Congress passed the Infrastructure Investment and Jobs Act in November that includes $65 billion for grid infrastructure and $50 billion more for cybersecurity and climate measures. A seemingly endless host of stakeholders has priorities for the programs that will ensue in the electric sector.
There are three strong possibilities as we embark on an unprecedented period of electric infrastructure investment in an economy experiencing inflation: electricity costs will rise (related to the Act or not), utilities will receive some of the blame (warranted or not), and customers will be hard-pressed to ignore short-term electric bill pain in anticipation of long-term improvements in service, quality, cost and other attributes such as sustainability. Can electric power stakeholders mitigate cost increases and disruptions to the grid through this period of change?
Many parties agree new transmission is needed to support increased wind and solar integration. Transmission siting, approval and construction are long lead processes, and history indicates changing how we conduct these activities can be drawn out as well. There are measures utilities can focus on now to maintain grid performance as we strain to accommodate a varied and growing resource mix prior to major transmission expansion. The Eastern Interconnection Planning Collaborative (EIPC), composed of transmission planning coordinators responsible for the bulk power grid throughout the Eastern Interconnection, has identified such measures.
EPIC reports that the retirement of legacy synchronous generators with strong transmission ties has decreased grid performance including steady-state thermal loading, voltage stability and transient stability. Utilities in areas with high DER activity and elsewhere are addressing these impacts by taking measures ranging from increased grid monitoring to implementing distribution automation protocols and even systemwide advanced distribution management systems. According to EPIC, utilities in the Eastern Interconnection serving two-thirds of the U.S. and Canada also need to conduct more sophisticated modeling to evaluate: changes in load composition and reserve requirements due to the addition of DERs; the effects of weather on variable resources; and how the changing mix of resources will affect system events. The Act contains over $6 billion for electric grid reliability and resilience research, development, and demonstration, but utilities must deliver reliable and cost-effective service now while that work is underway.
To facilitate new transmission development, the Act gives FERC broader transmission siting authority for new power line build-outs located along national interest transmission corridors. The corridors will be designated by a new Department of Energy Grid Deployment Authority in regions where it deems the public will benefit from additional transmission to relieve congestion and address other factors such as supply requirements. The Act also provides that the DOE can become an anchor tenant in new power lines like the process for justifying new gas transmission pipelines.
Aspects of the Act’s transmission siting provisions are reminiscent of FERC Order 1000. That order was passed in 2011 to overhaul transmission planning, cost allocation and competitive bidding for new projects. A cross section of parties were not satisfied with the results of Order 1000, and it is unclear whether sticking points, such as open competitive bidding, cost allocation, property rights, land use, and environmental impacts, will be solved with the new law. What appears inevitable is the collective time frame for awarding grants, conducting research, performing siting proceedings, and authorizing and constructing new transmission, as contemplated by the Act, may be a decade or longer.
This past July, FERC opened a proceeding to investigate how it can overhaul federal transmission policy, creating some hope that shorter term transmission related fixes may be possible. One issue several FERC commissioners sited as ripe for review is the interconnection review process. Many regions have huge backlogs, and a common criticism is a lack of standardized performance requirements for renewable resources with inverter-based control systems. A resolution in this one area could improve the approval process for new projects, and the performance expectations for existing plants, providing some relief during a comprehensive transmission overhaul and expansion.
A major goal of the Act is to increase access to renewable energy, while maintaining the reliability, efficiency, and affordability of electricity. Significant R&D spending and the replacement of depreciated infrastructure with new will challenge the ability of utilities to avoid rate increases. However, there are reasons to expect that long-term electric costs can be controlled. First, reported transmission congestion costs which amount to billions of dollars per year could be significantly reduced with strategic transmission additions. Second, increased competition resulting from more generators on our networks should help lower electricity costs based on experience. Now, regulators, grid operators, utilities, DERs and other stakeholders simply need to work collaboratively to expeditiously achieve the long-term benefits of increased electric infrastructure investment, including maintaining reliable service on an increasingly complex grid and reasonable rates.