Roundup: Task Forces Delve into Proposals  

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Market Efficiency Process Enhancement Task Force  

The Market Efficiency Process Enhancement Task Force spent much of its June 15 and June 25 meetings comparing and contrasting six enhancement proposals (XLS) in three different categories:

PJM’s Operating Agreement requires PJM to review the costs and benefits of constructing new economic-based enhancements or expansions included in the Regional Transmission Expansion Plan on an annual basis.

The reevaluation process, however, is very complicated due to the large number of market efficiency projects in the RTEP, the undefined order in which the projects must be reevaluated, and uncertainties over other assumptions, including transmission topology, generation, fuel costs and the expected in-service dates of facilities.

PJM and stakeholders reviewed the proposed options to develop alternative solution packages at both meetings. PJM is looking for as much common ground as possible.

The task force opened a nonbinding poll based on the proposals after the June 25 meeting. The task force will review poll results at the July 5 meeting with the goal of a first read at the July 12 Planning Committee. There will also be a separate first read for changes in Manual 14 language (PDF).

Primary Frequency Response Senior Task Force

At the June 19 meeting of the Primary Frequency Response Senior Task Force, stakeholders continued to work on proposals for Federal Energy Regulatory Commission Order 842 but agreed that they are not ready to vote on packages.

The order requires certain generators to provide primary frequency response. PJM has requested clarification on whether Order 842 was meant to include both new and existing resources. There is no timetable for a FERC response. PJM has said there would be a stakeholder vote on the proposals in the fall if the FERC has not responded.

Stakeholders reviewed clarifications on packages from Calpine (Package E) and American Electric Power. AEP also presented exemptions from primary frequency response requirements.

Discussion included possible participation of energy efficiency and demand response products. Glen Boyle, manager – Operations Analysis & Compliance and task force facilitator, pointed out that it might not be technically possible for energy efficiency to provide primary frequency response since EE reduces load.

Stakeholders also looked at how generator owners would need to balance the costs, how much investment they would be willing to make in a new generator and whether they would be likely to make that same investment for an existing resource that has 10 years of life remaining.

PJM also reviewed its communications with the FERC on the Wholesale Market Participation Agreement  and the agreement’s role in PRF.

Energy Price Formation Senior Task Force

At their June 25 meeting, members of the Energy Price Formation Senior Task Force discussed a newly released paper outlining PJM’s proposal to enhance reserve market design and Operating Reserve Demand Curves (ORDCs).

The proposal is not complete, but the concepts it explains “are the most critical to ensuring the reserve markets work efficiently,” the paper says.

The paper addresses:

  • Consolidation of Tier 1 and Tier 2 reserve products
  • Locational reserve assignments and nodal reserve pricing
  • Implementation of ORDCs

At stakeholders’ request, they also heard more about the differences (XLS) among capacity, 10-minute and 30-minute reserve products.

The group discussed locational reserve modeling (PDF). The concern at issue is that PJM’s current, static reserve zone modeling approach doesn’t always accurately reflect the constraints that dispatch is most concerned with overloading. This leads to the potential for reserve prices to be misaligned with the reliability value of those locational reserves.

Catherine Tyler of Monitoring Analytics proposed (PDF) revising the synchronized reserve offer margin to $3.80 per megawatt hour from the current $7.50/MWh, saying there are no “explicit costs” of providing synchronized reserves.

Stakeholders also initiated discussion of an alternative to combining Tier 1 and Tier 2 resources that would include nonperformance penalties for Tier 1 reserves.

Members also heard two presentations about ORDCs: Tyler presented ORDC shape options (PDF), and PJM provided ORDC supplemental information (PDF).

Load Analysis Subcommittee Meeting

Members of the Load Analysis Subcommittee were introduced to potential load forecast enhancements at their June 20 meeting (PDF).

Andrew Gledhill, senior analyst – Resource Adequacy Planning, presented (PDF) potential impacts to the load forecast that reflect tweaks to the current modeling of commercial load and coincident peak. He stressed that the model development is ongoing, and the results are not final.

The effort aims to separate non-weather-sensitive and weather-sensitive load to enhance the accuracy of the winter and summer load forecasts, he said.

The next steps are to gather stakeholder feedback, investigate additional refinements and develop energy, non-coincident and load delivery area capacity performance models.

Gledhill also shared an update (PDF) from the Summer Only Demand Response Senior Task Force, outlining a potential peak shaving program.

Dispatcher Training Subcommittee

All member transmission companies are in compliance with PJM training and certification requirements, the Dispatcher Training Subcommittee reported at its monthly meeting (PDF) June 19. In addition:

  • One generation company is noncompliant with certification requirements, compared with three the previous month (PDF).
  • Four generation companies are noncompliant with training requirements, the same as the previous month.
  • One small-generation company is noncompliant with training requirements, the same as the previous month.
  • One CSP company is noncompliant with training requirements, compared with two the previous month.

The updated PJM Transmission Owner Operator certification exam has been pushed back to Aug. 1. It will be available August and September, with a blackout period starting Oct. 1 while the tests are graded and a cut score is determined.

During August and September, the exams will not be instantly scored. Test-takers will learn how they fared after the blackout period, but those who pass will have a certification date of the day they took the exam.

The drill schedule through Oct. 31 also was presented.