on at least some of these issues.”

Exelon’s Sharon Midgley also supported delaying the vote for an additional month, saying she’s continuing to field questions from stakeholders about how the Exelon package would function.

PJM’s Tim Horger said he hadn’t heard of any specific changes being considered for any of the packages and would have been comfortable moving forward with a vote last week, but was supportive of any consensus building that could be done.

Four of the packages include two versions, addressing both co-located load without receiving direct service from the PJM grid and a second for interconnected loads, each of which would have required a second vote with the possibility of the end result being components from two different sponsors being selected. The AEMA proposal does not recognize a distinction between co-located load with or without grid service and would treat both the same.

First Read on Reactive Power Compensation Proposals

During the MIC’s first read last week, stakeholders discussed four packages that would revise the compensation structure for reactive power.

Danielle Croop, PJM’s facilitator for the Reactive Power Compensation Task Force, said the status quo system uses the “AEP methodology,” which identifies equipment at generators that support reactive capability, and each generator is required to make a cost-of-service filing at FERC, many of which result in “black box” settlements.

PJM Assistant General Counsel Thomas DeVita said FERC attorneys have said PJM reactive filings make up a significant portion of their caseload and the commission may seek a resolution of its own.

“If we don’t end this process with a solution there is a significant risk that FERC will act on its own and we will be here again in short order,” he said.

Croop said compensation also is not tied to generators’ performance in supplying reactive power and it sometimes has to provide make-whole and opportunity cost payments. The proposals aim to create uniform compensation — both for providing reactive service and associated opportunity cost payments, reduce administrative burden and draft new market rule changes to replace the existing procedures in Tariff Schedule 2.

A December 2022 poll at the task force found support among members was strongest for the Clean Energy Coalition proposal, at 63%, followed by the PJM package with 28% support. Two packages from the Monitor received 17% and 16% member support. The poll also found that 62% of responding members did not believe that change to the Schedule 2 compensation method is necessary. The poll received 280 member responses, 37 of which were unique.

The proposals are limited to new generators or facilities entering new compensation agreements, with the task force’s scope precluding changing existing reactive rates. The MIC voted down a proposal to expand the task forces’ scope to include existing service rates last month. (See “Stakeholders Reject Proposal to Expand Reactive Power Task Force Scope,” PJM MIC Briefs: June 7, 2023)

The CEC proposal is based on applying the AEP methodology to resources on a class-wide basis by forming a separate rate for each type of generator. The rates would be posted on PJM’s website, but only the underlying formula would be included in the tariff.

The CEC presentation states that applying the AEP process on a technology-wide basis avoids requiring unit-specific FERC filings and treats all generation comparably. Creating a cost-based compensation structure would incentivize investments in reactive capability that caps payments at the cost of the proxy unit. PJM’s proposal would limit compensation to generators that are capable of providing reactive service on the transmission grid, excluding those that can provide it at the distribution grid level. Payments would be based on demonstrated or tested capability and would seek to recognize that all reactive power (VARs) is the same.

Calpine’s David “Scarp” Scarpignato said existing testing for reactive capability often is difficult to complete given technical limitations on the grid, requiring some generators to schedule multiple tests before one can be successfully administered.

Wade Horigan, a principal of Tangibl, said he believes the PJM proposal would create an incentive for PJM and transmission owners to not change voltage during testing and that running only two tests would not reflect generators’ actual capability to respond to a voltage excursion.

PJM’s Glen Boyle said if generators exceed their capabilities, their parameters and compensation would be increased. If generators don’t perform, their revenues would be withheld for that month and future expected capability would be reduced. He estimated the proposal would require an 18- to 24-month implementation period.

Market Monitor Joe Bowring said the AEP method is archaic and illogical and was designed in 1997 to maximize the allocation of costs to reactive for a utility that was fully cost-of-service regulated. Bowring said a recent FERC order on the same issue in MISO required that all such payments for reactive power be terminated.

“There is no need for a cost-of-service approach in a system that relies on markets. This payment of more the $380 million per year in side payments is unnecessary and should be eliminated,” he said.

The first of the Monitor’s proposals — Package F under the matrix — would immediately eliminate separate cost-of-service payments to all resources and would also remove reactive revenues from the energy and ancillary services offset, resulting in an increase in capacity market revenues. All resources currently are required to provide reactive as a condition of their interconnection service agreements (ISA).

The second proposal — matrix Package H — would start with a flat-rate design, similar to PJM’s, but would fully phase out all cost-of-service payments over a short period and would use the same performance penalty as PJM.

Bowring said doing away with the current settlement process and using the AEP method for all resources, as recommended by the CEC, would result in an approximate doubling of the $380 million per year in reactive costs borne by load. He said the FERC order in the MISO reactive compensation case was clear and there also are additional cases in front of FERC that address the fundamental issues of cost-based rates in a market structure.

Stakeholders Question Scope of Distributed Resources Subcommittee

During an update on the work the Distributed Resources Subcommittee (DISRS) is engaged in, PJM’s Ilyana Dropkin noted that Voltus introduced a problem statement and issue charge in which the demand response provider said it could bring a stronger response to the market if offers could reflect operational parameters such as limits in curtailment duration and a need for downtime between curtailments.

Several stakeholders questioned if the DISRS is the best forum for such discussions and whether it’s appropriate for non-voting committees to consider such topics. Scarpignato said subcommittees have the potential to take up subjects that can result in PJM staff being devoted to topics that may not have support at the standing committee level. He predicted the matter brought by Voltus ultimately will result in an issue charge being approved for discussion at either the DISRS or cost development subcommittee (CDS), but it presents procedural questions.

Posted on

NYISO Investigating Storage as Transmission

NYISO has started the process of considering energy storage resources as transmission assets, according to a presentation given to the Installed Capacity Working Group/Market Issues Working Group on July 11.

The ISO will assess existing procedures to evaluate whether ESRs can be treated as regulated transmission assets and what potential rules would be required to operate storage as transmission.

NYISO already identified several issues to the effort, however, including what size or duration of ESRs should be allowed to participate and how “dual-use” storage — resources that could both participate in the markets and act as transmission — should be treated.

Glenn Haake, vice president at renewable energy operator Invenergy, sought clarification on what NYISO’s deliverable would be for this year.

Katherine Zoellmer, market design specialist at NYISO, responded, “This issue discovery will conclude with a recommendation for moving forward, and that is what would be taken into next year’s project.”

Haake also asked if storage will be included as a standalone solution in future public policy transmission need assessments.

“This is something we are considering and working through at the moment,” Zoellmer answered.

NYISO said it will return in a month or two with more information on how the project will proceed and asked that any additional questions, comments, concerns or recommendations be sent to KZoellmer@nyiso.com.

 — John Norris

Posted on

DC Circuit Upholds FERC on PJM FTR Rule

The D.C. Circuit Court of Appeals on Friday upheld FERC’s decision to approve PJM’s financial transmission rights forfeiture rule without ordering refunds under previous rules implemented without commission approval.

But the court remanded the case to FERC to provide a fuller explanation of why it did not order a forfeiture exemption for non-leveraged transactions — when a trader’s FTR gains do not exceed the losses incurred from that trader’s virtual transactions (22-1096).

FTRs are financial instruments that allow load-serving entities to hedge the risk of transmission congestion costs and permit financial traders to arbitrage day-ahead and real-time congestion. PJM originally implemented the forfeiture rule in 2000 to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions.

The commission ruled in May 2021 that PJM’s previous 1-cent FTR impact test, which determines whether the net flow impacts the absolute value of an FTR by 1 cent or greater, to be unjust and unreasonable. FERC approved PJM’s replacement rule in January 2022 (ER17-1433). (See FERC Accepts New PJM FTR Forfeiture Rule, Without Refunds.)

After FERC rejected rehearing requests from FTR trader XO Energy, the traders sought relief in the D.C. Circuit, arguing that the commission’s decision approving the new rules and denying refunds under the old rules was arbitrary.

The D.C. Circuit said XO’s arguments were “ultimately unpersuasive” and that the commission “adequately justified” its decision not to order refunds.

“It considered record evidence submitted by PJM, which explained that calculating refunds would be a difficult task requiring ‘considerable software development and testing work that would take months to complete,’” the court said.

The court was more sympathetic to XO Energy’s contention that the new rule should exempt “non-leveraged” positions from forfeiture because they provide no economic incentive to engage in manipulative conduct.

While it declined to overturn the ruling, the court said FERC had provided only “a brief … inadequate, explanation of why it declined to order a forfeiture exemption for non-leveraged transactions.”

“Although the commission acknowledges that leverage might be one way to determine cross-product manipulation, it states that it opted to allow PJM to employ other means to detect this conduct rather than require exemptions based on leverage,” the court said. “That is the extent of the commission’s explanation. It does not address XO Energy’s position that market manipulation cannot occur when the net losses of a trader’s virtual transaction portfolio exceed the net profits from its FTR portfolio. Nor does it explain why the exclusion of this requirement strikes the appropriate balance between preventing manipulative conduct and not hindering legitimate hedging activity.”

But the court declined to vacate the order, saying instead that FERC could “redress the deficiency of its reasoning by providing a more fulsome explanation for its decision not to order PJM to account for leverage.”

Posted on

FERC-state Transmission Task Force Examines Barriers to GETs

Grid-enhancing technologies (GETs) could offer significant savings, but an industry that is conservative when it comes to grid operations and planning needs to get used to them first, regulators heard Sunday at the Joint Federal State Task Force on Electric Transmission in Austin, Texas.

The motivation for expanding the use of GETs is clear, with the electric industry undergoing a massive transformation that will see its share of total energy use expand from 21% today to 39% by 2050, while decarbonizing power generation, said Andrew Phillips, vice president of transmission and distribution infrastructure for the Electric Power Research Institute.

“There are about 400,000 miles of transmission lines 100 kV and above in the United States,” Phillips said. “We’ve been building them at a rate of about 2,000 miles per year; we are going to have to double that rate to meet that goal to integrate all of those lower-cost and also carbon-free renewables.”

Getting more use out of transmission lines and related infrastructure such as substations and transformers through GETs — such as dynamic line rating (DLR), advanced conductors or topology control — would make that work easier, he said. Different technologies would have different uses because the issues around the grid vary depending on the exact infrastructure.

Short lines (30 miles or fewer) are the ones that are impacted by temperature the most and would benefit from DLRs that take into account actual temperatures, wind speed and other conditions, Phillips said. Generally, the industry allows only as much power through such transmission lines as would work on the hottest day of the year with low wind speeds, but more often than not, they could handle more electricity.

Advanced conductors also would benefit such transmission lines because traditional transmission can operate only up to 93 degrees Celsius, while newer technologies can run more than twice as hot. Such new conductors have been available for a decade, but the industry has longer timeframes than that, with utilities needing to know they will last for many decades.

“For the last 10 years, EPRI has been doing tests on all of these new advanced conductors, and developed a test that can be put into a specification, so that utilities can acquire these conductors with confidence and knowing that they will last for 40 or 50 years,” Phillips said.

Shorter lines would also benefit from DLRs, but the industry needs to get accurate data on a range of things that impact transmission capacity, including temperature, wind speed and the amount of sunlight hitting them. Many technologies are available to measure those factors, with EPRI and its industry partners determining what works best and where, Phillips said.

“If it’s going to become a day-to-day thing, where we’re going to incorporate these things, we need standards and specs, just like we’ve got standards and specs for transformers, insulators [and] conductors,” Phillips said.

The changing capacity of transmission lines is something grid operators are not used to, and it implies a greater risk, so they will have to familiarize themselves with that before it becomes common, he added. It only makes sense that grid operators are conservative.

“Why are they conservative? Because you want to make sure the lights stay on, right?” Phillips said. “But that conservatism is a challenge when you’re trying to incorporate a new technology and increase the risk. … Maybe a reasonable risk, but a higher risk.”

While such technologies offer savings, they cannot replace transmission expansion entirely, FERC Commissioner Mark Christie said. DLR is “dynamic,” which he said means it is always changing; sometimes it can free up more capacity, but other times not.

“From a planning standpoint, how do you work in a dynamic [system]?” Christie asked. “We know there’s tremendous potential — we know they can save a ton of money — where and when they work.”

From a long-term planning point of view, predicting the wind in 10 years is just not feasible, but DLRs can be very useful in a more immediate, economic way, where they can be used to bring cheaper supply to customers, Phillips said. Long-term planners still have to use the static rating of the line because the grid will experience times when it is hot and the wind is not blowing.

Real-time operators have some leeway when it comes to DLR because of conductors’ “thermal lag,” so that if the wind stops blowing, they have a couple of hours to update power flows over dynamically rated transmission, Phillips said.

In MISO, the planning process does not account for GETs, and planners are skeptical about factoring them in for the long term, but the grid operator is much more open to them when it comes to operations, said Michigan Public Service Commission Chair Dan Scripps.

“RTOs are in many cases able to institute reconfigurations when there is a pressing reliability issue in real time but are more hesitant to act in a proactive way that is only focused on economic benefits,” Scripps said.

That could change going forward, especially with the ability to use different transmission line ratings for the summer and winter in planning going forward. When the conditions for DLRs are not right, it might make sense to use topology control, with which grid operators can tweak the system by, for example, shutting down one piece of infrastructure that frees up more power flow overall, Scripps said.

A major issue to getting GETs rolled out around the grid is the financial incentives for utilities, which are biased toward spending more capital and thus earning more returns, FERC Commissioner Allison Clements said.

“The short answer to how do you better integrate it is for the commission to require utilities to consider whether or not to use them, and then to align the financial incentives so that they’re encouraged when they’re considering them,” she said.

It is also important to dispel the “myth” that GETs are new technologies that are rife with risks when deployed.

“The existence of those risks shouldn’t stop us from starting to require consideration of deployment, and certainly the many cases we’ve heard so far about entities that have used dynamic line ratings to the benefit of customers have found ways to manage those,” Clements said.

Acting FERC Chair Willie Phillips offered an analogy for how GETs will impact the industry by comparing them to the change from road atlases to GPS programs on smartphones.

“When you think about how to use GPS, you don’t use it like a map,” Phillips said. “You don’t set it on time and forget about it.”

The software will reroute drivers around traffic jams and to quicker routes to their destination, with drivers using GPS at every turn throughout their journeys.

“I think that’s exactly how we should use GETs,” said Phillips. “We should use it an interconnection queue phase; we should use it during construction — I say ‘use,’ [but] I mean ‘consider.’ We should consider it during the construction phase. We should consider it after construction and during implementation.”

Just before the task force meeting, Grid Strategies released a report showing growing congestion costs around the country, with $12 billion in RTO markets during 2022 and more than $20 billion around the country, Phillips noted.

“If we can use GETs to bring that number significantly down, I think it’s incumbent upon regulators to do just that,” he added.