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December 7, 2025

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Manual Changes: Manual 1, 12, 21, 28

The Operating Committee last week approved changes to manuals 1 and 12, while the Planning Committee received a presentation on proposed changes to Manual 21 and the Market Implementation Committee heard a first reading on changes to Manual 28.

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.

Next Step: Vote by Markets and Reliability Committee.

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).

Next Step: Vote by Markets and Reliability Committee.

PJM contact: Rus Ogborn

Manual 21: Rules and Procedures for Determination of Generating Capability

Reason for change: Clarifying ambiguous language, updating terms.

Impacts:

  • Clarifies that intermittent resources (wind, solar) are not required to perform seasonal verification tests because their capacity credit calculation is used in place of a ratings test.
  • Clarifies that all generators, except hydro, pumped storage and diesel units, are required to adjust rating test results for expected cooling water and ambient air conditions.
  • Hydro and pumped storage units must perform their annual ratings test during the summer verification window and are not required to perform a winter test.

Next Step: Vote at next Planning Committee meeting.

PJM contact: Tom Falin

Manual 28: Operating Agreement Accounting

Reason for change: Incorporating changes to lost opportunity cost compensation as approved by FERC.

Impacts:

  • Changes sections 5.2.6 and 5.2.8 (Operating Reserve & Reactive Services Lost Opportunity Cost Credits) to limit lost opportunity cost compensation to the lesser of a unit’s economic maximum or maximum facility output as approved in FERC Docket ER13-1200.
  • Section 7.2  (Shortage Pricing) amended to incorporate calculation details for non-synchronized reserve market lost opportunity costs.
  • Modifies section 5.3 (Operating Reserve) to correct errors and provide clarifications on exempting deviations during shortage conditions and revisions for associating interfaces to the East or West BOR regions.
  • Modifies sections: 5.2.3 to incorporate details of Lost Opportunity Cost Credit for Synchronous Condensing; 5.2.6 (Wind Lost Opportunity Cost) to align language with Tariff; 17.3 (Allocation of Annual and Monthly FTR Auction Revenues) to correct section reference.

Next Step: Vote at next MIC meeting.

PJM contact: Suzanne Coyne

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Reliability Projects in 2013 RTEP Likely to Exceed $1B

PJM transmission planners have identified more than $800 million in reliability upgrades for inclusion in the Regional Transmission Expansion Plan (RTEP), officials told members last week. Costs are likely to exceed $1 billion once all projects are tallied.

The upgrades, outlined to the Transmission Expansion Advisory Committee Thursday, include 26 projects to address high voltage problems, 10 to fix load deliverability problems and four areas with short circuit problems.

Short Circuit Upgrades

The biggest single reliability project is likely to be one addressing the short circuit problem in the PSE&G transmission zone outside New York City.

The 2012 PJM RTEP identified several buses in the PSEG zone where the fault currents exceed 80 kA. Potential solutions include upgrading stations to 90 kA and installing current limiting reactors.

Another possible solution being reviewed by PJM is to isolate the Hudson 230 kV from the 138 kV at Marion and 345 kV at Farragut. The 138 kV buses and transmission facilities on the path from Linden to Bergen would be converted to double circuit 230 kV or 345 kV lines. The 345 kV proposal is estimated to cost $1.1 billion but eliminates the need for $588 million of approved RTEP projects, resulting in a net cost of $515 million.

Also under consideration is a proposal to build parallel 700 MW high voltage DC converter stations, estimated at $800 million to $1.1 billion.

One member said PJM should open a proposal window to solve the issue. But PJM officials said they were unlikely to do so — meaning PSEG would have the right to construct the solution — because of the urgency of the problem.

“We will be hard pressed to get any solution by 2015,” said Paul McGlynn, general manager of system planning. “It doesn’t really lend itself to a proposal window.”

“The board has been concerned that this [problem] has been hanging on for quite a while,” added Steve Herling, PJM vice president for planning.

PJM staff is refining its cost analyses and performing additional load flow analyses. Any solution will have to accommodate PJM’s contract with NYISO for the so-called Consolidated Edison “wheel.” The wheel funnels 1000 MW from NYISO through PSEG and into New York City.

In addition to the PSEG short circuit project planners also identified “overstressed” circuit breakers in the Duke Energy Ohio and Kentucky (cost to be determined), Duquesne Light (cost TBD) and Jersey Central Power and Light Co. transmission areas (estimated cost $360,000).

High Voltage

Location of High Voltage Problems Identified by PJM (Source: PJM Interconnection, LLC; p. 11, RTEP Reliability Analysis, TEAC 7-10-13)
Location of High Voltage Problems Identified by PJM (Source: PJM Interconnection, LLC; p. 11, RTEP Reliability Analysis, TEAC 7-10-13)

PSEG also figures prominently in upgrades to fix high voltage problems, with 13 projects with a total cost of $122 million. AEP had five projects totaling $17 million while AEC had two projects totaling almost $30 million. PEPCO, PPL, Jersey Central Power and Light, Allegheny Power System and PECO had upgrades ranging from $16 million to $4 million.

PJM’s Board of Managers will be asked to approve the high voltage projects in October, PJM officials said.

Load Deliverability

Twenty-five of 27 Locational Deliverability Areas (LDAs) passed the load deliverability test with no thermal or voltage issues while voltage violations were identified in the Penelec transmission zone resulting from the Penelec and Western MAAC load deliverability tests.

Planners identified 10 projects to solve the problems. One in PPL is estimated at $84.5 million and another in Atlantic City Electric Co. at $11.2 million. Costs of the remaining projects, one in Delmarva Power and Light and seven in PEPCO, have not been estimated. 

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PJM OASIS Adds Temporary Transmission Ratings Info

Responding to marketers’ requests, PJM has begun posting temporary ratings changes from all transmission owners on its OASIS System Information page.

PJM spokeswoman Paula DuPont-Kidd said the RTO began posting the information in response to frequent requests from members. PJM decided to make the information publically available because releasing it to individual companies would provide them a competitive advantage. “It’s mostly for marketers who use it for the day ahead and real-time markets,” she said.

Temporary rating changes are made throughout the day, most of them resulting from system conditions and having operational impacts. The expanded information included details to indicate the provisional status of requests. A list of reasons for ratings changes also was posted.

Beginning July 31, the postings will be updated at 11 a.m. and 1 p.m. daily.

PJM contact: Michael Zhang, PJM Operations Support

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Black Start RFP Open through Sept. 30

PJM began its first RTO-wide solicitation for black start service July 1, with proposals accepted through Sept. 30.

Respondents to the request for proposals (RFP) must be capable of: starting without an outside electrical supply; closing their output circuit breakers to a de-energized bus within three hours or less; maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.

Existing black start providers do not need to submit proposals.

The RFP is one of the recommendations of the System Restoration Strategy Task Force, which also increased the pool of potential resources through revisions to the definitions for black start units and critical load to be served by them.

PJM expects to lose some existing black start capacity by 2015 as a result of the planned retirements of coal-fired generators squeezed by EPA regulations and low natural gas prices.

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PJM, Monitoring Analytics Sign New Contract

PJM announced this morning that the Board of Managers has approved a new contract with Monitoring Analytics, PJM’s independent market monitor. The contract, which must be approved by the Federal Energy Regulatory Commission, runs through 2019.

The contract ends — for the time being, at least — the latest dust-up among PJM and its stakeholders over the independence of the market monitoring function.

In March, states, industrial consumers and cooperatives protested the board’s plan to issue a request for proposals for monitoring services. The stakeholders said the board’s proposed RFP contained language that would undermine the independence and quality of the monitoring function. They also expressed concern that PJM would suffer a loss of institutional knowledge if it replaced Monitoring Analytics, LLC, which has been operating as the Market Monitor under the terms of a 2008 FERC settlement (EL07-56).

The board responded in April by announcing it was negotiating a new contract with the company and dropping plans to put the contract out for bid.

On July 2, however, the Organization of PJM States, which represents state regulators, sent a letter to the board complaining that it had not been consulted in the drafting of the new contract.

“We are frankly baffled by an apparent reluctance on the part of the board to consult with OPSI on the new contract language prior to the execution of the contract,” wrote Maryland Public Service Commissioner Lawrence Brenner, chairman of OPSI’s market monitoring committee. “…As a procedural matter it is doubtful that FERC created the OPSI Advisory Committee if the only beneficiary of its advice was to be the commission itself.”

Brenner told RTO Insider today that OPSI received a copy of the 19-page contract after it was signed July 8. He said OPSI may work with PJM and the monitor to address its concerns in PJM’s filing seeking FERC approval of the contract.

“There are a couple areas where we’ve suggested that some clarification would be helpful,” he said. He declined to go into specifics, saying he was speaking for himself and not OPSI.

Asked what OPSI’s exclusion from the negotiations said about its relationship with PJM, Brenner said “I wouldn’t read too much into it. We have a pretty good relationship with the board.

PJM President and CEO Terry Boston said in a statement that “robust, independent monitoring services are essential to PJM’s ability to administer fair and efficient wholesale electricity markets.

“The competency, integrity and analytical capability of the Monitoring Analytics staff is well known and appreciated at PJM and we look forward to continuing to work productively with them for the benefit of the region we serve.”

Monitoring Analytics President Joseph Bowring also issued a statement, saying “We look forward to a productive relationship with the board, with PJM and with PJM members in the coming years.”

A Ph.D. economist, Bowring has served as PJM’s market monitor since 1999. At a FERC technical conference in 2007, Bowring accused then-PJM President Phil Harris and his allies of attempting to muzzle him by squelching his reports and cutting his budget. Following an investigation, Harris resigned and FERC approved a settlement in which Bowring formed Monitoring Analytics and was awarded a six-year contract. The contract was worth about $10 million per year.

Brenner said yesterday that OPSI will be looking closely at the new contract provisions that govern the balance between the monitor’s independence and the board’s right to provide oversight of its performance.

“Both the market monitor and PJM tell us that the negotiations were very respectful and not contentious,” Brenner said. “All those things are a change from some years ago.”

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Eight Companies Vie for Artificial Island Project

By Rich Heidorn Jr.

PJM’s first competitive transmission project under FERC Order 1000 attracted proposals from five utilities and three independent developers.

Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons
Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons

The proposals – to correct stability issues at Artificial Island, home of the Salem and Hope Creek nuclear plants, in Hancocks Bridge N.J. – ranged from a new 230 kV line and station (estimated cost $116 million) to two new 500 kV lines (a projected $1.5 billion price tag).

The Federal Energy Regulatory Commission’s Order 1000 eliminated incumbent utilities’ Right of First Refusal on construction and operation of new transmission projects, opening the business to competition from independent transmission developers.

The diversity of technical solutions and cost estimates submitted for the Artificial Island project appears to validate FERC’s prediction that competition could reduce costs and increase innovation in transmission development.

In all, 26 proposals were submitted, led by PSE&G with 14 alternatives. Transource Energy, a partnership between American Electric Power and Great Plains Energy (owner of Kansas City Power & Light Co.), submitted four proposals, while Virginia Electric and Power Co. submitted three and LS Power offered two. FirstEnergy Corp., Atlantic Wind Connection and a partnership between Pepco Holdings Inc. and Exelon Corp. each made a single proposal.

PJM planners will evaluate the proposals through analyses including thermal and short circuit studies.

Here is a summary of the proposals which were outlined to the Transmission Expansion Advisory Committee on Wednesday:

Atlantic Wind: Install a HVDC converter station near Artificial Island; Install a SVC at the new Artificial Island HVDC station; Install a HVDC converter station near the existing Cardiff 230 kV; Install a 320 kV HVDC facility from the Artificial Island HVDC station and the HVDC station near Cardiff 230 kV. Cost: $1.012 billion. 

FirstEnergy: Install a new, New Freedom – Smithburg 500 kV line with a loop into the Larrabee 500 kV; Install two new 500/230 transformers at Larrabee; Install a Hope Creek – Red Lion 500 kV line. Cost: $452.3 million (cost submitted does not cover entire project).

LS Power: Two proposals:

Least Expensive: Install a new Salem – Silver Run 230 kV line with a 500/230 kV transformer at Salem; Install a new 500/230 kV station that taps the existing Red Lion – Cedar Creek 230 kV and Red Lion – Cartanza 230 kV lines. Cost: $116 to $148 million.

Most Expensive: Install a new Salem – Red Lion 500 kV line. Cost $170 million.

PHI/Exelon: Install a new Peach Bottom – Keeney – Red Lion – Salem 500 kV line; Remove existing Keeney – Red Lion 230 kV circuit; Reconfigure the existing 230 kV line from Hay Road – Red Lion (23020) to terminate at Keeney instead of Red Lion;  Re-conductor the Harmony – Chapel Street 138 kV line.  Cost: $475 million.

PSE&G: 14 proposals.

Least expensive: Install a new New Freedom – Deans 500 kV line; Install a new Salem-Hope Creek 500 kV line. Cost: $692 million.

Most expensive: Install new New Freedom – Whitpain North 500 kV line; Install a new Salem-Hope Creek-Red Lion 500 kV line. Cost: $1.548 billion.

Transource: Four proposals.

Least expensive: Install a new Salem – Red Lion 500 kV line. Cost: $123 to $156 million.

Most expensive: Install a new New Freedom – Lumberton – North Smithburg 500 kV line with new 500/230 sub east of Lumberton. Cost: $788 to $994 million.

Virginia Electric and Power: Three proposals.

Least Expensive: Install a new 500 kV line from Salem 500 kV to a new station in Delaware; Install a new station in Delaware that taps the existing Red Lion – Cartanza 230 kV and Red Lion – Cedar Creek 230 kV lines. Cost: $126 million.

Most expensive: Install a new 500 kV line from Hope Creek 500 kV to a new station in Delaware; Install a new station in Delaware that taps the existing Red Lion – Cartanza 230 kV and Red Lion – Cedar Creek 230 kV lines;  Install a new Salem – Hope Creek 500 kV line. Cost: $202 million.

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Closed Doors: Liaison-Board Meeting Shut to Public, Press

There’s an important PJM meeting today — but you’ll have to listen in yourself if you want to know what happens.

The Liaison Committee’s irregular meeting with the Board of Managers will be held at 4 p.m. EDT today in Chicago.  The meeting is open only to PJM members and regulators. No public. No press.

“The members felt that they needed to have a forum where they could hold candid, informed and informal discussions with the Board,” committee secretary Dave Anders, manager of stakeholder affairs, explained in an email.

Anders noted that no decisions are made at these meetings, which are “simply opportunities for discussion.”

The fact that no decisions are made does not negate the import of these sessions, however. They are one of the few opportunities for members to observe and interact with the board: From 2009-2012, the Liaison Committee met an average of three times per year. And the four issues on today’s agenda have been the subjects of considerable controversy:

The Liaison Committee will make an oral report on the meeting with the board at the next Members Committee meeting, Aug. 1.

Click here for details on listening to the meeting (only Liaison Committee members are permitted to speak).

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Manual Changes: M11, M14D , M15

The Markets and Reliability Committee Thursday approved changes to Manuals 11 and 14D, while the Members Committee approved changes to Manual 15.

Manual 11: Energy & Ancillary Services

Reason for changes: Clarifications, error corrections and changes to conform to other manuals.

Impact:

The changes:

  • Clarify and add conforming language for regulation rules:
    • Resources cannot clear for both RegA and RegD within an operat­ing hour (Section 3.2.9)
    • Changes language to conform to M12. Regulation resources must return to their regulation range within 10 minutes of the end of a synchronized reserve event (Sec­tion 4.2.12). The current language calls for a return within two minutes.
  • Clarify hydropower units’ opportunity cost when providing synchronized reserve:
    • Hydro units providing Tier 2 synchronized reserve receive lost opportunity cost payments only when they are held to condense mode rather than off-line. (Sec­tion 4.2.7)
  • Corrects and clarifies Attachment C regarding cost offers and station manning:
    • Removes language stating that a resource can submit only five cost offers for energy. The actual limit is “in the 60s,” said Rus Ogborn of PJM.
    • Clarifies the compensation rules that apply when PJM requests generators be manned in order to start units more quickly. Units required to provide staffing will be compensated even if the resource is not called on because system conditions change.
  • Clarifies and cleans up revisions for Shortage Pricing rules. Changes were made to clarify existing rules and remove errors in the current text.

PJM contact:  Rus Ogborn

Manual 14D: Generation Operational Requirements

Reason for changes: Conforming to other manuals; revised NERC standard; updated information and addition of wind unit dispatchability checklist.

Impact:

  • Multiple sections revised to replace out­dated references.
  • Section 7.1.1, Generator Real-Power Control: Revised for consistency with M-36.
  • Section 7.1.3, Notification to PJM for Reactive Power Resource Status during Unit Start-up: revised to reflect changes in NERC Standard VAR-002-2b, R1, effective July 1.
  • Section 7.3, Critical Information and Reporting Requirements: Added references to PJM peak period maintenance season and changed notification time from 30 minutes to 20 minutes for consistency with section 7.4.
  • Section 7.4 Synchronization and Disconnection Procedures: Revised to include notification times for synchronizing and disconnecting generators from the system.
  • Section 8, Wind Farms Requirements: Revised to include references to Attachments L & M.
  • Attachment H, PJM Generation and Transmission Interconnection Planning Process Flow Diagram, revised for consistency with Manual M-14A/C.
  • Attachment M, Wind Unit Dispatch­ability Check List: New attachment.

PJM contact: Dave Schweizer

Manual 15: Cost Development

Reason for changes: Manual 15 was not revised to include information regarding cost-based offers when PJM made changes to the regulation market.

Impact: Information on cost-based offers is being moved into Manual 15 from Manual 11.

  • Section 2.8: Insert regulation cost offer component bucketing from M11 sub-section 3.2.1 and update regulation cost offer calculation example.
  • Section 11.8: Redefine energy storage losses.
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Exelon Tops Maryland Lobbying Spending

Exelon Corp. spent more than $400,000 lobbying the Maryland legislature between November 2012 and April 2013, making it the top spender in the state, according to recently-released data.

In all, utilities and other electric industry companies spent $1.25 million in lobbying over the six-month period. The companies spent $1.8 million in the year ending Oct. 31, 2012.

The companies’ lobbying reports do not specify what matters they were attempting to influence, with many citing only “energy matters.”

Maryland Lobbying by the Electric Industry - November 2012-April 2013 vs. November 2011-October 2012 (Source: Maryland State Ethics Commission)
Maryland Lobbying by the Electric Industry – November 2012-April 2013 vs. November 2011-October 2012 (Source: Maryland State Ethics Commission)

But legislative sources told RTO Insider the utilities spent much of their efforts lobbying to modify a bill offering subsidies to offshore wind power and fighting several bills that would add new safety standards on gas pipelines. They also opposed legislation that would have made wood and plant biomass eligible for inclusion in Maryland’s Renewable Energy Portfolio Standard.

After failing in two prior years, a less ambitious version of the offshore wind bill was approved. One gas pipeline bill, concerning implementation of federal pipeline safety laws, also was enacted. The biomass initiative became a task force study — the Maryland legislature’s consolation prize for bills lacking enough support to become law.

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FERC Approves Entergy—ITC Holdings Merger

The Federal Energy Regulatory Commission (FERC) approved the merger of Entergy Corp’s transmission system with ITC Holdings Corp. and its move into the Midcontinent Independent System Operator (MISO).

Entergy’s transmission assets in Louisiana, Mississippi, Arkansas and Texas will be transferred to ITC Holdings, which operates transmission in Michigan, Iowa, Illinois, Minnesota, Kansas and Oklahoma. FERC’s approval came in four orders issued June 20. In addition to ruling the merger is consistent with the public interest (EC12-145), the commission approved formula rates for the new ITC operating companies (ER12-2681) and agreements governing the move to MISO (ER-12-2682, ER12-2693).

Map of ITC-Entergy Transmission Territories (Source: ITC Holdings Corp.)
Map of ITC-Entergy Transmission Territories (Source: ITC Holdings Corp.)

The deal will give Entergy’s shareholders ownership of about 50.1% of ITC’s common stock. Entergy will continue ownership of its generation and distribution assets.

Commissioners Cheryl LaFleur and John Norris dissented in part, saying they opposed allowing ITC to use a 60% equity/40% debt capital structure for five years, which they said will cause a rate increase for Entergy customers. The commission should have required ITC to use the Entergy Operating Companies’ capital structure, which has a lower level of equity, they said.

The merger awaits approvals by state regulators in the Entergy operating region.