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November 14, 2024

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Facing Opposition, PJM Delays UTC Cap Pending Broader Review

By Rich Heidorn Jr.
PJM Insider

Wilmington – PJM’s proposal to limit Up to Congestion (UTC) bids stalled at the Markets and Reliability Committee Thursday, as members called for a broader review of the bidding technique.

PJM proposed the cap because high bid volumes can make it difficult for the RTO’s day ahead markets software to reach solutions. Although the proposal was supported by financial market players who are the predominant users of UTC, other members balked, calling for a broader review of the impact of UTCs, which have grown in popularity since their creation in 2000.

The committee voted to defer consideration of the cap for two months to allow an in-depth discussion of their impact on the PJM markets.

UTCs were created as a way to hedge the exposure to price differentials from the source to the sink of physical energy deliveries. Trading volumes have increased since late 2010, when PJM eliminated a requirement that UTC bids include transmission reservations. “What started as a hedge for physical transactions has evolved into a virtual product,” said Stu Bresler, PJM vice president of market operations.

The proposed cap would allow PJM to limit a market participant to 3,000 UTC transactions per day when the RTO believes higher volumes would degrade performance of its day ahead software.  PJM already has authority to limit virtual bids but it has never invoked it.

Carol Smoots, counsel to the Financial Marketers Coalition, said her members reluctantly supported the cap to allow PJM flexibility. Smoots said she would oppose UTC changes that shifted costs to her members.

Independent Market Monitor Joseph Bowring, who was among those seeking a delay on the cap, said the review of UTCs should include the subject of cost causation.

Andy Ott, PJM’s senior vice president for markets, supported a brief review to increase members’ understanding of UTCs and how they compare with spread bids. “We don’t see a sense of urgency [for the cap] we saw a couple months ago,” he said, noting that bid volumes had fallen recently.

Ott said PJM needs to have a broader discussion on cost allocation that will include UTCs and virtual transactions and might result in such transactions being allocated a fixed fee. But he said that discussion should be handled separately by the Market Implementation Committee. “We can’t have a 10-month discussion on cost-causation,” before enacting the bid cap, Ott said. “We certainly can take a month or two.”

The vote to defer action passed with no opposition and three abstentions. The resolution did not include a reference to exploring cost considerations.

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Members Reject Change to Congestion Fee Allocation

By Rich Heidorn, Jr.
PJM Insider
Wilmington – PJM stakeholders Thursday soundly defeated a proposal to relieve holders of Financial Transmission Rights (FTRs) from responsibility for balancing congestion costs.

The proposal by Steven Lieberman of Old Dominion Electric Cooperative concerned market-to-market (M2M) payments under the Midwest ISO-PJM Joint Operating Agreement. It would have eliminated the balancing congestion account as a source of M2M funds and allocated the costs to the Balancing Operating Reserve (BOR) deviations account. The Members and Reliability Committee (MRC) rejected the proposal on a sector-weighted vote of 1.57-3.43.

The proposal was something of a Hail Mary pass, coming after the MRC failed to reach consensus on two other proposed changes to the funding of balancing congestion.

Supporters of the proposal said the change was needed to eliminate disparities in the allocation of M2M payments. When PJM exceeds limits on a binding MISO flowgate, the cost is assigned to BOR if the constraint is relieved by a PJM generating unit. The cost is assigned to holders of Financial Transmission Rights (FTRs) if a MISO generator relieves the constraint. This allocation method, some say, has contributed to increasing underfunding of FTRs.

Harry Singh, vice president at J. Aron & Co., presented an analysis that showed funding available for FTRs in January was only about 50% of target allocations. In some hours, underfunding reached 100%, Singh said.  Most of the underfunding was the result of construction-related transmission outages, he said.

“People say FTRs were never intended to be a perfect hedge,” Singh said. “I get it. But if you have 100% underfunding it’s no hedge at all.”
Other stakeholders acknowledged concern over FTR underfunding but said the proposal brought to the committee shifted costs without addressing the causes.

“This proposal is to squish the balloon and have it pop out somewhere else,” said David Pratzon, who represents generators.

Walter Hall, an energy market advisor to the Maryland Public Service Commission, noted that Market Monitor Joseph Bowring has questioned whether FTR underfunding is a real problem or the result of improper measurement. “We are concerned about additional charges on end users,“ Hall said.

In December, two other proposals to reallocate the cost of balancing congestion also failed to win consensus. The first option, which would have allocated costs to real time loads and exports, won majority support from only the Other Supplier segment. The Electric Distribution (ED) segment was unanimous in opposition.

A second option, to allocate costs to all FTR MWh, including counter-flow FTRs, also failed despite support from most ED and End Use Customer members. Most Generators, Other Suppliers and Transmission Operators were opposed.

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Manual Change: Senior Subcommittee Voting (M34)

The following change was approved by the Members Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 34: Stakeholder Process – voting by senior subcommittees

Reason for change: Subcommittees reporting to a senior standing committee, such as the Cost Development Subcommittee, were not allowed to conduct voting. Such committees need to conduct votes in order to submit a “Main Motion” to their superior committee.

Impact: The manual was amended with a bullet at the end of Section 7.4 that allows such subcommittees to vote on proposals using the same method as a standing committee as described in section 8.3. Task forces reporting to senior standing committees already had authority to conduct votes.

 PJM Contact: David Anders

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Manual Change: Light Load Analysis (M14B)

Changes to the following PJM manual was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 14B: PJM Regional Transmission Planning Process – clarification of light load analysis, SOL/IROL definitions

Reason for Change: The light load analysis section and SOL/IROL definitions required clarification. Also responds to a FERC recommendation regarding communication of modeling information between PJM and its member companies.

Impacts:

  • Adds detailed language to Section D-2.2 Light Load Reliability Analysis Procedure to clarify the application of the criteria. The light load reliability analysis tests the ability of an electrical area to export power during light load conditions. Applied to ensure that generation, including renewable generation, is not “bottled” due to reliability concerns.
  • Amends Attachment F: Determination of System Operating Limits to align definition of System Operating Limits (SOL) and Interconnected Reliability Operating Limits (IROL) with PJM planning practices. SOL includes all Bulk Electric System (BES) facilities and “Reliability and Markets” sub-BES facilities, as listed on the PJM Transmission Facilities pages; IROL definition amended to include lower voltage facilities monitored by PJM Operations. SOL and IROL are used in the transmission planning horizon.
  • Amends Attachment H: Power System Modeling to respond to a FERC recommendation that PJM establish a procedure to communicate interim updates of Regional Transmission Expansion Plan (RTEP) analysis models. PJM will communicate major updates to the RTEP analysis models outside of the annual model update window to Transmission Owners through the Transmission Expansion Advisory Committee (TEAC). PJM also will notify neighboring entities that may be impacted and make the updated affected models available upon request.

PJM Contact: Mark Sims

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Manual Change: Internal Sources and Sinks (M28)

The following PJM manual change was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 28: Operating Agreement – removal of internal sources and sinks / OASIS Regional Practices document

Reason for change: To address the removal of internal sources and sinks as an option for external Day Ahead and Real Time markets transactions on OASIS. The removal of internal sources and sinks was approved by MRC April 27, 2011 at the recommendation of the Independent Market Monitor.

Impact: Eliminates potential for uncollected congestion charges for Not Willing to Pay Congestion Transactions. Moves charges from explicit to implicit billing line item.

  • Added language in Regional Practices section 1.1 and Manual 28 (Section 2: Interface Pricing) to clarify that source and sink choices on OASIS are limited to the path border point for all products.
  • Exceptions may be granted for:
    • Existing grandfathered transmission service reservations and potential future grandfathered transmission service reservations that may be created with a new transmission owner integration.
    • Reservations for dynamic schedules. Such reservations will explicitly identify the source for a generator or the sink for a load.  OASIS administrators will update the reservation upon confirming the exception.  When ARRs are requested, the customer will indicate the source and sink in the customer comments section of the reservation.

PJM Contacts: Mike Colby; Eric Hsia

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Manual Change: Nuclear Plant Coordination (M39)

The following PJM manual change was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 39:  Nuclear Plant Interface Coordination – three-year review

Reason for change: NERC Reliability Standard NUC-001 R9.1.3 requires PJM to review Manual 39 every three years, including Nuclear Plant Interface Requirements.

Impact: Changes reflect review by the System Operations Subcommittee, with support from the Nuclear Generators Owners Users Group and individual nuclear plant operators. Updates roles of NERC, FERC, NRC and PJM. Minor edits throughout.

PJM Contact: David Schweizer, manager, generation

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Manual Change: Training and Certification (M40)

The following PJM manual change was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 40: Training and Certification Requirements – verification of operators performing reliability functions

Reason for Change: FERC Order 742 (issued Nov. 18, 2010) ratified NERC Reliability Standard PER 005 (System Personnel Training) to ensure the qualifications of system operators performing real-time, reliability-related tasks. Most requirements are effective April 1, 2013.

Impact: The changes require that all applicable operators be verified on the reliability-related tasks assigned to them (both common terminal tasks and company-specific functions) before the operator assumes independent shift duties. Creates a Systematic Approach to Training (SAT), as developed by the Dispatcher Training Subcommittee.

  • Operators must be re-verified on any modified tasks within six months of the modifications. Verification may include direct observation in a real-time or simulated environment or completion of relevant training and certification and verbal questioning.
  • All task verifications must be entered into a new Task Tracking Module of the PJM Learning Management System (LMS).
  • The one-year grace period for completion of Initial Training Program was eliminated for TO operators. (A similar provision for certification had already been removed to comply with NERC requirements.) A new initial training program is being created (using SAT). The course can be completed either online or in person.

PJM Contacts: Glen D. Boyle, manager, system operator training; Michael J. Sitarchyk, manager, state and member training.

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MRC OKs Changes to System Restoration Plan

On Feb. 28, the MRC endorsed changes to PJM’s system restoration procedures and methods for selecting black start units.

Reason for changes: The MRC acted in response to anticipated changes in PJM’s roster of black start units, Environmental Protection Agency regulations and a desire to increase cross-zonal coordination. Plant retirements are expected to eliminate one-third of PJM’s black start capacity by the end of 2015. The retirements are being driven by EPA mercury and air toxics (MATS) regulations and New Jersey’s High Electric Demand Day (HEDD) rules. The cost of complying with these environmental rules has undermined the economics of coal-fired generation  at a time of cheap natural gas.

PJM, the Market Monitor and stakeholders in the System Restoration Strategy Senior Task Force agreed on this unified proposal.

Impact: There are several major changes:

  • The critical load definition is changed  to include all generation that can start within four hours. The previous definition was limited to “critical steam units with a hot start time of 8 hours or less.” This will increase the capacity targeted for use of cranking power by 70,000 MW.
  • Potential black start units will be defined as those able to respond within three hours (up from the current 90 minutes), adding 64,000 MW of black start capability. About 2,000 MW of this total could act as black start units without plant modifications.
  • Black start units in one zone will be allowed to help restart generation in neighboring zones, allowing more efficient use of existing resources.
  • PJM will issue an RFP for black start generation every five years (see Manual 14D, Section 10: Black Start Generation Procurement). Minimum length of commitment will remain two years (or longer based on capital recovery time).

The proposal did not include changes in compensation for black start units or allocation of costs across zones, which will require OATT revisions and FERC approval.  A FERC filing is expected in the second quarter of 2013. The five-year request for proposals is expected to be issued in the third quarter, with contracts effective in April 2015.

The proposal was approved with no objections and three abstentions. It includes:

  • Manual 12: Balancing Operations – Section 4.6: Wording edits.  Deleted Section 4.6.8 and 4.6.9 due to elimination of 3 BS unit per plant restriction
  • Manual 14D: Generator Operational Requirements: Addition of five-year selection process
  • Manual 27: Open Access Transmission Tariff Accounting: Updated Section 7 to reflect cost allocation changes and TO Revenue requirements for cranking paths
  • Manual 36: System Restoration:
    • Minor updates to sections 6.2, Cranking Power and 8.1.1 Ascertaining System Status.
    • Created new section 9 on Cross Zonal Coordination.
    • Major edits to Attachment A to reflect changes in critical load, Black Start requirements and the reliability backstop process.
    • Minor changes to Attachment D – Drill Guide

PJM Contact: Chantal Hendrzak

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Demand Response Changes: Baseline Measurements, Information Requirements, Duplicate Registrations

On Feb. 28, the MRC endorsed demand response proposals concerning emergency measurement, information requirements for Curtailment Service Providers (CSP) and procedures for resolving duplicate registrations. The changes were proposed by the Demand Response Subcommittee.

Emergency Measurement and Verification

Reason for change: A study by Kema Energy Consultants found that that the economic method of determining Customer Base Line (CBL) is more accurate than the emergency method. Energy settlement rules were unclear for overlaps between economic and emergency events for the same DR resource. Economic CBL rule included emergency event days in CBL day selection process.

Impact:

  • If a CSP is listed as an economic registration, economic CBL will be used to determine load reduction; otherwise the existing hour before method will be used. (OATT, OA: Emergency Load Response Program changes; Manual 11, section 10.4 changes)
  • Clarify that demand resource dispatched for both economics and emergency conditions will be settled based on emergency energy settlement rules. (OATT, OA: Emergency Load Response Program changes; Manual 11, section 10.4 changes)
  • Selection of Economic CBL days will exclude emergency event days. (OATT, OA: 10.3A.2 changes)

Increased Information Requirements for Curtailment Service Providers

Expands and clarifies information reporting requirements for Curtailment Service Providers on the source of DR capability, business segment and on-site generation attributes.

Reason for change: PJM said reporting requirements were not adequately documented and information was sometimes incomplete.

Impact:

  • Clarify requirements in Manual 11, section 10.2.2
  • Eliminate use of “Other” category to ensure reasonable information is provided
  • Expand on-site generation attributes to include: Generator vintage, retrofit nameplate rating, permit status and permit type.

Most CSPs have already provided updated data.

Resolving Duplicate Registrations

Changes the resolution process used when different Curtailment Service Providers register the same end use customer.

Reason for change: Two CSPs sometimes attempt to register the same end-use customer, potentially creating double payment for the same service.

Impact: When two CSPs claim an end-use customer, both will be given five business days to contact the customer to affirm the customer’s selection and notify PJM that they have a valid contract. If only one CSP affirms they have a valid contract that registration will proceed. The registration will be terminated if neither CSP affirms they have a valid contract or both CSPs continue to claim the customer. Changes to Manual 11, section 10.2.

PJM Contact: Pete Langbein

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Capacity Market: Three-year Price Guarantee for New Capacity

The Members Committee and MRC approved changes on Feb. 28 to provide new capacity resources with a mechanism to avoid clearing the capacity auction for one year if they require multi-year price assurance to be a viable project.

Reason for change: New capacity resources currently are guaranteed only one year’s price guarantee – known as New Entry Price Adjustment (NEPA).

Impact: The Members Committee and MRC approved changing two sentences in the Tariff.

New capacity resources seeking the three-year price guarantee must declare their intentions when bidding in the first year and specify whether their offers are contingent upon qualifying for the price adjustment.  Such sell offers will not clear the auction if they don’t qualify for NEPA treatment.

Part of a bigger package of changes being developed by the Capacity Senior Task Force, this change will take effect in time for the May capacity auction. The task force will consider whether additional changes are needed after reviewing results of the May auction.

PJM Contact: Sarah Burlew