By Rory Sweeney

FERC’s technical conference last week on Order 1000’s performance produced a mix of feedback, with some participants suggesting complete overhauls of the landmark rule and others saying it’s too early to tell if any changes would be useful. But nearly every participant urged the commission to improve transparency in transmission planners’ decision-making processes (AD16-18).

Issued in July 2011, Order 1000 sought to increase transmission development by eliminating incumbent utilities’ monopolies and creating incentives for more innovative, cost-effective and efficient projects.

The order — and its 2012 sequels, 1000-A and 1000-B — have caused heated debate as well as confusion about how the order is to be applied.

Transparency and ‘Evaluation Risk’

George Dawe, vice president of Duke-American Transmission Co., said one of his biggest challenges as a competitive developer is what he called “evaluation risk.”

“I have no idea what the RTO is going to do. I have a general framework for how they plan to evaluate my project after I’ve spent ‘X’ amount of dollars, but no real idea because they’re not being real specific. We need that kind of clarity to keep the developers engaged.”

Those on the customer side also called for transparency.

Donald L. Gulley, president of the Southern Illinois Power Cooperative, said his members are not only asking for transparency but also the opportunity to review the results so they can understand what is working and what isn’t. “What it comes down to for us is … what is the consumer ultimately going to pay?” he said.

However, increased transparency poses a litigation risk for RTOs, said Craig Glazer, PJM vice president of federal government policy.

“Order 1000 is driving transparency, so it is driving us to put more and more things in our Tariff. We’ll have to sort of step back when trying to balance between transparency and specificity in the Tariff with not so much specificity that we have taken away the judgment and discretion part of planning,” he said. “When we document every part of the process, that, to me, is creating the ‘gotchas’ that we will have to deal with.”

CAISO Deputy General Counsel Anthony Ivancovich added that “a wrong decision that can be corrected by litigation is much better than a wrong decision that’s embedded in your tariff and can’t be resolved by litigation because it’s the filed rate.”

Cost Containment

Another recurrent topic during the two-day conference was cost caps. Noman Williams, the chief operating officer and senior vice president of engineering and operations for GridLiance, said caps change the standard transmission development process by transferring the risk of overruns from ratepayers to the builder. “It brings value back to the consumer,” he said. “It is incumbent on us, when we say we want those opportunities and we don’t want to have structure, that we also explain how the cost-containment, cost-cap bids can be applied.”

Sharon Segner, vice president of LS Power Development, lauded PJM and CAISO for figuring out “how to make the cost caps enforceable and not just a PowerPoint presentation.” Developers who fail to stay within their caps risk both the project and the approved rate, she said, and “that is a lot.”

Kim Hanemann, senior vice president for delivery projects and construction for Public Service Enterprise Group, said cost-containment provisions “are of limited value.” PSEG “does not view Order 1000 right now as improving the transmission planning process or bringing value to our customers” because it focuses too exclusively on costs, she said.

“Projects with the greatest overall value may be more expensive in the short term, but they might provide other ancillary benefits, such as reducing congestion and replacing aging infrastructure,” she said. “Simply put, the project with the lowest bid-cost is not necessarily the best project or value for our customers.”

In 2014, PJM planners recommended PSEG’s Public Service Electric and Gas to construct a stability fix for the company’s Artificial Island nuclear complex in New Jersey. However, the PJM board reopened the bidding and ultimately awarded much of the project to LS Power, citing the developer’s lower cost and inclusion of a cost cap.

Richard S. Mroz, president of the New Jersey Board of Public Utilities, said cost and cost caps shouldn’t factor into decision-making until the end of the process.

The process must focus on the scope of the project and what needs to get done, he said, before it can determine how much that will cost. “That’s something that can get lost in the process. That sense of cost consciousness is what drives me and what should drive the process for everyone.”

John Lucas, general manager of transmission policy and services for Southern Company Services, who was also representing Southeastern Regional Transmission Planning, asked that the region —  which isn’t overseen by a grid manager — be excused from any rules on cost-containment.

“We would note that [cost caps are] voluntarily adopted processes … that were not required in Order 1000,” he said. “Therefore, if the commission feels the need to make adjustments in those regions, we would just ask that you direct changes to the regions where those processes have been adopted.”

Debate over Incentives

There was also debate regarding project incentives, with consumer advocates saying some should be eliminated while industry members asked for more and said they wanted several — including construction work in progress and abandonment incentives — standardized for all projects.

That brought strong opposition from Peggy Bernardy, staff counsel with the California Department of Water Resources. “The commission should resist the urge to standardize incentives that might be calcified and set in stone for perpetuity,” she said. “That is a risk to us.”

“The commission is perhaps unwittingly complicit in creating an investment environment in which nothing gets done without some form of ‘incentives’ —  but which, in reality, are subsidies that only create the illusion of success,” said John Hughes, CEO of the Electricity Consumers Resource Council (ELCON). “Subsidies to promote responses by independent transmission companies to the competitive solicitations mandated under Order No. 1000 do not achieve competitive markets.”

Developers, however, said the potential revenue offered by incentives are key in larger companies getting projects supported by their executives.

Sponsorship or Competitive Model?

Raja Sundararajan, vice president of transmission finance, strategy and siting for American Electric Power, said the order is largely working well, containing both necessary flexibility and transparency. Of the two project-selection methods — sponsorship or competitive bidding — he greatly favored the latter.

CAISO, MISO, SPP and WestConnect have adopted the competitive bidding model, in which transmission planners, with stakeholder input, identify the projects they want and then solicit bids from developers. The winners are eligible for regional cost allocation.

Under the sponsorship model, in contrast, transmission planners and stakeholders identify transmission needs and allow developers to propose potential solutions. PJM, ISO-NE, NYISO, South Carolina Regional Transmission Planning, Florida Reliability Coordinating Council, Southeastern Regional Transmission Planning, Northern Tier Transmission Group and ColumbiaGrid have adopted the sponsorship model.

CAISO’s competitive solicitations have a six-month window that allows time to put together a “real” proposal, Sundararajan said. The sponsorship model is “great for generating ideas” but “doesn’t lend itself” to preparing a comprehensive proposal because it doesn’t allow enough time for the necessary research, he said.

“When the rules are known and the methodology is consistently applied, business works best,” said Michael Sheehan, executive director of NextEra Energy Transmission. California is “getting repeated bidders coming back to competitions in that market because it is clear, transparent, consistently applied and you’re getting feedback.”

ELCON’s Hughes called the project-approval process “nothing more than a food fight” within the RTOs, saying that his membership is seeing transmission costs rise each year without any benefits to show for it.

Southern Co.’s Lucas said there hasn’t been enough information gathered yet to suggest any changes to the order, while Omar Martino, director of transmission for EDF Renewable Energy, said there are many changes that need to be implemented. RTOs are holding onto “historical ways of doing things” that are increasing congestion and hampering grid efficiency, he said.

Planning vs. Regulation

PJM’s Glazer said that by factoring cost into their project approvals, RTOs are effectively setting rates. That movement into a regulatory role “is what makes us nervous,” he said, suggesting the RTO be allowed to take tough decisions to FERC for a second opinion.

PSEG’s Hanemann said grid operators don’t have adequate proficiency in several project development considerations, such as environmental permitting requirements, industry practices, local regulations and equipment procurement.

CAISO’s Ivancovich warned against installing rigid mathematical formulas for decision-making, saying it doesn’t allow for evaluating each proposal on its facts. “You need to establish integrity and credibility that we will be fair in looking at” each proposal, he said.

The entire proceeding was guided by the FERC commissioners’ questions on the positive and negative impacts of the order. Commissioner Cheryl LaFleur said she attempts to follow what she called the “regulatory Hippocratic Oath: Don’t make things worse.”

In a statement before the hearing, LaFleur noted that FERC has dealt with ratemaking and incentive issues resulting from the order on a case-by-case basis and asked for feedback on whether it should issue a policy statement or rulemaking to address the issues generically. “I also hope to address how to harmonize requests for incentives, particularly regarding return on equity, with competitive proposals that include cost caps or other limits on a developer’s ability to recover costs,” she wrote.