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November 15, 2024

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PJM Urges Action on Simple Stability Fixes to RTEP

Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal given first reading at the Markets and Reliability Committee meeting Thursday.

PJM will ask MRC at its next meeting to endorse Tariff revisions allowing the RTO to add “easily resolved constraints” to the RTEP.

Before posting the planning parameters for each Base Residual Auction, PJM staff would be required to identify Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective. Upgrades that raise the ratio above 115% would be added to the RTEP if they:

  • Cost less than $5 million;
  • Can be completed within 36 months or prior to June 1 of the Delivery Year; and
  • Does not duplicate customer-funded upgrades already in the transmission queue (e.g., one whose cost is assigned to an interconnection customer).

The proposal was approved easily in a vote by the Capacity Senior Task Force.

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Triennial Cost of New Entry (CONE) Review

MRC members heard first reading on a problem statement to review potential changes to the Cost of New Entry (CONE) triennial review process. CONE values are used in PJM’s Reliability Price Model (RPM) to obtain capacity resources.

Reason for problem statement: PJM and members agreed to explore changes in the review process in a settlement approved by the Federal Energy Regulatory Commission in January (Docket No. ER12-513).

Impact of problem statement:  The inquiry will assess the use of the Handy-Whitman Index of public utility construction costs for adjusting CONE and other potential changes.

PJM is required to file Tariff changes with FERC in time for the 2014 triennial review or a status report if stakeholders are unable to reach consensus on changes.

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PJM, NYISO Tout New Option to Improve Power Scheduling

PJM members will be asked tomorrow to approve a new scheduling option for transactions into the New York ISO to reduce uneconomic power flows.

Under the current system, PJM’s Stan Williams told the Markets and Reliability Committee Thursday, power often flows from PJM into New York even when PJM’s prices are higher.

To improve the alignment of energy scheduling with interface prices, PJM and NYISO are proposing creation of an additional product that would allow participants to submit “price differential” bids that would clear when prices in New York exceed those in PJM above a threshold set by the bidder.

The Coordinated Transaction Scheduling (CTS) proposal will be brought to a vote at the next MRC meeting if it is approved at tomorrow’s Market Implementation Committee meeting.

PJM says the new product should increase forward price transparency and price convergence between PJM and NYISO.

A cost benefit analysis found that the change would have reduced total production costs in the two RTOs by as much as $26 million in 2012. PJM officials said they had not calculated how much the savings would have been reduced by generator make whole payments resulting from the change.

The biggest opportunities for savings will come when the price differential between the two RTOs is relatively low. Analysis showed prices could be reduced in about half the hours when the price difference is $5/MWh but only 13% of the hours when the difference is $15.

CTS Interface bids would be scheduled based on the projected price difference between PJM and NYISO at the interface. It would use PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application, which has a two hour look-ahead capability.

The application correctly predicted prices about 60% of the time when the price differential is $5 or less. Williams acknowledged the tool was much less reliable when the price differential is higher. Williams said PJM plans to begin posting the forecasts publicly next spring and is attempting to improve its accuracy.

Bob O’Connell, vice president and compliance manager for J.P. Morgan Ventures Energy Corp., said members shouldn’t vote on the proposal until they have evaluated the risks of relying on the forecasting tool.

He also said the changes could increase balancing congestion, which would penalize Financial Transmission Rights holders. “FTR holders get no benefit from CTS,” he said.

Williams said the changes shouldn’t hurt FTR holders and should reduce price volatility.

CTS Interface Bids would have as many as four bid curves and up to 11 $/MW pairs. The option would be in addition to current hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers.

Credit requirements on the new scheduling option would be based on the higher of the 97th percentile historical (prior year) hourly price for the node or the 15-minute IT SCED price forecast for the node.

The issue has been under discussion with NYISO since November 2012. The new scheduling product would require approval of the Federal Energy Regulatory Commission.

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Maryland County to Challenge PEPCO Rate Hike

Isiah Leggett, chief executive of Montgomery County, MD, said last week the county will appeal the Maryland Public Service Commission’s decision awarding Potomac Electric Power Co. (Pepco) a $28 million increase in distribution rates and a $24 million surcharge to accelerate the hardening of feeder lines.

Leggett said that the PSC’s decision to approve the surcharge was “premature.”

“I believe that Pepco has made improvements in their communications, infrastructure, and emergency response systems since last summer’s ‘Derecho’ storm. However, just how improved these changes are have not yet been seriously tested,” Leggett told The Washington Post.

Leggett, who is seeking his third term as county executive, will face off against his predecessor, Douglas Duncan, and County Councilman Phil Andrews in next June’s Democratic primary.

Andrews has criticized Leggett for a series of tax hikes, including a 2010 increase in the county’s energy tax that increased household electric bills by about $139 annually.

The surcharge and base rate increase approved by the PSC will boost average residential bills by about $26 per year. (See MD OKs $28 Million Base Rate Boost for PEPCO.)

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New Rules for Wind Lost Opportunity Costs

Wind farms that fail to follow PJM’s electronic dispatch signals will no longer receive lost opportunity cost payments under a tariff amendment approved by the MRC.

Reason for change: Some wind generators are not following their economic basepoint, requiring PJM to issue manual dispatch instructions. This delays generators’ responses, causing less efficient market operations and a potential risk to system reliability, PJM says.

PJM proposed the new language as a Tariff change in response to a May 29 Federal Energy Regulatory Commission order that rejected its earlier proposal to incorporate the new rules in the Operating Agreement. The commission said the OA language “failed to provide any detail or tariff language describing the specific circumstances under which compensation would be reduced or how the compensation would be reduced.”

Impact: Would add language to section 3.2.3 of Tariff Schedule 1 to deny lost opportunity credits to pool-scheduled or self-scheduled wind generators that fail to follow PJM dispatchers’ electronic instructions to reduce output. (See PJM to Tighten Penalties on Wayward Wind.)

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Manual Changes: 1, 12, 19, 20

The Markets and Reliability Committee approved the following manual changes Thursday.

Manual 1: Control Center and Data Exchange Requirements

Reason for change: New rules for access to PJM Energy Management System (EMS).

Impacts:

  • Added new section 2.5.7 detailing rules for transmission owner read-only access to PJM’s EMS. No screen scraping is allowed;
  • Modified section 3.2.3 to clarify procedures for data communication outages;
  • Modified section 4.2.4 to clarify repeating of All Call messages;
  • Adds details to Information Access Matrix in Attachment A.

Manual 12: Balancing Operations

Reason for change: PJM is changing the regulation requirement to align it with operational needs and address volatility in light load periods.

Impacts:

  • Changes On-peak (05:00-23:59) requirement to 700 effective MW, a decrease in the requirement for 52% of days, an increase for 48% of days. Net daily decrease of about 60 MW (section 4.4.3).
  • Changes Off-peak (00:00-04:59) requirement to 525 effective MW, an increase for 66% of days and a decrease for 34% of days. Net daily increase of about 20 MW (section 4.4.3).
  • Changes regulation scoring methods:
    • Performance scoring for small regulation allocation: Historical performance scores will be used if the control signal has an average absolute value less than 1% of the regulation assignment (section 4.5.6);
    • Performance scores when data is not available: Historical performance scores will be used if data is not available and for intervals less than 15 contiguous minutes (adds section 4.5.9);
    • Regulation Assignments: Scoring will be suspended for 10 minutes after assignment to allow time to ramp into position (adds section 4.5.10).

PJM contact: Rus Ogborn

Manual 19: Load Forecasting and Analysis.

Reason for changes: Integration of East Kentucky Power Cooperative (EKPC), addition of annual demand resources and need to ensure accuracy of load shed programs.

Impacts:

  • Adds EKPC to load forecast model;
  • Revises assumption for winter load management;
  • Makes minor typo fixes and clarifications for NERC audits;
  • Changes demand resources available in winter months due to addition of annual DR product;
  • Codifies guidelines for switch operability studies for load management programs. The guidelines are designed to ensure the accuracy of load shed estimates for participants in direct load control programs. The study must be designed for a minimum 90% confidence level and based on a randomly selected sample from the entire population of participating customers. No customers can be excluded.

PJM contact: John Reynolds

Manual 20: PJM Resource Adequacy Analysis

Reason for change: Codifying procedure approved by FERC. The changes were endorsed by the Planning Committee in October 2012.

Impact: Revises section 5 to add Test 2 for the six-hour duration requirement for the Limited DR Product.  The Test 2 procedure is effective with the 2016/17 Delivery Year.

PJM contact: Tom Falin

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New Process for Exceptions to Generator Parameters

PJM would add new processes for generators seeking exemptions from operating parameters under changes presented to the Markets and Reliability Committee Thursday.

PJM’s generation parameters set defaults for different types and sizes of generators. The parameters cover minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min).

They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.

The proposed change, the result of a year-long effort between PJM and the Market Monitor, would create three types of exemptions:

  • Temporary Exception: A one-time exception of 30 days or less.
  • Period Exception: An exception lasting for at least 31 days but no more than one year during the 12 months between June 1 and May 31.
  • Persistent Exception: An exception lasting for at least one year.

MRC will be asked to approve the changes at its next meeting.

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Ridge to Headline 20/20 Forum on Grid Resiliency

Former Homeland Security Secretary and Pennsylvania Gov. Tom Ridge will be the keynote speaker at PJM’s Grid 20/20 forum Nov. 11 and 12 in Philadelphia.

The forum, which will take place at the Sheraton Society Hill, will focus on the electric power grid’s ability to withstand extreme weather challenges and cyber attacks.

The forum will cover the ability of the grid to withstand shocks during a physical or cybersecurity event, communication best practices, and the role of policy and investment.

PJM contacts: Erin Sechrist (sechre@pjm.com) and Sarah Burlew (burles@pjm.com).

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Earlier Deadline for Plant Retirement Notices Approved

A modified proposal to set earlier deadlines for power plants seeking exemptions from participation in PJM’s capacity market auctions won approval from the Markets and Reliability and Members committees Thursday.

The current rules require 120 days’ notice before the opening of the auction.

Stu Bresler, PJM vice president of market operations, said that’s not enough time for PJM to analyze the impact of plant retirements on system operations and determine whether the RTO needs transmission upgrades to ensure reliability.

Andy Ott, executive vice president for markets, said the changes also will give market participants more information in advance of the auctions.

The change will require generators seeking exemption from the “must-offer” requirement to file notice by Sept. 1 for the annual base residual auction (BRA) and 120 days before incremental auctions. The exemptions apply to generators that will be unable to provide capacity because they plan to retire.

At July’s MRC meeting, generators said the policy change could cause staffing problems and financial burdens at generators that will be forced to announce retirements earlier. (Generators Balk as PJM Seeks Earlier Notice on Plant Retirements.)

In response, PJM and the Market Monitor changed the proposal to provide generators more flexibility and to mask the identities of individual power plants:

  • Retirement requests must be made by September 1 but can be based on a conditional deactivation analysis. The submission would specify the conditions that are creating uncertainty, such as pending negotiations on fuel or labor contracts. The finalized deactivation plan would be required by December 1 unless the request is withdrawn.
  • PJM will post information on pending plant retirements in the first week of September but will do so using zonal aggregation rather than identifying individual generators. For each transmission zone, PJM will specify the amount of capacity scheduled to retire within one of the following ranges:
    • Less than 100 MW
    • 100 MW to 500 MW
    • 500 MW to 1000 MW
    • Total capacity to be retired will be specified if a zonal total exceeds 1,000 MW.

The revised proposal was approved by a 4.11-0.89 sector-weighted vote in the MRC, with support from six generators. Five generators voted no and three abstained. The Members Committee approved it 4.35-0.65.

John Horstmann, director of RTO affairs for Dayton Power & Light Co., supported the modified proposal, saying the changes made the proposal “a lot less onerous” for generation owner. But he said the earlier deadlines don’t apply to about 20,000 MW of demand response, energy efficiency and imported generation capacity, giving them a competitive advantage. “It’s a free option,” he said.

“We’re aware of that,” Bresler responded, saying PJM would consider the issue in the future.

Neal Fitch, representing NRG Energy, also praised PJM’s revisions to the proposal but said it was still an “overcorrection.”

Susan Bruce, representing the PJM Industrial Customer Coalition, spoke in support. “It’s an important step to help the market operate efficiently,” she said.

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VA OKs Dominion Virginia Power Generator

Virginia regulators last week approved Dominion Virginia Power’s request to build a 1,358 MW natural gas-fired generator near Lawrenceville in Brunswick County.

Dominion said it plans to start construction immediately on the $1.3 billion combined cycle plant, which is expected to go into commercial operation in the summer of 2016.

The Virginia State Corporation Commission approved a Certificate of Public Convenience and Necessity for the project and a rate adjustment clause to recover construction costs. The commission also approved the construction of a 13.5-mile 500 kv transmission line to connect the generator to the grid.

The rate rider will generate $43.5 million in its first year, increasing the monthly bill of a residential customer using 1,000 kilowatt-hours of electricity by 81 cents.

Dominion said the plant, which is being added to serve load growth and replace retiring coal plants, will save $96 million in fuel costs in its first full year of operation.