The Biggest Renewable Bottleneck: Transmission

All the billions going into developing new solar, wind and battery storage projects will not make much of an impact if there is not sufficient transmission capacity to integrate it into the wholesale markets, move it to load centers and ultimately reward the renewable developers for their investments. This is the message that is increasingly being heard in America, Europe and elsewhere as the rush to scale up renewables gains traction. In Mar 2023, the US Department of Energy (DOE) released a draft of its study that highlights America’s transmission needs. The report, to be finalized in the summer of 2023, examines the need for expanded regional transmission lines and interregional transfer capacity under different scenarios. It says 47,000 gigawatt-miles (GW-mi) of high voltage transmission will be needed by 2035, a 57% increase from today’s system, with 120 GW of cumulative additional transfer capacity needed between all regions.

The need will be significantly higher in the more ambitious renewable growth scenarios. The most pressing needs are in the Plains, Midwest, and Texas.

According to the DOE the median required transmission expansion is 115,000 GW-mi by 2040, doubling today’s grid capacity, with 655 GW of interregional transfer capacity — more than 6 times the current capacity. 

The DOE says interregional transmission capacity can significantly reduce the cost of renewable buildout and provide high economic value by enabling electricity imports from regions with excess supply to those with high demand. DOE’s conclusions are echoed by a recent study at the Lawrence Berkeley National Laboratory (LBL) which found that in 2022, single interregional transmission links alone could have saved $2-300 million in multiple locations.  

As previously reported in this newsletter, the current process of getting approval before any new generation resource can be connected to the transmission network is cumbersome, slow and not fit for purpose mostly because lines crossing state boundaries fall under the jurisdiction of the Federal Energy Regulatory Commission (FERC), an agency not known for moving fast, if at all. This forces many utilities and developers to focus on building shorter lines that serve narrow needs and fall within a single state boundary. But that is not what the country needs nor how electrons travel once injected into the high voltage network. They do not recognize FERC’s authority, or state boundaries and move according to the Kirchhoff’s law.

The DOE’s report identifies cost allocation as an area where federal action is urgently needed because who bears the costs of new transmission and who gains from them is a tricky issue which needs to be resolved at a national level in accordance with what is good for the country as a whole rather than the narrow and parochial interests of the constituencies and stakeholders within it.

FERC’s traditional authority to allocate costs to states according to the benefits accrued, however, is currently weak. The US Congress needs to provide FERC with additional powers to act decisively to remove one of the most significant sources of delay, among the many reasons contributing to the long transmission queues.

DOE’s study confirms that regardless of which clean energy scenario materializes, there is an urgent need to build orders of magnitude more transmission in the next decade than in the last. The inadequacies of the transmission network have become a source of irritation for policymakers, investors, system operators, utilities, clean energy advocates, and customers while frustrating state and federal goals of decarbonizing the grid.

Another recent report, the Power from the Prairie Concept Development Study, released in mid-April 2023 envisages a large HVDC Grid that links California, Nevada, Utah, Wyoming, Colorado, Montana, Nebraska, South Dakota, North Dakota, Minnesota, Manitoba, Iowa, Wisconsin, and Illinois. Its main aim is to move the region’s ample wind and solar resources to major markets who need the power to the west and the east.

The study which covers vast expanse of the country including WECC, SPP, PJM, and MISO identified the need for an Inter-regional Transmission Operator (IRTO)that would operate the inter-regional transmission that links Balancing Areas and ISO/RTO systems. The current balkanized system is not well-suited to operating such as expanded region. According to Fredric Fletcher of the Power from the Prairie who posted a blog on the Electricity Brain Trust (EBT), a professional networking site,

“Each current system claims that it is capable to operate such an inter-regional system, but it gets absurd to think CAISO will operate a 4000 MW HVDC converter just outside of Chicago, or that PJM will operate the interconnections near Hoover, Las Vegas, Salt Lake, Wyoming, and Denver.”

There needs to be a single operator who is dedicated to inter-regional system operations – similar to those operating in Europe. Moreover, the IRTO must be capable of working with large and small distributed energy resources (DERs) as well as emerging microgrids. Given its large footprint, the system analyzed in the study enabled 12,000 MW of additional renewables to be added to the network, roughly equal amounts of solar and wind with benefit/cost ratios of 0.9 to 1.3.  

If any further evidence was needed on the multitude of problems associated with lack of adequate transmission capacity, the Lawrence Berkeley National Laboratory (LBL) released its latest report on the SPP in late April 2023, the fourth in a series. Prior studies covered MISO, PJM, and NYISO with a forthcoming study covering ISO New England to follow soon.

The message of the latest report is nearly identical to the others.  At year-end 2022, SPP had 109 GW of generation and storage capacity actively seeking grid interconnection. As is common everywhere, the bulk of the capacity in SPP’s queue, 96%, is solar and solar hybrids (51 GW), wind (35 GW), and standalone storage (13 GW). 

Not surprisingly, the SPP’s queue has ballooned over the past decade with the cumulative active queue more than 5 times larger than in 2013. Another indicator of the problem is that the requests for transmission connections in 2022 were nearly 3 times those of 2021. The total capacity with interconnection requests is more than twice as large as SPP’s peak load of around 51 GW.

To address the backlog, the SPP initiated interconnection process reforms in 2009 by transitioning to a clustered, “first-ready, first-served” approach while increasing project deposits and readiness criteria. Yet despite these and other reforms SPP’s active queue interconnection wait times have increased steadily to nearly 6 years.

With data from 845 projects covering the period to March 2023, the LBL analyzed interconnection costs for three types of projects:

• Those that have completed all required studies including plants in service;
• Those actively working through the study process; and
• Those that have withdrawn from the queue.

The analysis found that

• Costs for recent complete projects (2020-2022: $57/kW) are largely unchanged from the 2000s (2002-2009: $54/kW), though they were slightly lower in the 2010s ($43/kW);
• Interconnection requests that withdraw from the queue saw large cost escalations in the 2010s (from $22/kW in the 2000s to $247/kW) and continued to climb in the early 2020s to $304/kW; and
• Projects still working their way through the queue have average costs of $106/kW in 2020-2023.

Average costs for withdrawn projects are currently 5 times the costs of complete projects, likely a key driver for those withdrawals.

The LBL report concluded that network upgrade costs are the primary driver of recent cost increases, especially for withdrawn projects; they have recently increased on average to $23/kW. For withdrawn projects, these network costs grew strongly in the 2010s ($180/kW) and continued to climb for some in the 2020s ($230/kW). Recent active projects had intermediate costs for network upgrades ($58/kW).

Partly in response to the higher costs and longer waits, some generators have reverted to seeking interconnection services as an energy instead of a capacity resource, which means that they forfeit preferential treatment during high load hours, cannot participate in SPP’s resource adequacy market and may face increased curtailment.

Potential interconnection costs of all solar ($157/kW) and wind ($154/kW) requests have been greater than those of storage ($109/kW) and natural gas ($97/kW).

Among completed projects recent interconnection costs for solar ($99/kW) and natural gas ($53/kW) have increased compared to historical costs, while wind costs have decreased ($43/kW). Solar projects that ultimately withdrew had interconnection costs of $394/kW, equivalent to 25% of total project installed costs, compared to $263/kW or 17%) for withdrawn wind applicants.

Another recent report by Grid Strategies, a consulting firm, concluded that congestion costs on the US grid more than doubled to an estimated $13.3 billion in 2021 from the year before, and according to Rob Gramlich, Grid Strategies’ president it will keep rising until more transmission capacity is built. The Midcontinent Independent System Operator (MISO) had the highest congestion costs at $2.85 billion in 2021, followed by the Electric Reliability Council of Texas (ERCOT) at $2.1 billion and the Southwest Power Pool (SPP) at $1.2 billion.

The overwhelming message that comes from the above studies in the US – and similar ones in Europe and Australia, who are equally eager to decarbonize their grids – is that lack of adequate transmission has become the most acute bottleneck, slowing the pace of progress more than anything else.

Recently, TenneT, a transmission system operator for Germany and the Netherlands proposed Target Grid, a network of DC superhighways and an AC grid connecting major energy hubs while enabling more renewable electricity to be transported across long distances from the North Sea to consumers and industry in the middle and south of Germany.

In the case of the US, the obvious remedies include:

• An overhaul of the FERC’s cumbersome approval and cost allocation process including efforts to bundle multiple projects into a bundle and discouraging speculative applications that prolongs the queues while making it more expensive for the serious contenders;
• Moving towards Inter-regional Transmission Operator (IRTO) concept given the large interconnected markets that can no longer be managed by a single grid operator; and
• Radical out-of-the-box solutions – such as microgrids mostly supplied with local generation and serving local loads operating within macrogrids.

If the old ways of doing things no longer work, perhaps the time has arrived for trying something different.

This article originally appeared in the June 2022 issue of EEnergy Informer, a monthly newsletter edited by Fereidoon Sioshansi who may be reached at [email protected].

DOE study

https://www.energy.gov/gdo/national-transmission-needs-study

Power from the Prairie

https://www.powerfromtheprairie.com/the-cds

LBL report

https://eta-publications.lbl.gov/sites/default/files/berkeley_lab_2023.04.20-_spp_interconnection_costs.pdf

https://www.utilitydive.com/news/grid-congestion-cost-transmission-grid-strategies-report/647668/