Rob Gramlich, president of Grid Strategies, has a simple explanation for why U.S. transmission grid policy has stalled the growth of wind and solar power.
“If you talk to a developer, they will say [that] the grid operators and transmission owners are woefully slow and unpredictable in terms of what it costs to connect, and the process is extremely frustrating,” he said in a Monday interview.
“If you talk to the grid operators, they’ll say, 'Renewables developers keep throwing in different projects, [so] I have to study each of them — and when I give them an answer, they drop out of the queue and I have to go back and study everything else.'”
“They’re both right — and it’s because we have a systemic problem,” said Gramlich, co-author of a new report, Disconnected: The Need for a New Generator Interconnection Policy. Despite incremental attempts by the country’s major interstate transmission operators to solve these problems, Gramlich and his colleagues felt they “had to point out how everybody’s working in a fundamentally broken system.”
These observations are backed up by a rising tide of evidence from clean-energy advocates and academic research indicating that attempts to decarbonize the U.S. electricity system may be stymied by a lack of transmission to carry wind and solar power from where it’s most cheaply generated to where it’s most needed.
The fundamental disconnect stems from Federal Energy Regulatory Commission Order 2003, created in the same year, which allows independent system operators (ISOs) and regional transmission organizations (RTOs) to hold developers of new generation facilities responsible for the costs of upgrades needed to interconnect their projects to the transmission grid.
The purpose was to avoid cost-sharing structures to force the cost of connecting new generators onto the broad base of utilities and customers. That made sense when the primary new resource being added to the grid was large-scale natural-gas generators that could be sited at the most advantageous interconnection locations.
But it has become a major problem as wind and solar projects, which tend to be most productive in far-away locations, have come to make up about 90 percent of new interconnection requests in the queues of the ISOs and RTOs that manage the transmission networks that provide electricity to about two-thirds of the country’s population.
Transmission upgrade costs are killing renewables projects
Average network upgrade charges have grown from about 10 percent of total project costs a few years ago to as much as 50 to 100 percent of those costs today, according to data from Lawrence Berkeley National Laboratory and input from multiple ISOs and RTOs.
In the western subregion of the Midcontinent Independent System Operator (MISO), assigned network costs have grown from about $300 per kilowatt-hour in 2015 to nearly $1,000 per kWh in 2017. Southwest Power Pool (SPP) has seen these costs rise from an average of $89 per kilowatt in 2013 to close to $600 per kW in 2017, and similar increases, though not quite as large, have occurred in New York ISO and mid-Atlantic grid operator PJM.
These generator interconnection studies end up forcing costs onto whichever project at the front of the interconnection queue ends up triggering the need for grid upgrades, Gramlich explained. When that project drops out under the weight of those costs, grid operators must redo their interconnection studies with the new mix of projects, leaving the next one in the queue to face the cost burden and drop out, and so on.
The results have been dire for many developers. MISO’s western region has seen nearly all of the 5 gigawatts of renewable energy projects in its queue drop out in the past two years, despite having already secured power-purchase agreements, the report states. The last remaining project, consisting of 200 megawatts of wind and 50 MW of solar, faces about $500 million in upgrade costs.
All the while, months of grid studies turn into years, the queue of projects seeking interconnection continues to grow, and the cost of upgrading the transmission system at large continues to balloon.
This approach is like trying to “put the whole cost of the highway lane extension on the next car on the road,” Gramlich said. “Clearly the better way is to plan the size of the road based on expected future use of all the cars that will be coming.”
That’s increasingly important as the wind, solar and energy storage projects continue to fall in cost, making them the cheapest as well as the cleanest option, and as states and utilities are setting decarbonization goals that will require much more rapid interconnection of renewables than has happened in the past.
Looking for integrated, future-forward transmission policies
ISOs and RTOs have taken on several reform efforts over the past decade to relieve this problem, from instituting “cluster studies” that address grid planning for multiple projects at once, to setting milestones to differentiate “placeholder” projects in queues from those with significant investor and offtaker support. In 2018, FERC Order 845 instituted many queue interconnection procedures proposed by wind energy advocates.
But Gramlich and Grid Strategies VP Jay Caspary contend that these reforms don’t go deep enough. What’s needed, they said, is a new regulatory structure to allow transmission-owning utilities, grid operators and regulators in the states within their grid footprints to plan and share the costs of grid build-outs to accommodate future growth and the projects now in interconnection queues.
There are examples of this kind of forward-thinking grid development effort from the past decade, he noted. Examples include Texas’ CREZ policy, MISO’s MVP process and SPP's designation of “priority” projects.
“All of them had a similar formula: long-term, proactive planning based on expected future use, considering all the multiple needs and benefits, and then spreading the costs broadly to all of those who benefit,” Gramlich said. While they were costly and complicated, the end results have been increased generation and cheaper electricity, with benefits outweighing costs by 50 percent to 350 percent, according to grid operator analysis.
“There were a lot of magic moments when everyone saw the need for a big portfolio of projects” to help bring low-cost power to market, said Caspary, a co-author of the new report. But regionally planned transmission investment has dropped by half since 2010 as these efforts concluded and no new undertakings were initiated to take their place.
What’s the solution to this impasse? That’s the subject of an upcoming report from the same authors, but Gramlich insists that FERC, which sets policies for the country’s grid operators, “has ample authority to make sure that reasonable forecasts of the future resource mix can be incorporated into plans, not just as a scenario to study, but as the core base plan.”
“Utilities have publicly stated commitments to retiring some resources and developing others,” he said. “Just like utility planners plan for load growth, which is uncertain but something you can estimate, they should also be using reasonable estimates of the future system.”
He added that this kind of planning and cost-sharing may well be more important for spurring transmission growth than finding ways to surmount the legal challenges from government agencies, private landowners and environmental groups that have stalled many high-profile projects in the past decade.
“Permitting certainly can be a barrier — but SPP, MISO and ERCOT all built a tremendous amount of transmission,” he said. “It can be done.”