We need a lot more transmission. Here’s why it isn’t getting built

We need a lot more transmission. Here’s why it isn’t getting built
Transmission lines in Tracy, California (Courtesy: Casey Horner)

Episode 72 of the Factor This! podcast features Ari Peskoe, an expert on transmission policy and the director of the Electricity Law Initiative at Harvard. Subscribe wherever you get your podcasts.

Three decades ago, the grid needed organizing.

The Federal Energy Regulatory Commission, or FERC, recommended implementing independent regional operators to manage power markets and facilitate transmission planning.

The resulting six entities — California ISO,  SPP, MISO, PJM, New York ISO, and ISO New England — as well as Texas-regulated ERCOT, have largely succeeded in bringing competition to a power industry that was, previously, wholly controlled by utilities.

To be sure, the foundation for regional transmission organizations (RTOs) and independent system operators (ISOs) was laid long before the energy transition took hold. But today, experts believe the entities deserve some of the blame for the country’s woefully inadequate transmission supply, a critical need amid the shift to distributed clean energy and broad electrification.

And, perhaps more importantly, deference to utility interests has diluted the independence of grid operators, according to Ari Peskoe, the director of Harvard’s Electricity Law Initiative.

Peskoe doesn’t mince words when explaining who he believes is the culprit, as the title of his recently published research paper, “Replacing the Utility Transmission Syndicate’s Control,” plainly suggests.

“If you’re not satisfied with the direction that the industry is heading, you have to look to governance,” Peskoe said on the Factor This! podcast from Renewable Energy World. “Who’s making decisions, why are they making those decisions, and who else ought to be making decisions.”

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So, what’s the big deal? For one thing, ambitious climate targets require new, clean energy resources to connect to the grid. Equally urgent is unprecedented demand growth as electrification expands across the economy.

According to Grid Strategies, U.S. peak demand growth could grow by more than 38 GW through 2028, driven by electrification, along with the development of data centers and industrial and manufacturing facilities.

The report, The Era of Flat Power Demand is Over, cited forecasts from grid planners, who have doubled their five-year load growth forecasts in just the past year. The nationwide demand forecast jumped from a rate of 2.6% to 4.7% growth over the next five years, according to FERC filings.  And those forecasts are likely an underestimate, Grid Strategies said.

Perhaps unsurprisingly, Grid Strategies said the grid is not yet ready for such significant growth. The U.S. installed 1,700 miles of new high-voltage transmission miles per year on average in the first half of the 2010s but that dropped to only 645 miles per year, on average, in the decade’s second half. Low transfer capability between regions is a key risk for reliability if load growth outpaces the deployment of new generation in some regions, the report added.

At the same time, little has changed in the governance structures of RTOs and ISOs since their inception, despite significant societal and technological shifts.

ERCOT control room (Courtesy: ERCOT)

What has changed? Renewable energy now accounts for 20% of U.S. power generation, more than double the supply in 2000. More recently, batteries have begun to replace fossil fuel assets as the grid’s reliability stopgap. Smart devices, software and AI, meanwhile, are bringing intelligence and dynamism only dreamed of when RTOs and ISOs were first recommended by FERC in 1996.

While Peskoe decries a lack of transparency in transmission planning by investor-owned utilities, which he says are emboldened by the light-handed governance of grid operators, his overall concern “goes back to innovation.”

It’s not just wind, solar, and batteries that grab headlines, either. Grid operators have been slow to embrace so-called grid enhancing technologies, GETs — like dynamic line rating and power flow controllers, to name a couple — that could unlock additional capacity from the existing network. FERC, to its credit, issued a rule last year that requires transmission providers to evaluate alternative technologies, like GETs, which can expedite interconnection and lower costs.

Interregional grid connections could go a long way, too, by increasing reliability and supporting the buildout of new clean energy resources.

“In a lot of respects, the US is lagging behind other parts of the world,” Peskoe said. “And again, why is that?” The answer, he said, is governance. “We really don’t have regional governance by the RTO. We have shared governance by both the RTO and the utilities.”

A simultaneous dynamic, and one that’s just as impactful, involves utilities prioritizing transmission buildout within their service territory over regional and interregional projects.

Local transmission projects often involve replacing aging infrastructure. Those projects are easier to permit than new projects, are less expensive and, usually, are more profitable. Regional projects, on the other hand, are tougher to permit and typically involve cost-allocation agreements among neighboring utilities.

But the biggest difference is that grid operators stay out of the local planning process. As a result, Peskoe said, utilities avoid regional projects and meddling by their respective RTO or ISO, which would otherwise trigger broader stakeholder engagement.

Take PJM, for example, which operates the Mid-Atlantic grid that serves all or parts of 13 states and Washington, D.C. Peskoe said PJM takes local utility planning processes as a given and then works to fill gaps in a regional planning process.

By following what amounts to a reactive planning process, PJM, in essence, unnecessarily cedes control over transmission planning to utilities. And, he said, “control of transmission is control over the industry.”

While the industry continues to increase transmission capital expenditures each year, a lot of the focus is on local projects, “much of which is just rebuilding last century’s network,” Peskoe said.

PJM control room (Courtesy: PJM)

Indeed, investor-owned utility investment in transmission to serve new load has decreased over the past three years, according to data from the Edison Electric Institute. In 2021, expansion-related transmission capital expenditures were forecast at $9.2 billion but declined to $8.8 billion for 2023.

A complaint currently before FERC notes that Ohio utilities have invested more than $6 billion in local transmission projects since 2017. And while “supplemental” projects were checked by PJM to ensure they don’t degrade reliability, PJM did not approve the projects as cost-effective or needed to meet consumer demand.

One answer to the problem, in Peskoe’s view, is for grid operators like PJM to utilize the power already granted them by FERC to play a larger role in local and regional transmission planning decisions.

Another is to expand the pool of stakeholders granted so-called filing rights, which allow entities to offer proposals to FERC. Historically, those rights have been reserved for utilities. And FERC on its own is limited in its ability to expand filing rights, requiring Congress to step in.

“Utility regulation is really just about incentives, getting the incentives right,” Peskoe said. “Right now, the incentives are telling utilities that they should favor local investment.”

It’s not all bad news, though.

Industry insiders lauded MISO, the Midwest grid operator, for its collaborative work to approve 18 new transmission projects in 2022. The $10.3 billion investment could result in more than 2,000 miles of new transmission lines and support up to 53 GW of new generating capacity.

Andy Kowalczyk, transmission director for the Southern Renewable Energy Association, remarked at the time on social media that the expansion should serve as “an example that we can still do big things in the U.S. while addressing consumer needs and climate change.”

The Tranche 1 Long Range Transmission Planning portfolio of new transmission projects approved by MISO. (Courtesy: MISO)

MISO’s success is an example of effective regional transmission planning which, unfortunately, has been rare to date, Peskoe added. ISO New England only recently began the process for long-term regional system planning to serve 2050 needs, and PJM has yet to start.

“(MISO) found the secret sauce,” Peskoe said. “It was a really long-term effort with the states and other stakeholders to figure out what actually is the goal, and what are we trying to plan here. I think state involvement in the planning process was critical.”

FERC is taking another stab at regional transmission planning and cost allocation that could prove to be a key development in spurring desperately needed resources.

Back in 2011, FERC issued Order 1000, which required public transmission utilities to participate in regional transmission planning. That largely impacted only vertically integrated utilities in non-RTO regions. The formal planning process has, however, resulted in zero projects in those regions.

The result demonstrates the importance of (truly) independent governance, Peskoe believes.

“Where we don’t have it, we don’t get anything.”

FERC issued a proposed rule in 2022 to require long-term approaches to regional transmission planning, which the regulatory body determined “is necessary for it to meet its legal obligation to ensure just and reasonable rates for transmission service.” The rule would also expand the role of states in cost allocation.

A final rule is expected early this year.

While it may not be obvious, Peskoe said he is optimistic. Transmission has more momentum than ever before. Permitting reform is headlining debates in Congress. And the challenge underlying electrification and demand growth now is the focus of a broad roster of stakeholders.

In the final analysis, Pesloe said, “We have to move beyond your grandfather’s electric grid.”