By Michael Kuser and Jason Fordney

Generation developers and transmission providers on Wednesday called for more direction from FERC to improve coordination of “affected system” studies in the generation interconnection process.

Suggested improvements on the second day of a FERC technical conference included sharing study models earlier, clear timelines and cost estimates, and better definitions for identifying an affected system — one impacted by new generation in a neighboring region (EL18-26, AD18-8). (See related story, Renewable Gens Face Off with RTOs at Seams Tech Conference.)

Day 2 focused largely on the commission’s generator interconnection Notice of Proposed Rulemaking (RM17-8). The NOPR noted that because affected systems are not bound by the practices of the system processing an interconnection request, its process and schedule may differ from the host.

“The challenge with California is that we are like Swiss cheese, with no requirement that all the utilities had to join the CAISO,” said Deborah Le Vine, CAISO director of infrastructure contracts and management. “We have a total of, believe it or not, [19 potentially] affected systems, and out of [them], two are [FERC] jurisdictional.”

Seeking a FERC Fix

“We’d love for you to tell us a fix, because all the ideas we’ve come up with haven’t worked so far,” Le Vine said. “The challenge has been trying to put together any type of reciprocity agreement. That’s why we don’t have the ‘teeth’ to mandate compliance.”

Brian Fritz, director of transmission development at PacifiCorp, said that since the inception of the company’s interconnection queue, it has received more than 1,000 requests for interconnection totaling over 90 GW. “I heard the term ‘Swiss cheese,’ but ours is Swiss cheese on steroids,” Fritz said. “We’re interconnected with many, many different utilities because we have such a large footprint across the west.”

Lisa Szot, head of transmission and interconnection for Enel Green Power North America, bemoaned the lack of a standardized process for affected-system studies. “It would be nice to have something that forces the affected systems to have to complete a study within the time frame of associated areas to meet the timelines of the interconnection process,” she said.

Scott Seier, vice president of private equity firm and generation investor Tenaska Capital Management, said he preferred FERC direction to lengthy RTO stakeholder processes.

“FERC leadership is vital and necessary to ensure problems plaguing processes are addressed to ensure the efficient processing of the interconnection queue and foster competitive and robust markets for electricity,” Seier said. “Looking at the narrow issue of affected-system study coordination, fixes include limited scope of studies in the early stages, increased RTO study resources and allowing interconnection customers to fund affected-system or other interconnection study work to ensure interconnection agreements can be achieved by a certain date.”

Cost Allocation

Commission staffer Tony Dobbins asked MISO Director of Resource Utilization Vikram Godbole if the RTO calculated cost responsibility on a case-by-case basis, “or has it been pretty much a standardized process or document that may have a couple of variations for each entity?”

Godbole said that MISO’s documentation could be improved to provide more detail to customers at the front end of the process.

“We need to keep in mind how far RTOs have come from a coordination perspective,” Godbole said. Older tariff versions lacked any coordination process, he said.

“About the geography of the upgrades, it doesn’t matter whether it’s 600 miles away or a thousand miles away, it comes down to electric impact that has to be mitigated,” Godbole said. “Upgrades will be identified, and somebody’s going to have to pay those. … We have to keep going with our process, the way we’re doing, look for more feedback from stakeholders. And any guidance FERC wants to provide would be helpful.”

EDF Renewable Energy Project Engineer Anton Ptak said the industry needed tariff provisions to detail how costs are allocated and how models are established between affected systems and host transmission providers.

“One thing we’d like to see is specific tariff requirements on affected systems to perform their affected-system studies and provide results when required under the host transmission provider,” Ptak said. “We’ve experienced several delays with affected systems providing their results to MISO in the recent past, and so we’d really like to see some specific language improving the provision of the affected-system study results.”

Szot agreed that cost estimates need to be provided early in the process.

“The affected systems need to provide base case models so an interconnection customer can try to assess potential costs,” Szot said. “For an interconnection customer, the costs that can occur from an affected system could make the project no longer viable. This is a huge commercial risk to developers.”

Small Utility Perspective

James McFall, manager of electric resources for the Modesto Irrigation District in the Central Valley of Northern California, gave the perspective of a smaller — 560 square miles and 114,000 customers — utility. MID is not a member of CAISO but is an affected system of other systems that are connected to the ISO. As such, it has no ability to control dispatch on generators connected to the host system to manage reliability events, McFall said.

The utility must spend significant staff time and resources on affected-system studies, he said. The utility mitigates costs by waiting until certain milestones are met to maximize potential that projects that are studied will be developed.

“Any cost impacts caused by generators interconnecting to third-party systems are borne by MID’s ratepayers if MID is unable to recoup or avoid the costs created by those interconnections,” he said.

McFall said MID is not in favor of standards for affected-system coordination, and he asked FERC to “consider collateral impacts on smaller entities such as ourselves” if it considers standards.

Interconnection-wide Models?

Tradewind Energy Transmission Manager Aaron Vander Vorst said that the industry has been left to navigate its way through affected-system studies because of the “unscripted process” of Order 2003, including managing departures from the pro forma interconnection procedures.

He proposed a concept of “One Model, One Queue, One Schedule,” including jointly developed interconnection-wide transmission models to improve accuracy and efficiency between systems.

Affected systems should be able to do studies on their own queues and neighboring queues simultaneously to encourage cross-seam coordination, he said. And he said the study schedule should be aligned between neighboring providers to ensure developers have the information they need to make informed milestone decisions.

“Taken to the extreme, use of identical dispatches across seams would largely eliminate the need for affected-system studies,” he said.

“The existing rules, procedures and coordination procedures are simply not adequate for the environment that we have found ourselves in today,” he said, “but change is difficult.” The industry needs clear directives from FERC, he said.

First Solar Development Interconnection Manager Madeleine Aldridge, whose company developed about one-third of utility-scale solar serving California, said CAISO has improved its processes by notifying affected systems at an earlier stage. But, she said, “more needs to be done to incent the host transmission owners to take on the coordination that will provide interconnecting generators certainty and best siting incentives relative to existing transmission.”

Aldridge said her the company has waited for as long as two years for affected-system studies. Under current rules, “we are not really sure when we will get the studies report,” she said.

“The concept of coordinated regional planning has not yet touched the generator interconnection process in an efficient manner,” she said. “The Bulk Electric System is really one grid, except for a few exceptions, and really cannot, and should not, be planned for in discreet sections. With well-planned generation, interconnection study processes, regional coordination that includes utilities outside the boundary of the host transmission owner, can increase least-cost solutions, versus disjointed expensive transmission upgrades.”

But Jay Caspary, director of research development and tariff studies for SPP, said an interconnection-wide transmission planning and interconnection process is impractical in the Eastern Interconnection.

“Our [generator interconnection] models — all the models we use for tariff services whether its transmission service or generator interconnections — are based upon our [integrated transmission plan] model,” he said. “I can’t imagine us trying to do that in one effort. Those are big efforts individually by themselves.”