Load representatives said Thursday they will oppose PJM’s proposal to increase the installed reserve margin (IRM) to 16.6%, from 15.7%.

“There’s going to be a lot of push back on this,” said James Wilson, a consultant to state consumer advocates, who criticized what he called PJM’s “arbitrary” choice of a load model. “There’s quite a lot of load models that would fit equally well” but result in lower reserve margins, Wilson said.

Ed Tatum said the proposal prompted a “fairly violent” reaction among his colleagues at Old Dominion Electric Cooperative and threatens to renew the “IRM wars” of previous years.

Tatum said the increase in the IRM was “counterintuitive” given the higher performance expectations of PJM’s new Capacity Performance product. As a result, he said, load representatives will challenge the “overly conservative” assumptions PJM used in calculating the figure.

PJM’s Patricio Rocha-Garrido said the increase resulted from changes in 2015 capacity and load models as well as a decline in the capacity benefit of ties (CBOT) — expected capacity imports.

Rocha-Garrido noted that seemingly large increases in IRM may not have that much impact on the forecast pool requirement (FPR), which determines the amount of capacity procured in the annual Base Residual Auction.

The reliability requirement is calculated based on the 50/50 peak load forecast for the delivery year multiplied by the FPR. The FPR is increasing from 1.0847 to 1.0881 (from 8.47% to 8.81% above the peak load forecast.)

The increase is a result of a new load model (2003-2012) that better represents the coincident peak distribution in the 2015 load forecast, Rocha-Garrido said.

The CBOT was reduced because the “rest of world” peak demand is becoming more coincident with the PJM peak, he said.

PJM will seek members’ endorsement of IRM and associated parameters for delivery years 2016 through 2019 beginning in October, with final approval by the PJM board expected in December or January.

New Methodology Could Lower Summer 2018 Forecast by 2.6%; Winter down 1.8%

PJM could lower its 2018 summer peak load forecast by 2.6% as a result of new forecasting methodology that incorporates more recent economic data, a shorter weather simulation and the energy efficiency of air conditioners and electric appliances.

The new methodology also would reduce the winter 2018 forecast by 1.8% over the current official projection.

The forecast outlined to the PC last week will be finalized after an additional update to economic data, equipment index trends and any additional equipment “saturation” data by zones.

Manual language documenting the new methodology still needs to be developed and presented to the PC and MRC.

PJM said the new methodology will reduce the error rate for forecasts three years into the future to 1.5%, compared with the current method’s 6.6%.

One significant change is the RTO’s effort to improve its weather forecasts to reflect a trend of higher peak temperatures.

The RTO has based its forecasts on temperature and humidity data from 26 weather stations dating back to 1973. But a new analysis revealed that peak readings for 1993-2013 were higher than those for 1973-1993.

As a result, PJM’s Andrew Gledhill said, the RTO plans to exclude the earlier data and rely on that from 1994/95. It will reevaluate the historical base about every five years. (See “Climate Change Impact? Higher Highs has PJM Adjusting Weather Forecasts,” in PJM Planning Committee Briefs.)

ODEC’s Tatum said PJM’s plan to reevaluate the time sample for the weather forecasts could inject subjectivity into the modeling, creating a temptation to make changes “to get the answer you want.”

But PJM’s Tom Falin said the weather analysis will be done independently and not evaluated based on its impact on the forecast load.

At the Oct. 1 Markets and Reliability Committee meeting, PJM officials will discuss how they plan to incorporate the new methodology into its capacity auctions. Stu Bresler, senior vice president of markets, said adjustments will have to be made to ensure the RTO is not double counting energy efficiency, which can offer into the auction as a capacity resource.

Action Delayed on Voltage Threshold for Competitive Projects

PJM delayed a vote on a plan to exclude transmission reliability projects below 200 kV from competition, saying it wants to refine the proposal in response to stakeholder comments.

PJM said reliability projects below 200 kV are almost always allocated to one zone and thus automatically assigned to the incumbent transmission owner. The “voltage floor” would allow the RTO to eliminate the cost of evaluating competitive proposals in cases where the likely solution is a transmission owner upgrade. It would not apply to market efficiency projects.

Competitive developers expressed reservations about the proposal at the August PC meeting. (See “Developers Wary of ‘Voltage Floor’ on Competitive Projects” in PJM Planning Committee Briefs.)

At last week’s PC, PJM distributed an expanded chart for how the RTO would handle projects between 100 kV and 200 kV and those above 200 kV or below 100 kV. PJM’s Sue Glatz said the chart “narrows the scope of discretion” for PJM in determining whether or not to open a project to competition.

ITC Holdings’ John Kopinski said the chart made his company more comfortable with the proposal, which he said was consistent with the FERC-approved process for deciding which projects are competitive and which are reserved for incumbents. “You’re not really changing what’s competitive and what’s not,” he said.

Paul McGlynn, general manager of system planning, said PJM will modify the chart and proposed Operating Agreement language to reflect stakeholder comments from the meeting. PJM would like to implement the change in time for the 2016 Regional Transmission Expansion Plan.

Winter Peak Reliability Study

PJM planners last week outlined new rules for separately modeling winter reliability as part of the RTEP.

The changes to Manual 14B: PJM Region Transmission Planning Process would require planners to conduct a reliability analysis to ensure that the grid can deliver enough generation to meet the 50/50 winter peak. It will model generators by fuel class based on historical operation during winter peak loads.

In the past, PJM has planned for reliability based only on its summer peak load.

The changes will be brought to an endorsement vote at the PC next month, with plans to incorporate the study in the 2016 RTEP.

At the Transmission Expansion Advisory Committee meeting later Thursday, planners presented the results of their first study under the new rules, which defines winter as December through February. (See pp.11-24 of the presentation.)

The analysis looked at thermal and voltage violations both with and without consideration of gas contingencies. The North American Electric Reliability Corp.’s transmission planning standard (TPL-001-4), which takes effect Jan. 1, requires PJM to consider extreme system events such as the loss of a large gas pipeline serving significant generation.

PJM analyzed 30 gas pipeline and compressor failure contingencies that could result in the loss of 1,000 MW or more of generation.

Two contingencies, for pipeline outages in EMAAC, suggested the potential loss of 10,000 MW of generation, although officials said the generation would not go offline immediately because of the ability to burn “line pack” gas.

McGlynn said the results of the winter study did not suggest “the sky is falling” but reinforced the need for criteria to capture problems not seen in the light load or summer analyses.

Manual Language on Multi-Driver Projects OK’d

Members approved manual changes documenting how PJM will oversee transmission projects that have multiple benefits. The new rules on multi-driver projects are documented in manuals 14B and 14A: Generation and Transmission Interconnection Process.

Multi-driver projects have benefits in at least two categories, including baseline reliability upgrades, market efficiency and public policy.

States seeking to meet public policy objectives could sign on to projects after they have been approved. But once rights of way or equipment such as transmission towers have been acquired, states would be liable for costs “even if they didn’t go forward with the solar farm or wind farm,” said PJM’s Fran Barrett.

Long-Term Firm Transmission Service Study

The PC approved the charter for a group considering changes to the way PJM conducts studies for long-term firm transmission service.

The group, which resulted from a problem statement approved in April, has met twice, with a third meeting set for Sept. 24.

It will determine if changes are needed to:

• Modeling practices for long-term firm transmission service requests (TSRs) in RTEP power flow cases;
• Study methods used in RTEP and new service queue studies; and
• Cost allocation requirements associated with long term TSRs.

PAR Transmission and Withdrawal Rights

Planners gave stakeholders the first read on rules governing how phase angle regulators (PARs) that redirect energy flows can qualify as controllable AC merchant transmission facilities.

The proposal resulted from a problem statement proposed last November by PSEG Energy Resources & Trade.

PJM currently awards withdrawal and injection rights to controllable AC and DC merchant transmission facilities using only variable frequency transformer (VFT) technology, which excludes PARs. (See “PSEG Seeks Injection Rights for PARs” in PJM Planning Committee Briefs.)

The task force appointed to review the issue endorsed a PJM staff recommendation after staff determined through flow control analyses that PARs “did not show any significant deviation from other controllable AC or DC type installations.”

The task force said that PARs did not harm holders of existing injection and withdrawal rights “assuming reinforcements identified for PAR installations were made.”

PAR owners will be required to comply with rules governing allowable deviations for all resources that are self-scheduled. The operators must be able to control their flows automatically, with the ability to manually adjust.

PJM will allocate costs for PAR facilities consistent with the methodologies used for HVDC and VFTs.

The new rules will be added to Manual 14E: Merchant Transmission Specific Requirements; no Tariff change is required.

— Rich Heidorn Jr.