ARLINGTON, Va. — The electric industry must improve its long-term planning to account for a changing generation mix and new load patterns, experts at Infocast’s Transmission & Interconnection Summit said Tuesday.

While MISO’s long-range transmission planning and California ISO’s 20-year transmission outlook both stand out as exceptions, the industry generally does not think far ahead when it comes to grid planning, Grid Strategies President Rob Gramlich said at the summit. (See MISO Board Approves $10B in Long-range Tx Projects.)

But FERC’s Notice of Proposed Rulemaking requiring the industry to adopt long-range, scenario-based planning has started to change that. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“I think the push has been helpful in the establishment of a sort of a vision that you should be proactively looking at the anticipated future resource mix and … the load forecast. And both of those things are, of course, uncertain, but the industry has had to deal with that for its entire history,” Gramlich said.

The uncertainty can be addressed by using scenarios to determine the best transmission options to link future supply and demand. While that would be the ideal, most of the country is not doing that even at the regional level, Gramlich said.

“What happens then is all the pressure for the limited capacity goes into the interconnection process,” Gramlich said. “And it’s a self-reinforcing downward spiral of studies and re-studies and queue churn — and all of those things that can be greatly alleviated if we had the infrastructure.”

In SPP’s 2021 interconnection process, most interconnecting resources were saddled with more than $1 million in transmission upgrade costs — often for lines rated at 345 kV and above, said ICF Vice President Himali Parmar.

“That clearly tells you that the system — the planning process — is broken somewhere in SPP,” she added.

Stuart Nachmias, CEO of Con Edison Transmission, agreed that the transmission planning process needs to start looking ahead to a grid dominated by renewables and responsible for the electrification of both transportation, which has already started, and heating, which he said is not far behind.

“There is much more robust planning process that we need. We need to identify the transmission … and distribution that needs to be expanded to meet the future needs,” Nachmias said. “Because the one thing I know for sure is that the day reliability is not what customers expect is the day that everything comes to a standstill. And none of us want that to happen.”

The industry has a spotty record when it comes to planning lines required to meet public policy mandates, but FERC could be doing more under existing rules to make that more common, said Sharon Segner, senior vice president of transmission policy at LS Power.

“There’s whole sections of the PJM operating agreement that are not being enforced right now relating to public policy planning and requirements,” Segner said. “And there’s more than this FERC could be doing under existing law.”

PJM’s Order 1000 compliance rules call for the RTO to perform an annual sensitivity analysis on public policy transmission requirements, which are not being used, she added.

Transmission planning processes were all designed around slow and deliberate change to the power system, but bigger changes are coming now, said Kris Zadlo, chief commercial and technology officer at Grid United.

The “institutional framework” was “set up for something that was relatively static,” Zadlo said. “And now we don’t have a very static system, the system is changing in front of our eyes, and the whole planning process must adapt accordingly.”

An increase in computing power has made planning much quicker. Where it once took hours for a mainframe to process one power flow, modern machines can now go through thousands of scenarios across an interconnection in just hours, Zadlo said. That extra analysis has led to paralysis: Instead of focusing on so many options, transmission planners should pick the best plan and move forward with it, he added.

At the request of New England states, ISO-NE started to plan further into the future with its 2050 study, in which the states helped identify what resources would be developed and how load would grow in response to their policies, said Maine PUC Chair Philip Bartlett II. (See ISO-NE Planners Outline Potential Solutions for 2050 Tx Overloads.)

Bartlett said state officials hope the change will ensure the region can “right-size” investments in larger projects that improve efficiencies. “Because the only way we’re going to get through this transition cost-effectively is if we think thoughtfully, we don’t miss opportunities for lower-cost upgrades, and we avoid some of the expensive costs down the road by making smarter decisions through our planning today.”

While New England has spent plenty on transmission in recent years, the spending has been directed at curing reliability issues, and not nearly enough has gone to help states meet long-term policy goals, he added.

PJM is also spending on transmission now, but its process often favors local projects that lack outside scrutiny, said Greg Poulos, executive director of the Consumer Advocates of the PJM States.

“We pay a lot of money for local transmission, and the local transmission process doesn’t typically allow for any oversight,” Poulos said.

Coordinating policies can be challenging in both RTOs. PJM states have a wide range of policy goals, while in ISO-NE, one state has no climate goals, while many others call for net-zero emissions by midcentury.

But transmission provides other benefits for all states, from improving reliability and resiliency to reducing emissions covered by existing federal laws, Bartlett said. The key to getting needed transmission built regardless of state policy differences is to define those benefits and allocate associated costs in a way that achieves agreement, he said.

By using separate planning processes to meet different goals, RTOs dilute the value of the kind of multipurpose transmission lines that are often praised as most effective, said Matthew Crosby, senior director of policy and strategy at Cypress Creek Renewables.

“There’s a clear need to look at the sequencing of these tests,” Crosby said. “And right now, without someone that’s independent of the transmission owner, or the regional transmission operators, enforcing that and guiding that process — I’m not sure how we disrupt the status quo.”

That role could be filled by an “independent transmission monitor,” an idea FERC floated in its advanced NOPR on transmission but that did not make the cut in its planning NOPR. Reliability often takes precedence because the issues need to be fixed quickly and a multivalue planning process takes longer, but Crosby suggested some of those issues could be dealt with using grid-enhancing technologies while giving planners enough time to come up with more efficient, long-term transmission fixes.

State Perspectives

In states participating in organized markets, grid planning is typically led by the RTO, but that seems to be changing, as FERC and ISO-NE have started to recognize that states should lead when it comes to planning lines for policies, said Vermont Public Utility Commissioner Riley Allen. States in his region are represented by the New England States Committee on Electricity (NESCOE), which gives them a cohesive voice on RTO issues.

NESCOE should be able to come up with a plan to build out the grid regionally to meet its members’ policies, both through the ISO-NE’s 2050 outlook and nearer-term planning, Allen said.

“Something that is relatively robust and amounts to a more postage stamp-type framework is probably preferable over time to kind of a state-by-state approach and addressing some of the challenges associated with that,” Allen said.

Allen sits on the Joint Federal-State Task Force on Electric Transmission with North Carolina Utilities Commissioner Kimberly Duffley, who said the Order 1000 process is working in the Southeast without resulting in capital flight to local projects with less oversight, which she attributed to her agency’s robust IRP process. (See Federal and State Regulators Look into How to Improve Grid Security.)

“If you do this type of top-down approach of transmission planning in non-RTO regions, you really are infringing upon the state’s resource planning that they’re doing where the state is looking at transmission, as well as generation, for solutions to meet the goals in a least-cost manner,” Duffley said.

Her state also has a robust transmission siting process, issuing certificates of public convenience and necessity in a process where the commission’s “public staff,” which represents state residents, can intervene to oppose unneeded projects. Another major difference is that North Carolina utilities can recover 70% of their transmission costs in retail rates, so FERC does not even control most of the funding.

Colorado is considering joining an RTO, but in 2021 it created the Colorado Electric Transmission Authority (CETA) to facilitate development of new transmission, said the agency’s Kathleen Staks.

CETA was established by the same bill directing the state’s utilities to join an RTO by 2030, so it was conceived to consider the broader regional perspective of better connecting the state with the rest of the West, Staks said.

Colorado modeled CETA on New Mexico’s Renewable Energy Transmission Authority, which helped clear the way for approval of Pattern Energy’s Sunzia line, which was designed to bring New Mexican wind output to markets further west, Staks said. (See Sunzia Project Wins Final Approval, Signs Offtakers.)

DOE Sees State Collaboration as Key

While the U.S. Department of Energy has limited authority to designate National Interest Electric Transmission Corridors, it will be increasingly important for it to collaborate with states as it studies the issue of transmission buildout, according to Jeff Dennis, deputy director for transmission at the agency’s Grid Deployment Office.

The nascent offshore wind industry could benefit from such a collaboration. The sector is currently driven by state contracts and dominated by an inefficient radial approach to transmission, where each project runs its own connection to the onshore grid. But that approach won’t scale as more projects get built, Dennis said.

DOE has been working on recommendations to help expand the industry, including getting Atlantic states to collaborate on a networked transmission system and share the costs.

“The obvious example is landing points, right?” Dennis said. “If we continue this radial approach, we’re going to impact lots of communities. We’re going to impact lots of offshore industries outside of energy, like fisheries.”

Offshore wind’s most obvious impacts are along the coast, but the resource will require an expansion of the onshore grid that will impact even inland states such as Vermont, he added.

“We’re not the regulator, of course, so that gives us some opportunities, I think, to provide support to collaboration [and] to try and provide good information that will help the states in those collaborations make decisions collectively,” Dennis said.