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December 5, 2025

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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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Atlantic City Electric Wins $25 Million Base Rate Hike

New Jersey regulators approved a $25.5 million annual increase in Atlantic City Electric Co.’s base distribution rates and recovery of $70 million costs for recovery following the June 2012 Derecho and Hurricane Sandy in October 2012.

Capital costs of $44.2 million were included in the rate base while deferred operation and maintenance expenses of $25.8 million will be amortized over three years.

The New Jersey Board of Public Utilities announced its approval of a settlement signed by the utility, the Division of Rate Counsel and intervenors including Wal-Mart Stores, Inc. on June 21.

The company’s $25.5 million base rate increase, which excludes sales and use tax, is based on a return on equity of 9.75%. The new rates will cost residential customers using 1,000 KWh per month $4.44, a 2.8% increase. The changes took effect July 1.

The company, a subsidiary of Pepco Holdings, Inc. (PHI), had sought a base rate hike of almost $70 million. Because of the lower increase, the company said it will reduce its capital expenditures by about $150 million through 2015, a cut of 30%.

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NJ Legislature Boosts Offshore Wind Transmission Project

The New Jersey legislature voted last week to urge state utility regulators to support development of an offshore transmission “backbone” to deliver wind power and relieve transmission congestion.

The Senate approved a resolution supporting the New Jersey Energy Link (SCR 159) 24-12 on Thursday, after an identical measure (ACR 197) passed the Assembly 58-18 on June 24.

The resolution asks the state Board of Public Utilities (BPU) to request that PJM include the project in its Regional Transmission Expansion Plan (RTEP) with an assumed capacity of 1,000 to 3,000 MW.

Map of Proposed New Jersey Energy Link (Source: Atlantic Wind Connection)
Map of Proposed New Jersey Energy Link (Source: Atlantic Wind Connection)

The measure outlines a four-stage process leading to commencement of construction in 2016 and urges BPU to sign a contract allowing the project developer, Atlantic Grid Development, LLC, to recover future development costs from ratepayers. The Federal Energy Regulatory Commission would be asked to modify a 2011 order so that ratepayers are not liable for any costs incurred before June 28 if the project is abandoned for reasons beyond the developers’ control.

The resolution also calls for a study by the New Jersey Economic Development Authority of the “economic activity, tax revenue growth, job creation [and] pollution reduction.”

The New Jersey Energy Link is the northernmost section of the Atlantic Wind Connection, which could transport wind from offshore turbines as far south as Virginia.

The developers say the project will create about 2,000 jobs, including 500 or more in the Delaware River port of Paulsboro, where they plan to build offshore converter platforms.

Atlantic Grid said four wind developers — Apex Wind Energy, EDF Renewable Energy, Fishermen’s Energy and OffshoreMW, LLC – have endorsed the project as the most efficient means to deliver the state’s offshore wind.

The developers say the undersea transmission also will help relieve transmission congestion when the wind isn’t blowing, allowing North Jersey to access cheaper power.

Atlantic Grid CEO Bob Mitchell has said approval of the legislation is “crucial” to getting the project built.

Stefanie Brand, director of the New Jersey Division of Rate Counsel, could not be reached for comment yesterday. She said previously that the line should not be considered until there is offshore generation for it to service, saying there are likely cheaper solutions to North Jersey’s transmission congestion. A BPU spokesman did not immediately reply to requests for comment yesterday.

New Jersey lawmakers approved legislation in 2010 committing the state to purchase 1,100 MW of offshore wind by 2020. But the only project proposed to date, a 25-MW pilot off Atlantic City, has been unable to win approval from state ratemakers to date.

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Who is Ron Binz, And What Will He Do at FERC?

Ron Binz - Consultant & FERC Nominee (Source - Public Policy Consulting)
Ron Binz – Consultant & FERC Nominee (Source – Public Policy Consulting)

President Obama last week tapped former Colorado utility regulator Ron Binz to replace outgoing FERC Chairman Jon Wellinghoff.

Who is he? A Democrat, Binz served as chairman of the Colorado Public Utilities Commission from 2007 through 2011, during which he drew praise from renewable energy advocates, opposition from the coal industry and criticism for his travel practices. He joined the PUC after serving as head of the state Office of Consumer Counsel from 1984 to 1995.

What is he likely to do at FERC?

Here are some clues: In a 2012 article he co-wrote for an electricity policy journal, Binz called for a new regulatory compact, saying that current utility regulation is “cumbersome … overly judicial and confrontational.” As a result, he wrote, it “provides limited motivation for utilities to innovate, diversify to manage risks, or undertake new efficiencies.”

The electric utility industry, he said, is in the midst of “what may be the most uncertain, complex and risky period in its history” due to large investment needs, stricter environmental controls, decarbonization, changing energy economics, new technologies and reduced load growth.

Will he face trouble winning Senate confirmation? He shouldn’t count on the votes of coal-state senators. But his support from industry and even some Colorado Republicans suggest he’ll survive, barring some unforeseen revelations. One potential snag: Obama has appointed him to not only join the commission but to immediately become chairman, a departure from past practice.

Dual Role

As is the case at FERC, the Colorado PUC served both a judicial and policy-making role. Binz saw the PUC’s role as “not simply as an umpire calling balls and strikes, but also as a leader on policy implementation” he said in an interview with a demand response group.

In that role, Binz participated in the drafting of Colorado’s Clean Air-Clean Jobs Act which offered utilities incentives for replacing coal-fired power plants with natural gas. Binz later rejected requests that he recuse himself from PUC cases implementing the law.

The bill, which was opposed by both the coal industry and independent power producers, led to the retirement of six coal-fired generators, the addition of pollution controls at two others and the construction of new gas generation at a cost of about $1 billion, according to the Denver Post.

Frequent Flyer

Binz also generated controversy for his frequent travel, spending 200 days at conferences during his tenure. In an apparent reference to Binz, a report by the state auditor said one unnamed commissioner was traveling so often that it was “difficult for division staff to meet with him and ensure his preparedness for meetings and hearings.”

In 2011, the Colorado Independent Ethics Commission found he had violated state travel policy by accepting free travel to speak at an industry conference in Houston. The panel declined to fine him, however, saying he did not personally benefit.

Binz was unapologetic about his travel, telling an interviewer that utility regulators and staffs “need much greater access to educational resources: publications, conferences [and] seminars” to prepare for emerging issues and not be “only reactive.”

Since leaving the PUC, Binz has worked with a Colorado renewable energy institute and run a consulting firm with clients including homebuilders, trade associations and environmental and consumer groups.

Industry Reaction

Binz’ nomination won praise from executives at Public Service Enterprise Group Inc., NextEra Energy Inc., Xcel Energy Inc. and the American Wind Energy Association.

NextEra CEO Jim Robo called Binz “a superb choice,” saying he “recognizes the need for diversity in the U.S. electricity supply and understands our country needs smart policies to modernize the grid to match up with today’s changing energy mix.”

Public Service Enterprise Group Chairman Ralph Izzo called Binz “a strong and timely choice.

“In Colorado, he showed a willingness to work with diverse groups and elected officials of both parties to develop and implement commonsense legislation,” Izzo said.

Previous FERC Chairmen (Source FERC)
(Source FERC)

He also received an endorsement from former Colorado House Speaker Lola Spradley, a Republican, who said his “expertise and leadership proved critical to advance a balanced approach in Colorado.”

Alaska Sen. Lisa Murkowski, ranking Republican on the Energy and Natural Resources Committee, issued a statement that was noncommittal on Binz’ qualifications but skeptical of Obama’s plan to elevate him immediately to chairman.

Murkowski said she “strongly believes that each of the commissioners, and especially the chair, must have and maintain a judicial temperament and must demonstrate a record for balance and a scrupulous regard for the law and the rules. It is noteworthy that in recent decades it has been rare to elevate the newest member of the commission directly to chairman. Under the law, FERC’s chair is responsible for setting the agenda and managing the agency.”

The last five chairmen served a median of 30 months before becoming chair. Only one, Patrick H. Wood III, served less than a year on the panel before his promotion.

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MRC Approves New Benefit Test for Market Efficiency Projects

The Markets and Reliability Committee Thursday approved changes to the way PJM determines beneficiaries of market efficiency transmission projects.

MRC also changed the way PJM planners add generation in market efficiency simulations and revised the definition of production costs to include cross border purchases and sales.

The changes, which were approved without opposition, were developed by the Regional Planning Process Task Force to align modeling and beneficiary determinations with the revised cost allocation formula approved by the Federal Energy Regulatory Commission in PJM’s Order 1000 compliance filing.

PJM uses an hourly unit commitment dispatch simulation to measure savings in production costs and load payments over 15 years.

Under the change approved by MRC (Package 10), benefits of regional projects will be calculated on a 50/50 ratio based on its impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity pay­ments (capacity benefits). (See chart)

Benefits of local, low-voltage projects will be determined entirely on the change in net load or capacity payments for zones that experience decreases.

Under the previous method for both regional and local projects, 70% of benefits were calculated based on production or capacity cost savings, with the remainder based on change in net load or capacity payments.

Generation Expansion

MRC also changed the way PJM adds generation in market efficiency simulations. Comparing forecasted load against forecasted generation typically results in a shortfall in the Installed Reserve Margin (IRM) in the later years of the 15-year horizon.

Under current procedures, PJM scales existing generation units to assume supply will grow to meet the forecasted IRM. Active generation queue projects that are not part of the unit specific plan — existing PJM units as well as units that have an executed Interconnection Service Agreement (ISA) — can impact the location and type of generation scaled.

Under the new procedure, PJM planners will include all generation projects with executed ISAs or Facility Study Agreements (FSA). Existing units will be scaled based on location and technology to meet the reserve requirement. Planners also will include transmission upgrades for congestion that arise from scaling assumptions.

Cost Allocation and Benefit Determination - Market Efficiency Projects in PJM
Cost Allocation and Benefit Determination – Market Efficiency Projects in PJM

Production Cost Definition

The current definition of production costs limits market efficiency simulations to purchases and sales within PJM, ignoring cross-border transactions.

Under the new definition, PJM will include costs for purchases from selected regions and lines outside PJM as well as sales outside PJM. Purchases will be valued at the load weighted LMP and sales will be valued at the generation weighted LMP.

If given final approval by the Members Committee, the changes will be effective in the 24-month market efficiency cycle beginning in January 2014.

PJM contact: Fran Barrett

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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.