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July 22, 2024

SETTLEMENT: PJM Drops suit; PJM Insider Forced to Change Name

RTO Insider is an independent publication of RTO Insider LLC. It is neither connected with nor endorsed by PJM Interconnection, LLC. 

By Rich Heidorn Jr.

We hadn’t even published our first article when the cease and desist letter arrived via email in February.

PJM Interconnection, LLC was unhappy that we had registered the website PJMInsider.com. We have a trademark on those three letters, said PJM’s lawyers. No one else can use them.

We disagreed, and continue to disagree to this day about our legal right to use PJM to describe our coverage.

But last week, we signed a settlement agreement with PJM agreeing to change the name of our publication to RTO Insider — our corporate name — to avoid PJM’s threatened trademark infringement suit.

All of the lawyers we consulted told us we would likely prevail if the case went to court. Unfortunately, as a new publication — funded by savings, credit cards and sweat equity — we didn’t have the $60,000 we were told it would cost to contest PJM’s suit. So, sadly, we were forced to make a strategic retreat.

PJM officials will tell you their stance was solely motivated by their obligation to “protect” their trademark from infringement. While it is true that trademark holders can lose their rights if they do not defend them, it is also true that the media are treated differently under trademark law.

As much as we tried, we could never come up with a better title for our publication than PJM Insider. And we still haven’t come up with any other way to explain — in just a few short words — what we’re covering than to mention “PJM” in the title.

We had no intention of tricking readers into thinking we were connected with PJM Interconnection. Indeed, our value proposition from the beginning has been our independence — both from individual stakeholder groups and from PJM itself. We have lived up to our word by scrupulously including disclaimers on all of our publications and literature.

Our lawyer explained all this in a letter to PJM. He also explained why PJM’s legitimate intellectual property concerns do not allow it to censor the free press.  (See sidebar, Trademark Law and the News Media.)

We hoped PJM would be satisfied with that. We were wrong. On June 6, PJM emailed us a draft of the lawsuit they said they planned to file the next day.

As you will see below, the suit is both hilarious — because the claims are so ludicrous — and infuriating, because PJM was able to get its way solely because it had a bigger bankroll.

We expect this to be about the last time we write about this dispute. But we do feel it important that PJM’s members, who are supposed to run the organization, and PJM’s ratepayers, who pay for it, be aware of the organization’s bullying behavior.

So why did PJM hire an expensive Philadelphia law firm to go after us? Well, PJM and I have a history. As a member of the enforcement staff of the Federal Energy Regulatory Commission, I led an audit of PJM with two other staffers.

During that audit, I met many of PJM’s management and dealt almost daily for months with Chief Financial Officer Susanne Daugherty, who put up with our nettlesome questions with far more patience and grace than most could have mustered. I have tremendous respect for Susanne and most of the people I dealt with at PJM.

Due to FERC rules on the confidentiality of audits, I can’t explain exactly why this experience may have factored into the trademark dispute. The audit report, as released by FERC, didn’t disclose any major problems.

But it’s clear that while PJM’s lawyers claimed to be concerned that our publication could be confused with PJM, it is actually our independence that frightens some in the organization.

We’ll let you be the judge of whether PJM’s suit had merit. Below are some of the more entertaining claims, along with our responses. The full draft of the suit can be downloaded Insider-Draft-Complaint-with-Exhibits-6-6-13.

Pgh. 16: “…The title design of RTO’s publication, “PJM Insider,” is visually similar to the title design of PJM’s publication “Inside Lines,” with the title of both publications appearing on the left in block lettering accompanied by a logo image of power transmission lines on the right.”

We plead guilty to a lack of originality. Sadly, the iconography of the electric power industry is mostly power lines and cooling towers. Dozens of companies and websites employ such images.

tx-line-iconography

But did we copy PJM’s look? Uh, no. The logo was designed by my computer-savvy 14-year-old stepson. And he had never seen PJM’s website before.

Pgh. 30: “As a result of RTO’s acts of infringement, PJM has suffered and continues to suffer damage and irreparable harm…”

Last time we checked, PJM was a monopoly. There’s nothing we could do or write that would give ratepayers in the 13 states within the PJM footprint the ability to choose another electric grid.

In 2012, PJM had 816 members. Current membership is 847. That’s an increase of more than 30, so it doesn’t appear we’ve hurt PJM here.

Pgh. 33: “PJM does, however, object to any implication by RTO that the company or the publication is authorized and/or sponsored by, or in any way related to PJM.”

So do we.

We didn’t launch PJM Insider as a “gripe site.” Most of what we publish is just-the-facts ma’am coverage of meetings and issues, not criticism.

But no one who reads our coverage of the PJM annual meeting or the Board of Managers election could confuse us with a house organ. See also our coverage of the uproar over the board’s plan – since rescinded — to get rid of Market Monitor Joseph Bowring and Monitoring Analytics.

pgh-37

We had to reproduce this paragraph of the suit so readers would know we weren’t making it up. State utility regulators are accused of many things, but we’ve never heard anyone say they can’t read. Moreover, the “consumers” PJM refers to in the same paragraph are people who work for utilities, electric cooperatives, attorneys, electric marketers — hardly an unsophisticated audience.

The fact is, anyone who spends more than a minute with our publication or on our web site will see our ubiquitous disclaimers.

Pgh. 51: “Because of the wide public recognition in the energy sector of PJM’ s registered mark, it is likely that the consuming public who encounter RTO’s use of the domain name and URL www.pjminsider.com/ will be confused, mistaken, or deceived into believing that RTO’s goods and services originated from, or are sponsored, endorsed, or approved by PJM.”

PJM-not-PJM-google-screenshot-w.-arrows

PJM apparently doesn’t like it that when people do a Google search for information on PJM, we also appear (see screenshot). We didn’t get our Google ranking based on the name of our site. We got it because we’ve written nearly 200 stories on PJM since February. People may have looked at us because the word PJM told them what we cover — but they only came back if they found value in what we are writing. And, as you can see, our disclaimer is right there.

PJM’s trademark covers:

  • Bulk electrical market services in the nature of commodity brokerage and price quotations in the field of electricity.
  • Management, administration, and operation of electricity transmission, power and energy markets; auction and trading services in the electricity transmission, power and energy markets; and provision of information related thereto.

We’re not running energy markets or running an electric grid— that’s PJM business.

Are we competing with PJM regarding “the provision of information related thereto”? For that, we make no apologies. Transmission of electricity may be a natural monopoly. Information about PJM shouldn’t be.

PJM members and stakeholders need an independent news source to help them keep track of the myriad issues and to serve as an historical record of previous stakeholder actions. Hundreds of you tell us every week that you agree, by opening our emails and visiting our website.

What happens next?

Over the next couple months we will be moving our website to a new URL (www.rtoinsider.com) and changing our email addresses accordingly. Nothing else will change.

We will continue to push for more transparency in the organization. We think it’s outrageous that the Board of Managers rarely meets in public, and that PJM refuses to disclose board members’ compensation. And we think section 4.5 of PJM’s Code of Conduct — which bars us from quoting members by name without their permission at all meetings but those of the Members Committee and Markets and Reliability Committee — is unnecessary and only feeds the distrust of critics who deride the organization as a “cartel.”

We will continue to be in the room when you can’t be – and asking the questions that need to be asked.

MIC Considers Loosening Rules on Zonal-Nodal Price Switching

The Market Implementation Committee next month will consider proposals to allow network load customers more frequent opportunities to switch to nodal pricing.

Current rules allow network customers to make such switch requests annually, effective June 1st. A stakeholder group formed under a problem statement approved at the request of retail marketer Direct Energy proposed two alternatives to allow such switches monthly. The annual switching rules don’t allow retail marketers to provide innovative products, Direct Energy said.

Both proposals would limit intra-year switches to 5% of the electric distribution company (EDC) network service peak load. The differences between the two proposals are the additional caps on the number of customers per EDC: either five or 50 customers per EDC.

Marji Philips, of Hess Corp., said the intra-year switches could hurt Financial Transmission Rights holders. “If five large industrial customers switch to nodal in the middle of the year, your [FTR] holdings could be seriously impacted,” she said.

David Pratzon, of GT Power Group, questioned the breadth of support for the proposed changes, saying only a small number of stakeholders worked on the problem statement.

The proposals would phase in implementation of intra-year requests with quarterly switches allowed in the first year and monthly switches permitted in the following years. The first switches would be available effective June 1, 2014.

Customers would be required to provide 60 days’ notice before the switch becomes effective, a deadline that could be extended to up to 150 days for complex cases.

As under current rules, customers would be barred from switching from nodal back to zonal.

The MIC is expected to vote on the proposals at its next meeting.

PJM contact: Tom Zadlo

Dominion and PPL to Add One SPS, Remove Three Others

Dominion and PPL will remove three Special Protection Schemes (SPS) while Dominion will add one, PJM told the Planning Committee last week.

Dominion will operate an SPS to control stability at its Bath County pump storage facility to continue operation during the Dooms – Lexington rebuilding project.

The pump storage facility has six generating and pumping units totaling about 3,000 MW. An existing Bath County/Cloverdale SPS is designed to trip either one or two Bath County pumps if the flows on the Cloverdale 6A/6B transformers exceed their temperature-adjusted emergency ratings.

The Dooms – Lexington 500 kV line will be taken out of service about September 2014 for a wreck and rebuild baseline project (b1908). Existing stability restrictions would restrict generation and pumping at Bath to two units, removing about 2000 MW of capacity. The new SPS (PJM Baseline Project b2281) will allow operation of up to five units.

The SPS will not be armed if there are any other 500 kV outages in the vicinity. PJM will determine how many units at Bath will be armed for the SPS based on the operating status of the Bath units (i.e., pumping, generating or condensing).

The target date for completion of the rebuilding project, and removal of the SPS, is June 1, 2016.

The three SPSs being removed are:

  • Dominion Harmony Village SPS:  The SPS was installed in 2007 to prevent an overload on line #65 during loss of towers carrying lines #2016 and #85. The completion of a new 230 kV line (#2122) from Hayes to Yorktown (B0779) in December 2012 eliminates the need for the scheme.
  • Dominion Virginia Beach SPS: The SPS was installed in 2007 to prevent line #27 from overloading as the only feed to Virginia Beach due to loss of two other feeds. The completion of a 230 kV line (#2118) from Landstown to Virginia Beach (S0375) in December 2012 eliminates the need for scheme.

PPL West Shore 230 KV Automatic Load Shedding SPS: SPS B0718 was installed in 2010 to alleviate an N-1-1 summer peak overload condition at the Steelton Tap on the Hummelstown-Middletown Junction #2 230 kV line. A second Brunner Island – West Shore 230 KV line (B0717) went in-service recently, eliminating the need for the SPS.

New 500 kV Line for Dominion

Dominion’s new Pleasant View-Goose Creek 500 kV line will be designated as line number 595.

Dominion is building a 500kV ring bus substation, Goose Greek, to install a 150 MVAR capacitor bank. The Doubs-Pleasant View and Pleasant View-Brambleton circuits will terminate at the Goose Creek station.

The project (PJM baseline upgrade b1799) is designed to correct NERC category C3 N-1-1 voltage violations, with completion targeted for spring 2014.

The Doubs–Goose Creek line will keep the 543 line designation while the Goose Creek–Brambleton (Loudoun) line will keep the 558 identifier.

PJM in Standoff with MISO, NYISO on Order 1000 Filing

Unable to resolve the disputes themselves, PJM last week asked the Federal Energy Regulatory Commission to settle its standoffs with MISO and NYISO over cross-border reliability projects.

PJM and MISO parted ways in separate Order 1000 interregional compliance filings. PJM balked at the MISO’s request to remove cross-border Baseline Reliability Projects (BRPs) from the cost allocation provisions of the PJM-MISO Joint Operating Agreement.

PJM also said it was unable to reach agreement with the New York ISO on a process to address cross-border tie-in facilities needed for reliability. As a result, it said, “the RTOs have not fully satisfied their Order 1000 compliance requirements.”

PJM did reach agreement with members of the Southeast Region Transmission Planning region (SERTP) on an “avoided cost” mechanism for funding cross-border reliability projects.

MISO Proposal

MISO told FERC (ER13-1943) says its request to amend the JOA is justified by FERC’s March 22 Order 1000 compliance order, in which the commission accepted MISO’s proposal to remove regional cost allocation for BRPs and assign all BRP costs to the pricing zone where the project is located. The change took effect June 1.

Since BRPs are no longer subject to regional cost allocation, cross-border BRPs cannot be eligible for interregional cost allocation, MISO says.

PJM - MISO Tie Lines (Source: PJM Interconnection, LLC)
PJM – MISO Tie Lines (Source: PJM Interconnection, LLC)

Instead, MISO proposes that tie lines between MISO and PJM transmission owners be designated as cross-border BRPs. Ownership and responsibility for any upgrades would be shared by the transmission owners — essentially preserving their rights of first refusal (ROFR) on cross-border reliability projects. According to PJM, there are 83 tie lines ranging from 69kV to 765 kV between the two RTOs.

MISO said reliability problems can be addressed through cross-border Market Efficiency Projects, for which interregional cost allocation would continue.

PJM and its transmission owners referred to the dispute only indirectly in their filings with FERC last week, leaving MISO to provide details. The PJM transmission owners “have informed MISO that they do not agree … [that MISO’s request] would be compliant with the requirements of Order No. 1000,” MISO Vice President for Transmission Jennifer Curran said in written testimony included with MISO’s filing.

In a meeting with MISO stakeholders in January, PJM officials and transmission owners made clear their opposition to MISO’s plan. Craig Glazer, PJM vice president of federal government policy, told MISO stakeholders that their proposal was not consistent with Order 1000. “I don’t think that dog’s gonna hunt,” he said. “…You’re doing this because you want to protect the ROFR rights.”

A MISO representative responded that broad cost allocation of reliability projects was not justified because the benefits of such projects are primarily local. In an earlier filing, MISO told FERC that in 80% of its Baseline Reliability Projects since 2006, at least 75% percent of costs were allocated to the local pricing zone.

PJM: MISO Can’t Unilaterally Change JOA

In its compliance filing last week (ER13-1944), PJM told FERC that it should reject MISO’s proposal because the JOA is a contract which can only be changed by mutual consent of the two RTOs. PJM said it would be “damaging” for FERC to “wrest one provision out of this carefully negotiated integrated agreement.”

The 2008 Joint Operating Agreement allocates the costs of cross-border reliability and market efficiency projects between the two regions based on the benefits each expects to receive. Although the two RTOs have had an interregional cost allocation provisions in force since 2005, no cross-border projects have been approved for cost allocation under the JOA, Curran said.

The Order 1000 dispute is one of several points of friction between the two RTOs. On June 20, the RTO officials appeared before FERC to make their cases in a dispute over the way PJM models cross border transmission deliverability, which MISO says is unfairly limiting its generation from competing in PJM’s capacity market. (See: PJM and MISO: Best of Frenemies)

NYISO

PJM also left it to FERC to sort out a dispute with the NYISO.

PJM said the Northeastern ISO/RTO Planning Coordination Protocol, which outlines its relationship with NYISO and ISO-NE, does not provide a mechanism for one region to link to its neighbor’s transmission facilities to solve one region’s reliability need. “These tie-ins are especially critical given the highly intertwined nature of the NYISO and PJM regions, and the unique nature of the NYISO/PJM seam,” PJM told FERC (ER13-1947).

PJM rejected NYISO’s proposal that PJM be subject to the NYISO tariff as a merchant transmission developer or a NYISO transmission owner under the NYISO Transmission Expansion Process. PJM said NYISO’s proposal was unworkable because those market-based processes don’t apply to baseline reliability facilities and would violate commission precedent that coordination between RTOs “should be done at the RTO level.”

PJM asked FERC to order the two RTOs to amend their JOA to add provisions for reliability transmission tie-ins. “Such a directive would help end what has been unproductive debate as to the relationship of this issue to Order No. 1000’s requirements,” PJM said.

SERTP

In a separate filing (ER13-1927), the PJM transmission owners said they reached agreement with the members of the Southeast Region Transmission Planning region (SERTP) to add a new schedule to the PJM Tariff governing cost allocation for interregional transmission expansions. Signing the agreement on behalf of SERTP were Duke Energy, Louisville Gas & Electric/Kentucky Utilities, Ohio Valley Electric Corp. and Southern Co.

The proposal calculates the benefits of an interregional project based on avoided costs — “the cost savings achieved by replacing higher cost regionally-planned transmission projects with the more efficient and cost-effective proposed interregional project,” the PJM transmission owners said.

They acknowledged that the commission previously ruled that the avoided cost methodology does account for economic or public policy benefits of transmission projects. However, they noted, “Order No. 1000 does not require the consideration of public policy or economic benefits at the interregional level.”

MIC Rejects Change to FTR Long-Term Auction Modeling

The Market Implementation Committee last week soundly rejected a proposal to change the modeling assumptions used in long-term auctions of Financial Transmission Rights (FTR).

The proposal — which would have reduced capability in long-term FTR auctions from 100% to 50% of available capability after reserving Auction Revenue Right (ARR) capability — received support from only 36% of MIC voters.

Bruce Bleiweis, director of market affairs for DC Energy, LLC, said the proposal would hurt the ability of market participants to engage in long-term hedging while providing only small improvements to FTR funding shortfalls. “It will result in a lot less liquidity, a lot less price discovery,” he said.

In May, the MIC gave near-unanimous support to two other modeling changes also intended to reduce the risk of FTR funding shortfalls by reducing or eliminating infeasibilities in the FTR model so that increased counterflow FTRs clear.  (“MIC OKs Options to Reduce FTR Shortfalls”)

MIC rejected another proposed change and deferred a vote on the long-term auction proposal pending a ruling on FirstEnergy Corp.’s complaint to the Federal Energy Regulatory Commission over FTR underfunding (EL13-47). FERC rejected the complaint June 5, saying FirstEnergy had not proven PJM’s current practices are unjust and unreasonable. The commission urged the RTO to continue its efforts to address the causes of underfunding.

Members Select Model for Installed Reserve Margin Study

The Planning Committee voted last week to continue using a load model based on the period 1998-2006 in its calculation of Installed Reserve Margin (IRM) requirements.

The 2013 Installed Reserve Margin (IRM) study will set IRM requirements for base capacity auctions for delivery years 2014 through 2017. The 1998-2006 load model selected by the committee is the same one used in the 2011 and 2012 IRM studies.

The committee is expected to receive the study results in September and vote on the new IRM requirements in October.

MD OKs $28 Million Base Rate Boost for PEPCO

Seeking its third base rate increase in four years, Potomac Electric Power Co. won approval from Maryland regulators Friday for a $28 million increase in distribution rates and a $24 million surcharge to accelerate the hardening of feeder lines.

Pepco had asked the Maryland Public Service Commission for almost $61 million in additional distribution rates and an increase in its return on equity (ROE) to 10.25%. The commission accepted a staff recommendation for an ROE of 9.36%, a slight boost from the current 9.31%. The changes will add $2.41 monthly to the average residential bill, effective July 12, 2013.

Pepco also requested a $192 million Grid Resiliency Charge, including $17 million for accelerated vegetation management; $151 million to move portions of six feeders underground and $24 million to accelerate the hardening of 24 feeders that are prone to outages during major storms.

The commission approved only the work on the 24 feeders, saying it needed more information on the undergrounding proposal. The commission said the company’s plan for accelerating vegetation management in 2014 “has no impact on the amount of tree trimming required for subsequent years and provides no cost savings in the future.”

PJM Considers Increased Penalties for Reserve No-Shows

PJM officials told the Operating Committee last week that they are considering increased penalties to eliminate the current economic incentives for generators and demand response providers that fail to perform when called on to provide spinning reserve.

Providers of Tier 2 synchronized reserve are paid per MWH of reserves offered but are only called on to provide reserves for about three spinning events per month, most of them less than 20 minutes long.

“The result is that it is possible to provide the service profitably with a very low level of compliance,” the Market Monitor said in the 2011 State of the Market Report. “This behavior does exist in this market.”

The monitor repeated its call for increased penalties in the 2012 report with some additional observations: “Sometimes units do not achieve the ramp rate they have bid, sometimes units fail to follow PJM dispatch, sometimes system conditions change rapidly during the hour between a market solution and the actual hour.” The monitor noted that non-compliance “has never caused a reliability problem at PJM.”

Tom Blair, of Monitoring Analytics, told the Operating Committee that the market monitor studied three spinning events of more than 10 minutes in 2013 and compliance by demand response resources was “not good.”

David Pratzon, who represents generators at GT Power Source, supported the call for increased penalties. “Tier 2 resources can clear for hundreds of hours before they are called even once. There is a risk that someone can take the money and run.” The weighted average market price for synchronized reserve was $8 per MW last year.

However, Pratzon and representatives of other generators said the rules shouldn’t be so strict that they penalize providers that are doing their best to comply. For example, Pratzon said gas generators can hit “dead bands” during duct firing, and coal plants may underperform if their fuel is damp or of lower quality.

Pratzon, AEP, Exelon and Exelon joined to propose an alternative set of penalties that would not apply unless providers fall below 90% of their promised reserves. Blair said the market monitor also supports the 90% threshold.

Brock Ondayko, of AEP, said although the PJM dispatch system has improved, it still does not accurately model the behavior of coal-fired units.

He added that PJM should ensure that changes to the synchronized reserve rules do not have unintended consequences. “Adjusting ramp rates also impacts the amount of energy we’re awarded during the day,” he said.

PJM staffer Kim Warshel asked participants to submit proposed alternate solutions by July 16, in time for consideration at the next special meeting of the Operating Committee to discuss the issue, set for July 18.

NYISO Scheduling Proposal Faces Questions

A proposed new scheduling option for transactions into the New York ISO faces an uncertain future after a first reading at the Market Implementation Committee meeting last week.

PJM said it plans to seek an MIC endorsement in August of the Coordinated Transaction Scheduling (CTS) proposal, which is designed to improve interchange scheduling efficiency between NYISO and PJM.

The proposal would create an additional scheduling product, intra-hour evaluations of CTS interface bids and offers. 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.

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 could reduce production costs by as much as $26 million, but PJM’s Rebecca Carroll said the RTO had not analyzed how much of those savings would be offset by make-whole payments to generators.

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 within $5 about 60% of the time. “We definitely see there’s room for improvement here,” said Carroll.

PJM initially proposed that the trades be exempt from Balancing Operating Reserve (BOR) charges because they provide economic benefits to both NYISO and PJM and will be cleared and scheduled based on near-term projected operating conditions.

But the RTO dropped that proposal after stakeholders said the transactions should be treated the same as real-time dispatchable transactions.

“Because this is a real-time product, it is going to have an impact on balancing congestion,” said one stakeholder, whose identity is being withheld at his request, per PJM’s code of conduct. He said Financial Transmission Rights (FTR) holders should not be penalized for such impacts.

PJM also proposed 15-minute settlements for all interchange transactions — the same interval for which they flow — rather than being integrated in the current hourly settlement processes. PJM said the change would require a longer transition process than using 15-minute settlements for CTS trades alone.

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.

Stephanie Staska, of Twin Cities Power, LLC, said the credit requirement should apply to all export transactions if such a screen is initiated for CTS transactions.

Several MIC members said it was premature to schedule a vote next month given the level of detail PJM had provided them to date. “I don’t know if we understand this issue well enough to vote knowledgeably,” said Jung Suh, of Noble Americas Energy Solutions LLC.

Dave Pratzon, of GT Power Group, said stakeholders should explore the impact of the change on balancing congestion and the implications of using 15-minute settlements.

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