The PJM Market Implementation Committee on Wednesday endorsed rule changes on fast-start pricing, five-minute dispatch, solar-battery hybrids and an issue charge over the handling of energy efficiency in the capacity market. It also heard first reads on other manual revisions and Buckeye Power’s proposed changes to capacity transfer rights, which sparked opposition from the Independent Market Monitor (IMM).
Fast-start Pricing Revisions Endorsed
Stakeholders endorsed revisions to three manuals addressing the implementation of fast-start pricing.
The changes were endorsed with 228 votes in favor (94%) versus 14 votes against adoption (6%) despite concerns from the IMM.
Phil D’Antonio, manager for PJM’s real-time market operations, reviewed revisions to Manual 11: Energy & Ancillary Services Market Operations, Manual 18: PJM Capacity Market and Manual 28: Operating Agreement Accounting. The revisions were first introduced last month. (See “Fast-start Pricing Manual Revisions,” PJM MIC Briefs: July 14, 2021.)
D’Antonio said there were no changes from the red-line language in the manuals when they were presented in July.
FERC accepted PJM’s filing in an order issued in May on its fast-start tariff changes with an effective date of July 1. (See FERC Accepts PJM Fast-start Tariff Changes.) PJM filed a request to move the effective date to Sept. 1 to avoid implementation during the summer peak period, which the commission approved.
The fast-start pricing order, which necessitated manual changes, included the implementation of separate dispatch and pricing runs in day-ahead and real-time markets, the defining of fast-start resources as those with a total time to start and minimum run time of less than or equal to one hour and the offer of lost opportunity costs (LOC) to provide incentives to follow dispatch.
Section 2.1 of Manual 11 was reorganized to include new sections on fast-start-capable resources, fast-start-capable adjustment processes and eligible fast-start resources. Other manual changes featured new day-ahead sections, including energy offers used in day-ahead price calculations and day-ahead integer relaxation (a process allowing the commitment status for a fast-start resource to vary between zero and one, inclusive of zero and one).
Updates to Manual 18 included a footnote added to section 8.4A clarifying scheduled megawatts used for “excusal and bonus purposes” in performance assessment interval (PAI) settlements calculated using dispatch run locational marginal pricing (LMP).
Manual 28 is expanded with a section on dispatch differential lost opportunity cost credits, which will provide incentives for resources dispatched down in the security-constrained economic dispatch (SCED) to continue following PJM’s dispatch instructions to address the “inflexibility” of fast-start resources. It also includes an offset to avoid the double counting of commitment costs.
Zhenyu Fan, PJM senior engineer, reviewed fast-start implementation and metrics, saying the RTO continues to monitor fast-start on a daily basis “for quality control and risk mitigation.” He said PJM is ready to fully implement fast-start pricing on Sept. 1.
Catherine Tyler of the Independent Market Monitor provided an overview of the IMM’s concerns regarding the formation of ancillary service market clearing prices under some fast-start conditions.
Tyler originally called attention to section 4.2.9: Synchronized Reserve Market Clearing Price Calculation in Manual 11 at the July MIC meeting. The updated manual languages states, “In the pricing run, the cost of the marginal synchronized reserve resource may also include amortized start-up and amortized no-load costs due to integer relaxation for eligible fast-start resources.”
Tyler said the Monitor believes PJM should not implement fast-start pricing in this way because it’s “not consistent with the filings and the FERC approved Operating Agreement.” Tyler said the result of the change is that the commitment cost of the marginal unit for reserves is included in the reserve clearing price when there is no LOC.
“It’s a detailed issue, but it’s pretty straightforward to understand,” Tyler said.
Carl Johnson of the PJM Public Power Coalition said he appreciated that the IMM brought the issue forward and presented an example of what it could look like in action, but he wasn’t sure if a solution was being recommended.
“While we always want to get these things right, I’m not sure we’re in a position to advocate for a delay from the Sept. 1 start,” Johnson said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), asked what the IMM believed the impact on costs would be if the proposed language remained the same.
Tyler said the issue doesn’t occur with a “high frequency,” but when it does occur the effect on prices is significant because amortized start-up and amortized no-load costs can be “quite large.”
“It’s a little difficult to directly quantify,” Tyler said.
Paul Sotkiewicz of E-Cubed Policy Associates said he disagreed with the IMM’s interpretation of the filing, calling it “much ado about nothing.” Sotkiewicz said PJM’s solution was “just part and parcel of co-optimization” that had already been approved by FERC.
“I think this is just a collateral attack from the IMM on PJM’s use of integer relaxation versus the method preferred by the IMM,” Sotkiewicz said.
Tyler said Sotkiewicz’s assertion was not correct and that the FERC order was clear. Tyler clarified that the impact on reserve prices is not due to co-optimization and that it is possible to implement fast-start with co-optimization without this result occurring.
The manual changes will be voted on at the Aug. 25 Markets and Reliability Committee meeting.
5-Minute Dispatch Revisions Endorsed
Members unanimously endorsed Manual 11 updates modifying and adding transparency to five-minute dispatch rules.
Aaron Baizman, PJM lead engineer with real-time market operations, reviewed the revisions to Manual 11: Energy & Ancillary Services Market Operations that were first presented at the July MIC meeting. (See “5-Minute Dispatch Manual Revisions,” PJM MIC Briefs: July 14, 2021.)
Stakeholders unanimously endorsed the proposed solution and associated tariff and Operating Agreement revisions at the April MRC and MC meetings. (See “Long-term 5-minute Dispatch Endorsed,” PJM MRC/MC Briefs: April 21, 2021.)
Baizman highlighted section 126.96.36.199: Capacity Resource Offer Rules, which adds a rule stating hydropower resources fall under the intermittent generation resource category and that hydropower resources that are committed capacity resources “shall meet the must-offer requirement by self-scheduling” and offering as a must-run resource.
A separate section on pump storage hydropower capacity said resources have to offer as must run or use the PJM pump storage optimization model in the day-ahead market. He said the two hydropower changes were made to conform with existing language in section K of the tariff.
Baizman said Section 2.5: Real-time Market Clearing Engine saw many edits with multiple diagrams updated and additional information added for real-time SCED optimization concerning the marginal resource identification process.
The Manual 11 changes will be voted on at the August MRC meeting.
Solar-Battery Hybrid Proposal Endorsed
Stakeholders endorsed a PJM proposal to clarify market participation by solar-battery hybrids and other mixed technology resources.
The PJM proposal, which has been worked through the DER and Inverter-based Resources Subcommittee (DIRS), received 235 votes in support (99%) with three stakeholders voting against. Members also unanimously voted to support the proposal over maintaining the status quo on the issue.
Andrew Levitt of PJM’s market design and economics department reviewed the RTO’s solar-battery hybrid resources issue. Levitt introduced the proposal at the July MIC meeting. (See “Solar-battery Hybrid Resources,” PJM MIC Briefs: July 14, 2021.)
The solar-battery hybrid resources problem statement and issue charge were originally brought forward by PJM staff and approved by stakeholders at the June 2020 MIC meeting to clarify business rules. (See “Solar-Battery Hybrids,” PJM MIC Briefs: June 3, 2020.)
The PJM proposal provides updates to the RTO’s governing documents and business manuals to clarify several aspects of market participation by solar-battery hybrid resources. The proposal introduces new definitions, including “mixed technology facility,” “hybrid resource,” “co-located resource” and “open-loop hybrid resource,” while a “standalone energy storage resource” is defined to draw a distinction between hybrid resources and other energy storage resources.
Levitt said the definitions are required to clarify new resource types and apply new or existing business rules to each resource type. For co-located resources, Levitt said, the proposal clarifies that market participation occurs separately for each underlying resource type and that metering and telemetry are required both at the point of interconnection (POI) and on one or all the underlying resource types behind the POI.
Levitt said a new “family” of models was created to include three types of solar-battery hybrid resources in the energy market:
- An existing standalone energy storage resource (ESR) participation model;
- An open-loop solar-battery hybrid resource model that can charge from grid, which is a type of ESR, and;
- A closed-loop solar-battery hybrid resource model that cannot charge from grid and is not a type of ESR.
Market Monitor Joe Bowring said the IMM “totally” supported PJM’s proposal, saying it “enhances competition.”
Dominion Energy’s Jim Davis reviewed an alternative proposal, which was identical to PJM’s proposal except for a provision pertaining to the regulation market. Stakeholders rejected the Dominion proposal, with 69 members (34%) voting in favor.
The PJM proposal will move on to the MRC for consideration.
Energy Efficiency Add-back Issue Charge Endorsed
Members unanimously endorsed an issue charge presented by the IMM on calculating the energy efficiency (EE) add-back.
Monitor Bowring reviewed the problem statement and issue charge addressing the calculation. Bowring presented the issue at the July MIC meeting. (See “Energy Efficiency Add-back,” PJM MIC Briefs: July 14, 2021.)
Bowring said the current treatment of the EE add-back in clearing the Base Residual Auction does not require it to match the effect of EE on the capacity market’s variable resource requirement (VRR) curve. Bowring said the result of the treatment is an artificial increase in the BRA clearing price even though EE was originally designed to be neutral.
The proposed solution calls for rewriting the manual language to permit PJM to calculate the EE add-back in the capacity market clearing so that the total EE add-back megawatts offsets the total cleared EE megawatts in the BRA.
The IMM initially requested that the “quick-fix” process be used to complete work on the issue so that PJM can use the correct EE add-back data for the upcoming 2023/24 BRA in December, but some stakeholders requested an additional month of discussion to explore options. The issue charge was amended to use the “CBIR Lite” (Consensus Based Issue Resolution) process and take two months instead of one to complete it.
After the vote, Jeff Bastian, senior consultant of PJM’s market operations, provided education on how EE is treated in the Reliability Pricing Model (RPM) for the capacity auction. Lisa Morelli of PJM facilitated a discussion on the development of the CBIR matrix.
Stakeholders made a few suggestions for interest identification of the issue on the matrix. In addition to minimizing the impact of the add-back process on clearing prices, stakeholders also called for preventing an adverse reliability impact from double-counting EE as a capacity resource and as a load forecast reduction, and ensuring a timely auction clearing.
The issue will be discussed again at the Sept. 9 MIC meeting.
Manual 15 Revisions
Tom Hauske of PJM’s performance compliance department provided a first read of the Manual 15: Cost Development Guidelines revisions regarding the incremental and no-load energy offer developed in the Cost Development Subcommittee (CDS). PJM also provided Operating Agreement and tariff revisions related to the manual changes.
Hauske said there are “quite a few changes” proposed in the manual. The main ones involve revising the no-load cost and incremental energy offer definitions to “more clearly define what costs can be included” and how they should be calculated.
Hauske said the biggest manual changes come in section 2.3 for the definition of incremental energy cost, which says, “The incremental energy cost is the cost in dollars per MWh of providing an additional MWh from a synchronized unit.” The changes also include methods for market sellers to submit sloped, stepped or block loaded incremental offers into PJM’s Markets Gateway System.
The committee will be asked to endorse the Manual 15 revisions at the September MIC meeting; the OA and tariff will be voted on by the Markets and Reliability Committee.
RPM Capacity Transfer Rights
Kevin Zemanek, director of system operations for Buckeye Power, provided a first read of Buckeye’s proposal regarding the allocation of capacity transfer rights (CTRs).
Stakeholders originally endorsed Buckeye’s issue charge at the March MIC meeting with 79% support. (See “RPM Issue Charge Endorsed,” PJM MIC Briefs: March 10, 2021.)
Zemanek said under the RPM, CTRs return to load-serving entities (LSEs) capacity market congestion revenues that occur when there’s a difference between the prices paid by load and market revenue received by cleared resources. He said CTRs permit LSEs with load inside a constrained locational delivery area (LDA) to receive a credit for the import of capacity from a lower-priced region.
Zemanek said PJM does not have a way to allocate CTRs directly to an LSE with network resources outside a constrained LDA but whose resources have been designed as deliverable on the LSE’s network integration transmission service agreement. Instead, Zemanek said, PJM allocates CTRs pro rata to each LSE serving load in the LDA or zone based on the LSE’s share of the zonal unforced capacity obligation.
Buckeye’s proposal calls for first allocating zonal CTRs to LSEs with historic generation resources identified as network resources in a network integration transmission service agreement (NITSA). The allocated CTRs will be “sufficient to meet the LSE’s daily unforced capacity (UCAP) load obligation but shall not exceed the total amount of the LSE’s generation capacity as identified on the LSE’s NITSA.”
The proposal would recognize generation resources and transmission rights that existed prior to the implementation of RPM but would also terminate upon the retirement of a resource or a change in the designated resource status in the NITSA. The new rules would be implemented at the next available CTR allocation process following FERC approval.
“We’re not changing the calculations for transmission constraints, and we’re maintaining reliability by keeping the total amount of CTRs the same,” Zemanek said.
Bowring opposed the proposed changes, saying that Buckeye’s approach was an attempt to use a non-market contract path approach rather than the market network approach that the CTR design was based on. He said the Buckeye approach meant that the company would be paid more and other market participants would be paid less. “It is a zero-sum game,” Bowring said.
Bowring also said the Buckeye proposal was inconsistent with the way in which the value of CTRs is defined based on delivery year forecasts rather than the results of the capacity base auction.
Bastian reviewed the megawatt quantity of qualified requests by zone to assist participants in evaluating the impact of the Buckeye proposal. Buckeye has said the impact of the current rules vary from year to year; it said the rules cost it $10 million in the 2015/16 delivery year and $2.5 million in 2016/17.
The committee will be asked to endorse the proposal at the September MIC meeting.