By Rich Heidorn Jr.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
1. PJM Manuals (9:15-9:35)
Members will be asked to endorse the following manual changes:
B. Manual 40: Training and Certification Requirements: Cover-to-cover periodic review.
C. Manual 14B: Regional Transmission Planning Process: Minor changes to ensure consistent terminology; revision to Section 1A on critical energy infrastructure information (CEII); Attachment C revisions concerning changes to load deliverability procedures; and updated generator and long-term deliverability procedures.
D. Manual 14G: Generation Interconnection Requests Planning Process: Cover-to-cover review.
2. Transmission Replacement Process (9:35-10:30)
Transmission owners will compete with load interests and merchant transmission operators for stakeholder endorsement of proposed manual revisions to address end-of-life facilities in the PJM planning process.
American Municipal Power’s proposed changes to Manual 14B: Regional Transmission Planning Process, which were seconded by Old Dominion Electric Cooperative at the July 27, 2018, MRC meeting, will be considered the main motion. PJM’s proposed revisions, which were moved by FirstEnergy and seconded by Public Service Electric and Gas at the Dec. 20, 2018, MRC meeting, will be the first alternate motion. (See AMP Offers ‘Best We Can Do’ on PJM Tx Planning and “Transmission Replacement,” PJM MRC Briefs: Dec. 20, 2018.)
AMP would add language in section 1.5.4 to require sufficient information for stakeholders to replicate TOs’ results on the need for proposed supplemental projects. It also would strike the word “useful” in references to “end of useful life.”
PJM said its proposal provides additional transparency to the Regional Transmission Expansion Plan process and incorporates most of the AMP/ODEC-proposed changes along with input from TOs.
LS Power has proposed a friendly amendment to either proposal that would limit the ability of supplemental projects — which are developed by TOs based on their own criteria — to supplant competitively bid projects accepted by PJM to address regional reliability violations or other criteria.
The main motion will be voted first. If it fails, the alternate motion will be brought to a vote.
3. Energy Price Formation (10:30-11:30)
Members will be asked to endorse one of four packages of energy market rule changes from the Energy Price Formation Senior Task Force (EPFSTF). The Board of Managers told members last month that it will make a unilateral filing with FERC if members do not reach consensus on a package by Jan. 31.
The rule changes will affect shortage pricing; reserve products; synchronized reserves; secondary reserves; and the alignment of the day-ahead and real-time reserve markets.
PJM’s proposal would replace the current stepped operating reserve demand curve (ORDC) with a sloped curve; the first horizontal segment would represent the minimum reserve requirement, with the downward sloping curve based on the probability of reserves falling below the minimum reserve requirement (PBMRR) in real time based on uncertainties.
The D.C. Office of the People’s Counsel proposed a similar ORDC, except that the downward sloping curve would take into account the regulation requirement.
The Independent Market Monitor’s proposal would leave the ORDC unchanged and reduce the current two-step penalty factor ($850 and $300) with a single penalty factor equaling the safety net energy offer cap of $1,000/MWh. If PJM approves a cost-based offer above that price, the penalty factor could increase in $250/MWh increments to a maximum of $2,000/MWh.
The PJM proposal would increase the price for the initial horizontal segment of the curve to $2,000/MWh and replace the second step of the curve with a downward sloping segment valued at $2,000 times the PBMRR.
Calpine supports the PJM proposal except that it would eliminate PJM’s proposed transitional mechanism to the energy and ancillary services (E&AS) revenue offset. PJM proposed the transition to reflect expected changes in revenues in the determination of the net cost of new entry. (See Monitor Sees Problems with PJM Reserve Pricing Plan.)
Votes at the EPFSTF meeting Wednesday will determine the breadth of support for the proposals and how they will be considered at the MRC.
4. Incremental Capacity Transfer Rights Clarifications (11:30-11:45)
Members will be asked to endorse revisions to section 234.2 of the Tariff to require new service customers to request incremental capacity transfer rights (ICTRs) calculations during the facilities study phase. Customers can include up to three locational deliverability areas in the request.
Section 234.2 requires PJM to determine in the system impact study the increase in capacity emergency transfer limit resulting from an interconnection, merchant transmission facility or customer-funded upgrade.
The change is in response to a FERC order that found PJM had not been following section 234 for assigning ICTRs. PJM had clarified the procedure in Manual 14E, but FERC said it must also be added to the Tariff (EL18-183).
The MRC and MC will also be asked to endorse the changes on their first read so they can be filed with FERC by Jan. 31.
Consent Agenda (1:20-1:25)
Members will be asked to approve a revised definition of “on-site generators” in the market participation rules in the Tariff and Operating Agreement. The changes will affect distributed energy resources located behind a customer’s meter participating as demand response to reduce load and as generation to inject power.
1. FTR Mark-to-Auction Credit Requirements (1:25-1:40)
The committee will be asked to approve a new mark-to-auction component for financial transmission rights credit requirements, a change prompted by the GreenHat Energy default.
Although a decline in market value can indicate increasing FTR risk, current rules do not provide for a collateral call when an FTR portfolio’s value is deteriorating.
Proposal G-1 would consider the difference between the FTR purchase price and most recent market price. It was endorsed by the MRC by acclamation, with one objection, in December. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)
2. Energy Price Formation (1:40-2:40)
The committee will be asked to approve revisions to the energy and ancillary market rules to improve price formation. (See MRC item 3 above.)
3. Incremental Capacity Transfer Rights Clarifications (2:40-3:00)
Members will be asked to endorse revisions to section 234.2 of the Tariff to require new service customers to request ICTR calculations during the facilities study phase. (See MRC item 4 above.)
4. Opportunity Cost Calculator (3:00-3:30)
The committee will be asked to endorse revisions to Manual 15: Cost Development Guidelines governing generators’ use of the Monitor’s calculator as an alternative method of calculating energy market opportunity costs.
Members also will be asked to approve related revisions to Schedule 2 of the OA. (See “Opportunity Cost Calculator Vote Deferred,” PJM MRC/MC Briefs: Oct. 25, 2018.)