PJM Maintaining Separate Load Peaks in Model
VALLEY FORGE, Pa. — The Planning Committee last week approved PJM’s recommendation to use 10-year historical data from 2003 to 2012 and to change the “world” peak week in its 2017 reserve requirement study.
PJM’s Patricio Rocha-Garrido told stakeholders the RTO decided to separate its peak load from that of the “rest of world” because of software limitations. Coincident peak distributions from the PJM load forecast cannot be used directly in its PRISM (probabilistic reliability index study model) software, which handles model uncertainty by week rather than day-by-day.
“The world” comprises of neighbors MISO, New York, the Tennessee Valley Authority and SERC Reliability’s VACAR region in Virginia and the Carolinas — areas from which the RTO would seek to import generation if it runs short.
(See “ISO-NE out of this ‘World,’ According to PJM Reserve Requirement Study,” PJM Planning Committee/TEAC Briefs.)
“When we have PJM and ‘the world’ peaking on the same week, effectively we’re having PJM and ‘the world’ peaking on the same day,” Rocha-Garrido said.
However, over the past 18 years, PJM and “the world” have peaked simultaneously eight times, while they have not peaked together 10 times.
In response, PJM moved the world peak to Week 11 in the summer and retained its peak on Week 10 to match the “historical diversity” in peaks.
Rocha-Garrido said the 2003-2012 load model, which was also used in last year’s study, was “a close second place” to the top-ranked 2004-2012 time period but had the advantage of an extra year of data.
“We do not see evidence to change that this year,” he said.
The recommendation was endorsed by acclamation, with no objections or abstentions.
RTEP Cycle Revisions Approved
The committee approved revisions to the rules for the Regional Transmission Expansion Plan, agreeing to extend the cycle from one year to 18 months.
PJM’s Amanda Long said the planning cycle will begin in September and run through February of the following calendar year. A new cycle will begin every September, overlapping the previous cycle. (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)
The committee also approved Operating Agreement changes to extend the 30-day competitive proposal window for short-term projects to 60 days beginning about June annually. The long-term proposal window will remain at 120 days.
The proposal was endorsed by acclamation, with no objections or abstentions.
Resilience to Become Planning Driver
PJM’s Mark Sims explained how the RTO’s recent focus on resilience will impact its planning processes.
NERC’s standards require PJM to consider in its planning critical “stressed” conditions so it can manage the system regardless of actual conditions on any day. In addition, NERC requires the RTO to conduct a system assessment and explore potential solutions of low-probability “extreme” events.
As a result, Sims said, PJM will seek to identify “worst offenders,” such as circuits that frequently are involved in low-probability events. (See “PJM Reconsidering Planning Assumptions,” PJM Planning & Tx Expansion Advisory Committees Briefs.)
“It’s not involved in one low-probability event; it’s involved in many. So in my opinion, it’s no longer low-probability,” Sims said, adding that it “might” make sense to fix these issues.
John Farber of the Delaware Public Service Commission reiterated his concerns from a similar conversation during the Operating Committee meeting earlier in the week.
“There are major issues with implementing resilience as a standalone driver in the RTEP,” he said. “Achieving a sufficient level of objectivity to justify its inclusion as a standalone driver in the RTEP is just a difficult challenge to deal with.”
He said it will be difficult to develop objective cost and benefits criteria to justify millions in spending, especially when individual states may have different viewpoints on spending the money.
Greg Poulos of the Consumer Advocates of the PJM States agreed. Developing appropriate metrics will be important to determine how goals will be achieved, he said. The timeline is another issue, he said.
“There’s a lot of concern about things adding up,” he said. “I certainly agree it’s an evolution, but the consumer advocates are concerned it’s a slippery slope. Where does it begin and where does it end?”
Sims assured stakeholders it would be a “very deterministic” process. “I think this paradigm is going to be a little bit of a shift,” he said.
Winter Evaluation
PJM’s Tom Falin provided an update on the RTO’s analysis of winter resource adequacy and capacity requirements, the subject of an issue charge approved by stakeholders last year. The details highlighted the differences across the RTO. (See “Winter Resource Adequacy Analysis Raises Questions,” PJM Planning & Transmission Expansion Advisory Committee Briefs.)
An analysis of the ratio between the winter and summer peaks in each locational deliverability area (LDA) found that the East Kentucky Power Cooperative was the heaviest winter peaking LDA in the RTO, with a winter-summer ratio at about 1.3. The RTO itself is mostly summer peaking with a ratio of .87, and Rockland Electric is the heaviest summer-peaking LDA with a ratio of about .59.
“The heaviest summer-peaking LDAs are basically [in] New Jersey,” Falin said.
The loss-of-load expectation analysis results found that, even including the outliers from the winter of 2014-15 that included the polar vortex effects, and assuming historical forced outages and the maximum historical planned outages, the LOLE was .02 days/year. Falin noted that these numbers only included generator forced outages and that transmission outages would need to be considered as well.
Going forward, Falin said PJM will compute summer and winter reliability requirements for the RTO and selected LDAs while continuing to investigate a winter load forecast model.
Solar Capacity Factors Class Averages
PJM has updated its capacity factors for wind and solar based on actual summer data from 2014-2016.
PJM’s Jerry Bell said the analysis found that wind turbines have a capacity factor of 14.7% in mountainous terrain during peak summer hours between 3 and 6 p.m. and 17.6% in open, flat terrain during the same period. Solar capacity factors ranged from 60% for ground-mounted arrays that track the sun, to 42% for fixed ground-mounted panels, to 38% for all panel types other than ground-mounted.
The capacity factor affects generators’ capacity revenues and a project’s entitlement to capacity injection rights.
Renewable developers can request higher capacity factors for their projects if they can provide evidence to prove their generators operate at higher levels.
The study hasn’t yet considered how capacity factors are affected by degradation of the equipment over time, but Bell said it will be added in the future. Several stations were removed from the analysis because they displayed obvious degradation over time, he said. Degradation is, however, factored into CIRs for stations, he said.
Transmission Expansion Advisory Committee
Transmission Proposal Window Opens
PJM opened a 45-day window last week seeking proposed transmission projects to fix reliability criteria violations on 43 flowgates. The window will close on Aug. 25.
The flowgates were identified in the 2022 analysis: 34 in PJM’s Western Region, six in the Southern Region and three in the Mid-Atlantic Region. The remaining 161 flowgates from the analysis were excluded from the window as either immediate-need projects or under 200 kV, which is PJM’s threshold for opening projects to competitive bidding. The RTO has found that projects under 200 kV tend to be upgrades handled by the incumbent transmission owner.
Updates to AI Analysis
Staff have updated PJM’s beneficiary analysis for the Artificial Island project to address issues raised by stakeholders at the June 9 special Transmission Expansion Advisory Committee meeting. Among the additions was a list of transmission facilities that could compose a stability interface.
Most of the $280 million bill for the project would shift from Delaware to New Jersey and Pennsylvania under two alternative methodologies outlined in the analysis. But it will be up to PJM’s TOs to petition FERC to adopt a new methodology for the project. “PJM does not have the authority to devise or file allocation methodologies as federal law makes clear that the Section 205 filing rights over rates and cost allocation in this area rests with the PJM transmission owners,” the report says.
The project, PJM’s first foray into competitive bidding under FERC Order 1000, has been bogged down in stakeholder infighting for years. In April, PJM’s Board of Managers lifted a suspension on the project and re-awarded it to LS Power. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
— Rory D. Sweeney