By Rory D. Sweeney

COLUMBUS, Ohio — PJM’s Craig Glazer opened a panel on controlling transmission project costs at last week’s annual meeting of the Organization of PJM States Inc. with a tongue-in-cheek game show: “Who Does What?”

The series of multiple-choice questions he presented highlighted the lack of clear authority throughout the transmission-development process, with state regulators, RTOs and FERC all potentially playing a role.

Who decides which of three cost-capped transmission proposals — differing on what costs are covered and what are excluded — is the best for ratepayers? Who enforces the cost cap after an award?

“There are no clear answers,” said Glazer, PJM’s vice president of federal government policy. “This is about one of the fuzziest areas we’ve got.”

That set the stage for a dialogue on transmission planning that spanned two panels and more than three hours of discussion. The first panel tiptoed around the troubled Artificial Island project to debate the advantages and challenges of cost caps. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)

The second panel focused on FERC’s recent decision to investigate how supplemental projects are awarded. It pitted incumbent transmission owners against independent transmission developers and the customers who pay to use their networks in debating how receptive TOs should be to outside opinions on how to manage their assets. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)

FERC Policy Statement?

Sharon Segner of LS Power, who sat on both panels, outlined her argument in detail. She started by campaigning for FERC to issue a policy statement defining the elements of cost caps, contrasting it with nonbinding cost estimates.

It was a reprise of arguments the company made in comments filed earlier this month following a FERC technical conference on Order 1000 (AD16-18). (See Five Years Later, FERC Takes Another Look at Order 1000.)

Segner said cost-containment proposals must be specific about what costs are covered and what are excluded, including legal caveats. And those promises must be incorporated into the designated entity agreement and rate case to ensure enforceability, she said.

“A PowerPoint proposal, in our view, is not a cost-containment proposal. It has to be clear, and the legal language has to be clear as well,” she said. “The selection process should fairly and truly weight the cost-containment proposal.”

Cost Caps Impractical

Jodi Moskowitz of Public Service Enterprise Group said cost caps make sense in theory but can be challenging in implementation. First, she said, the 45 days PJM has given bidders to respond to solicitations is not enough time to develop accurate cost estimates.

She also raised the issue of permitting delays, citing the Susquehanna-Roseland reliability project that PSEG built with PPL. It took four years to win National Park Service approval for a crossing through the Delaware Water Gap National Recreation Area even though it was completely within an existing right of way, she said.

“The challenges associated with these large, linear projects is intense,” she said, noting that “the cheapest project may not provide the overall best value to customers.”

She pointed out that FERC, in its acceptance of PJM’s Order 1000 compliance filing, rejected a cost-cap proposal, noting that many of the issues involved with project development are out of the developer’s control.

“Competitive transmission — we struggle with that term,” she added, questioning whether competitive developers’ designs are equal to her company’s standards. “We only have one grid.”

Risk Premium

Josh Burkholder of Transource Energy, a joint venture of American Electric Power and Great Plains Energy, said proposals that offer both guaranteed cost caps and significant cost savings are “too good to be true.”

“This has me scratching my head, because if risks are truly transferring [from customers to the developer], you would expect there to be an associated risk premium.”

In response to that pressure, his company attempted to share the cost risks with its construction vendors, equipment manufacturers and companies acquiring rights of way.

“That process has been very, very challenging,” he said. “There are risks that our suppliers are just flat-out not interested in taking. They have plenty of work that they can do without assuming a lot of new risks.”

Including its risk premium in its Artificial Island bid made it uncompetitive, he said.

Attorney Robert Weishaar, who represents the PJM Industrial Customer Coalition, said Order 1000 “has yet to deliver tangible benefits.”

“We think FERC needs to redouble its efforts to provide clear directions to RTOs on how … to fully implement Order 1000 and deliver on its promises,” he said.

Weishaar also said FERC should eliminate rate incentives — such as those for RTO participation and independent transmission companies — in Order 1000 projects. “This is competition,” he said. “There are no regulatory incentives in competition.”

Supplemental Projects

In the second panel, Exelon’s Gloria Godson and Bob Bradish of AEP passionately defended transmission owners’ authority to manage their assets without second-guessing.

“I have a good relationship with some of my neighbors. Some of them, I really don’t like the way that their doors look. I think that they should change their doors, but I have never gone over to my neighbor and said, ‘You know what? I’m going to take down your door and change it,’” Godson said. “You just don’t do that to someone else’s assets. It’s just not courteous. It’s not nice!”

“We have a set of standards,” Bradish added. “We’re certainly happy to sit and debate standards, but we don’t want someone’s opinion to substitute for 110 years of doing the work.”

He called suggestions from stakeholders on what specific components to use “not helpful.”

American Municipal Power’s Ed Tatum said the fact that his company is helping to foot the bill is what qualifies him to be part of the decision.

And he said that bill has jumped sharply in recent years. In the earlier panel, he had pointed to a transmission expansion in Jersey Central Power and Light’s territory whose costs ballooned from $22 million to $111 million once estimates had been more “fully refined,” according to the presentation at the Oct. 6 Transmission Expansion Advisory Committee meeting.

“We’re not asking to paint anybody’s door … but what we are concerned about is what’s being built and why. The reason is because we’re paying for it. If we’re paying for it … we should talk about it.”

Segner said her company is concerned the supplemental project process allows incumbent transmission owners to win projects that should be open to competition.

She also voiced concern that the Transmission Replacement Processes Senior Task Force — which has been assigned to develop rules and review processes for “end-of-life” projects — has a flawed mission and no means to repair it.

“The solution is not more PJM slides. It’s not prettier slides,” she said. “There needs to be fundamental reform in the local planning process, and that’s where the transparency needs to be.”

TEAC Restructuring

Earlier in the panel, PJM Vice President of Planning Steve Herling explained the RTO’s plans to restructure the TEAC to be more dynamic and communicative.

“We’re going to be putting more and more of the material out, essentially in kind of webcasts well in advance of the TEAC meeting,” he said. “Our goal is to have this material all available before we get to the TEAC or the sub-regional [Regional Transmission Expansion Plan] committees so that you can educate yourself about a particular problem, about a solution option that is out there and then engage in Q&A with PJM or with the transmission owners.”

PJM’s hopes to implement the changes by the beginning of the 2018 RTEP cycle, but enhancements will be rolled out as they are ready.