By Rich Heidorn Jr.

WASHINGTON — FERC has been asking questions about improving the transmission interconnection process for eight years.

“There will be a point where we stop asking questions,” FERC’s Arnie Quinn promised during a panel discussion at the Energy Bar Association’s Annual Meeting last week.

That point will come after the commission reviews the transcript of last month’s technical conference on the subject and the post-conference comments it is now soliciting.

The commission’s questions started in 2008, when it asked the RTOs to make proposals to reduce interconnection backlogs (AD08-2). The grid operators offered a number of changes, including clustering interconnection studies by location and establishing development milestones to weed out projects not progressing toward commercial development.

But the changes haven’t ended developers’ complaints about study delays or the difficulty in predicting interconnection costs. At the technical conference, transmission operators countered that the delays are caused by the high number of speculative interconnection requests, which force them to conduct restudies when a project drops out of the queue. (See Generators, Tx Operators Spar over Interconnection Processes Before FERC.)

Post-conference comments are due June 20 (RM16-12, RM15-21).

After that, the commission could respond with a prescriptive rulemaking, a policy statement — which wouldn’t require transmission operators to make any changes — or a hybrid of the two, said Quinn, director of FERC’s Office of Energy Policy and Innovation.

“The difficulty with this topic … is it’s fairly straightforward to define the problem,” Quinn said. “Identifying the solutions that are going to work everyplace — that’s the harder nut to crack.”

Incremental, Comprehensive Changes Sought

Last month’s conference was called in response to a rulemaking request by the American Wind Energy Association, which argued that existing interconnection rules are outdated and discriminatory.

Panel moderator John Moore, of the Natural Resources Defense Council, opened the EBA session last week by quoting from Invenergy’s testimony at the conference, in which the company related its experiences on the length of the interconnection processes: SPP (one year); PJM (two years); CAISO (two and a half years); MISO (“has seldom taken less than three years”); and NYISO (as long as six to seven years). “An interconnection process lasting three years or more can kill even the most serious of projects,” Invenergy’s Kris Zadlo said.

Quinn said he concluded from the conference testimony that developers are seeking both incremental improvements — including more access to models and the ability to self-construct interconnection facilities — and more comprehensive changes.

The comprehensive proposals are more controversial, Quinn said, citing a call for closer coordination between the transmission planning and the interconnection processes. “Instead of serially studying a bunch of projects over time, just identify an area on the transmission system where you’ll need some upgrades. Using the transmission planning process to do that might smooth the interconnection process,” Quinn explained.

The controversy? “Transmission is usually paid for by load; interconnection upgrades are typically paid for by the interconnection customers. So that can look like a cost shift, and — especially where the states are involved — they might want a say in the degree to which that cost shift occurs,” Quinn continued.

Another suggestion is to cap interconnection cost estimates at an early stage in the interconnection process, as CAISO is doing. “If the interconnection customer can get some information on cost that can feel firm, the interconnection customer can keep moving on,” Quinn said.

Panelist Mason Emnett, a federal regulatory attorney for NextEra Energy, had his own wish list. He said he would like RTOs to provide developers with information on their overloaded facilities. “Our transmission engineers can use that to go back to developers to give them a reality check and say, ‘This is what you’re facing.’”

Storage

Emnett also called for refinements in the modeling of storage resources. “RTOs generally consider the storage to be operating at full output — full discharge — at the worst time of the system, which generally is not going to be the time that the storage asset is operating that way.”

But he said storage doesn’t need an entirely separate process, either. “Nobody really loves [the current process]. The TOs don’t, the RTOs don’t, the generators don’t. But I’m not sure how you come up with a different one for storage because the question that’s being answered is largely the same: Are you changing the nature of the flows on the system? And what [is] the technical configuration of the equipment that you’re interconnecting and how does that interact with other things?”

More Flexibility Needed

Emnett said RTOs should provide more flexibility, praising MISO’s “net zero” policy.

“We’ve put some batteries on existing wind sites that had excess interconnection rights so that interconnection rights had already been studied at a certain level but they weren’t being fully utilized. In our mind, why can’t you just stick another resource on? You don’t have to go through the full study because all you’re using is something you’ve already got.”

He also cited PJM policy allowing interconnection customers to install more capacity than it has in injection rights. The interconnection service agreement requires that the customer limit its output. “If you burn down my wires you are responsible for everything,” Emnett said, summarizing.

Even if it requires a special protection scheme, Emnett said, “it’s going to be, in all likelihood, less expensive than upgrades and able to be implemented much more timely than the two and a half years to get a 10-MW storage project” approved.

Standardizing the Process

The panel also discussed whether the commission should order more standardization in the grid operators’ interconnection processes.

“I hope FERC will allow regional differences,” said panelist Tim Aliff, MISO’s director of reliability planning. He noted the RTO operates in 13 states. “So we have 13 different opinions of how things should be done.”

Aliff also responded to Invenergy’s description of interconnection timelines. “I do take exception to the [assertion that MISO takes] ‘no less than three years’ because it depends on where you are in our footprint,” he said.

In March, FERC rejected the RTO’s proposed changes to its queue process, saying they assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). The commission also said a proposed milestone payment could create barriers to entry for smaller developers. (See MISO Queue Changes on Hold Pending Technical Conference.)

Aliff said that in addition to working on revisions to its proposal, MISO is considering how it can accommodate additional wind growth.

In 2011, MISO approved multi-value projects (MVPs) designed to serve 26 GW of wind. The RTO has 15 GW of installed wind and another 10 GW in the queue.

“So if all of this generation were to interconnect and actually start generating, then we would be at the capacity or close to the capacity of our MVPs,” he said. “So now we’re kicking off the process to say what’s the next step in this? We may or may not come out with MVP-like projects, but we want to get ahead of [the demand] again. We want to look at what the Clean Power Plan is going to do.”