By Rory D. Sweeney

As far as PJM transmission owners are concerned, the customer doesn’t always know best. They lack the institutional knowledge of the TOs, who have been operating their systems for decades and are responsible for their performance.

PJM transmission customers agree that they don’t have the information the TOs possess. But some are trying to change that imbalance, saying they are no longer willing to pay for replacing aging infrastructure system without assuring themselves that the spending is necessary.

How much more information the TOs will be required to share could be decided at today’s FERC meeting. The commission is scheduled to release a decision on its 2016 show cause order that questioned whether TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71). (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)

The commission is also scheduled to address the TOs’ proposed Tariff Attachment M-3, which they developed to codify the “additional detail and transparency regarding the process for planning supplemental projects” that they’ve agreed to (ER17-179). (See PJM Demands Agreement on Tx Replacement Definitions.)

RTOs Provide Customer Forum

For most of their existence, TOs have had only to persuade state and federal regulators that their infrastructure plans were necessary, under a monopoly structure that entitled them to cost recovery and a margin of profit. The development of RTOs and ISOs has given their customers a forum to voice concerns and seek influence over transmission planning.

In PJM, American Municipal Power has made controlling its transmission costs a primary focus. Supported by several other RTO members — fellow transmission customers, state consumer advocates and merchant transmission developers — AMP has pushed the issue to confrontation on multiple fronts, including a stakeholder task force focused on end-of-life issues for transmission infrastructure. (See AMP Presses AEP, PSE&G on Transmission Projects.)

The Transmission Replacement Process Senior Task Force (TRPSTF) became a flashpoint almost as soon as it was proposed in January 2016. TOs argue that PJM and FERC rules give them sole discretion over how to maintain their assets — including when and how to replace them. The task force went into a 10-month hiatus after FERC issued its show cause order but reconvened after PJM stakeholders reinstated it last year.

More Transparency Sought

AMP and Old Dominion Electric Cooperative said they have been concerned about transparency in the planning process for quite some time.

“I don’t know if we had a big bang or if we had a slow burn,” AMP’s Ed Tatum said in an interview with RTO Insider. “We just kept asking more questions. … That gave us some traction to continue to ask questions.”

Both sides acknowledge that infrastructure, at some point, needs to be replaced. But the customers argue they aren’t provided enough information to independently evaluate whether proposed replacements are necessary or excessive. “I feel there should be adequate information for us to determine what is needed,” Tatum said.

AMP and ODEC argue that TOs are incentivized by their formula rates to build as much as possible and that regulators’ oversight is not adequate to corral the impulse.

“To me, it’s more of a check and a balance: Before they start replacing something, does it make sense?” ODEC’s Mark Ringhausen said. “Maybe that’s a concern that some of the TOs have: [that customers will] figure out that we’re replacing more facilities than they really need to.”

They point to a sudden rise in supplemental transmission projects, which are projects developed by TOs for their own transmission zones to address their own planning needs. They don’t have to address any PJM criteria, nor do they require the RTO’s sign-off to begin work.

Through 2012, according to a study done for AMP, PJM had planned or in service $21.3 billion in baseline and network upgrades — which are subject to detailed review by the RTO — versus $6.8 billion of transmission-owner identified (TOI) and supplemental projects. Since 2012, the $11.6 billion in baseline and network upgrades have been exceeded by $12.7 billion of TOI/supplemental projects.

“There are more projects outside of the PJM planning process than there are inside,” Tatum said.

“Of the 270 supplemental projects in 2017, when presented at their respective first reads [at Subregional RTEP Committee meetings], 181 of the projects were already in a stage of development ranging from engineering to 100% complete, with five projects already in service at their first reads,” the customers said in a 61-page recounting of their arguments filed on Tuesday. “At the second read, 205 out of 270 proposed supplemental projects were beyond the conceptual/scoping development phase, with nine already in service. Said another way, 76% of supplemental projects were presented to stakeholders in the SRRTEP meetings at a stage of development where meaningful input is unfeasible at best.”

Customers believe TOs have used these opportunities to bypass the stakeholder process and go straight to state and federal commissions, where they say they maintain longstanding political influence, as their best bets for revenue growth. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)

“I think it’s pretty simple economics. They’re not making a whole lot of money on generation right now, and they’re getting [returns on equity] on transmission in the 10 to 12% [range]. We don’t blame them,” AMP General Counsel Lisa McAlister said.

“Part of the reason why [customer input is] so important is because there’s not a lot of other regulatory oversight, and when it does happen, it’s too late in the process to be meaningful,” said McAlister, who signed AMP’s filing. “There aren’t a whole lot of other stopgaps to help.”

In its filing Tuesday, which asked the commission to reject Attachment M-3 and order further changes to achieve compliance with Order 890, the customers said FERC should require TOs and PJM to:

• Record and post all questions and answers from proposal reviews;
• Provide the power flow study details, including a description of the violations or issue identified;
• Provide more detailed descriptions of the proposed facilities, including descriptions and costs of the assets being retired, installed or replaced; and
• Provide adequate time for review and analysis.

PJM’s subregional transmission expansion plan process “has no provision to validate a TO’s need for supplemental projects nor the prudency of the project,” the coalition said.

TOs’ Response

The customers’ requests ignore PJM’s function on supplemental projects, says Exelon’s Gloria Godson.

“PJM’s process is a planning process, not a prudency review,” Godson said in an interview with RTO Insider. The correct venue for cost complaints is at FERC and state commissions, not PJM, she said.

To best understand the conflict, Godson said, think of TOs as car manufacturers and their networks as their own unique vehicle that they lease to customers. Customers get to use the car for their needs and must pay for improvements and maintenance, but ownership, knowledge about and ultimate responsibility for it remain with the manufacturer.

Customers want to understand the car’s engineering so well that they can independently confirm the need for the expenses the owners want them to incur. But the owners fear customers are more focused on cost because they’re not on the hook for the car’s reliability.

PJM, in Godson’s analogy, is the company that builds and maintains roads. But the RTO can’t tell TOs what tires to install on the car or when to replace the radio, she said, any more than it can tell TOs how much that work should cost.

In a combined statement to RTO Insider, PPL, Public Service Electric and Gas (PSE&G), Exelon and Duquesne Light said replacement costs have increased in response to new obligations, such as higher security demands and increased efficiency and reliability standards.

“Shared final decision-making with a diverse set of stakeholders each with differing priorities would negatively impact the safety, reliability, security and efficiency of the transmission network. It would also lead to lack of clarity as to who has the responsibility for the impact of adverse events,” the TOs said.

Order 890, the TOs said in their October 2016 response to the order to show cause, “affirmed that the ultimate responsibility for planning remains with transmission providers and that it was not requiring transmission providers to engage customers in the transmission planning process on a ‘co-equal basis.’”

Godson pointed to her experience at Potomac Electric Power Co. (Pepco) with the failed Mid-Atlantic Power Pathway project as an example of regulators’ exercise of cost discipline. Pepco attempted to recover $87.5 million in costs after the project was canceled by PJM, but intervenors protested and FERC eventually approved a $80.5 million settlement (ER13-607).

No Bright Line

It’s not possible, TOs say, to develop a standardized way for customers to replicate the analysis that they would be able to endorse because it would require modeling so detailed and exact — on variables ranging from terrain and weather to population density, local regulations and load types — as to be impractical, along with institutional knowledge that they say only exists at the TO.

“There is no bright-line criteria for determining when an asset should be replaced, as it is based upon a variety of factors that require engineering and operational judgement,” the statement said.

“A company may be willing to take a different type of risk in a rural area than they may be willing to take in Washington, D.C., for example,” Godson added. “That goes from one TO to another, so it’s … not possible to have a cookie-cutter approach to system design. … My question would be, for what basis? PSE&G knows their system better than anybody can. … This is what they do for breakfast, lunch and dinner.”

More can be Done, Customers Say

Customers acknowledge the issues but say there’s more that can be done.

“There’s judgment to this, but those are discussions that need to happen,” Ringhausen said. “They need to present us enough information that we can understand their criteria.”

“One of my large concerns with this is [the industry] creating the exact same situation we’re in now for the next generation down the road,” AMP’s Ryan Dolan said. The transmission infrastructure was largely built at the same time, and TOs are “in a mad rush” to replace everything at the same time. Dolan argues that with some foresight and consideration, the replacements, and their costs, could be rolled out over time.

“Should we have a long, sustained capital investment?” he asked.

“TOs don’t have anything that predicts the longevity of assets. … Age is simply a bucketing mechanism, but whether and when an asset is actually replaced depends on the condition of that asset,” Godson responded. “So, you may have a transformer that is relatively newer, but if it begins to [break down], you cannot defer maintenance [just] because it’s not old enough. Conversely, there are assets that are 70 years old and still going strong. So it depends on the condition and performance of the asset.”

While TOs’ primary strategy is monitoring and replacing based on condition and performance, there are some times when equipment targeted for replacement can be addressed while repairs are being made to infrastructure nearby.

Improvements

TOs argue they have worked to improve information sharing in the monthly meetings that focus on PJM’s Regional Transmission Expansion Plan, as documented in Attachment M-3. “The PJM process is far and away the most transparent of any process in the country,” Godson said.

Tatum contends the sides are “fairly close” and that a solution to the dispute “doesn’t need a quantum shift.”

The TOs disagree with the magnitude of the change they say AMP and its allies are requesting.

“AMP’s proposal that PJM and the PJM stakeholders take over the TOs’ responsibility for asset replacement and managing the supplemental project planning process violates the [Consolidated Transmission Owners Agreement] and would breach a fundamental contract that forms the basis upon which TOs joined PJM,” the TOs said. “PJM does not have the expertise, experience or resources to take over the TOs’ asset management function. PJM has stated repeatedly that they do not consider this an appropriate role for PJM.”