Electric Utility Reform in an Age of Electrification

This article presents some policy priorities and recommendations for the reform of the electric utility sector in the United States. These recommendations focus on state-level actions that can be taken now to accelerate the modernization of the grid while saving billions of dollars and protecting consumers from rate increases. These include using innovative techniques to unblock large-scale generator connections and transmission upgrades, lowering adoption barriers and soft costs for small-scale projects, harnessing flexibility to reduce the need for distribution upgrades, and reforming the Investor-Owned Utility (IOU) business model using a shared-savings approach.

The utility business model

Policymakers, regulators, and utilities have created one of the largest and most impressive modern machines in the electric grid. However, the system that delivers electricity to customers needs to be redesigned for a cleaner and more resilient power grid. The electric grid is composed of the transmission system and the distribution system. The transmission system is the high-voltage and high-capacity network that moves large amounts of power between and within states. The distribution system was traditionally the system that received power from transmission and delivered it to customers. Both systems are experiencing significant change and require investment. The need for regulatory reform of transmission and distribution utilities has been outlined elsewhere. This article focuses on the IOU business model, which is dominant in the United States.

It is important to understand that IOUs are regulated monopolies that must offer universal service to customers, something that sets them apart from typical commercial companies. Their revenues are determined by the costs of service they provide plus a return on the capital that they deploy, which means these revenues are largely determined by the wires, poles, transformers, and other equipment the utility installs. As a result, the IOU has an incentive to keep building new grid infrastructure, which is the main driver of revenue and profit. As a regulated monopoly, the IOU earns profit on equity at a rate of return agreed to with its regulator. In the U.S., that rate is generally around 10%, which is applied to its entire asset base. This means that if the IOU owns $1 billion of assets, it can potentially bill for up to $100 million each year as profit. Across the country, this profit accounts for between 6% and 10% of a customer’s bill. Because utility profit is not directly itemized on the bill but is embedded within the electric rates approved by the regulator, it’s not readily apparent to customers; your utility bill typically includes the costs of transmission and distribution infrastructure, plus the additional costs that are directly passed through by the IOUs, including paying generators for supply, and various fees, taxes, and programs. As a consequence, the IOU has no incentive to find ways to reduce the total customer bill.

IOU revenues and rate of return are being questioned at both ends of the political spectrum. In some cases, it has been suggested that utility returns need to be more effectively aligned to the cost of capital; in others, at the same rate of return as a treasury note. A new approach is needed to protect consumers from price increases, particularly those from low- and medium-income areas who cannot afford or access new DER technologies. The rates that IOUs charge their customers have risen 49% more than inflation in the last three years, while municipal or cooperative utilities have gone up at less than half the rate of inflation. Municipal and cooperative utilities are typically nonprofits and have a justifiably lower cost basis than IOUs. While the IOUs are often on the receiving end of blame for these higher rate increases, the problem is more fundamental: The overall system is failing to protect consumers from rate increases and needs to change.

Absent a real change to the status quo, the next-generation clean-energy grid we are building will be more capital intensive, more expensive, and less innovative than it should be. We need to harness the capabilities of new technologies and reform the way the system is planned and operates to include them. Without this, we may achieve our clean-energy objectives but at a considerably higher economic cost that is borne by consumers. 

Priorities for reform

• Use “connect and manage” and focus on strategic transmission projects
  The transmission system across the U.S. needs to be strengthened and upgraded. Severe weather, decommissioning power plants, new generator connections, new storage connections, and new loads (i.e., data centers harnessing the AI boom) are all pushing the system to a breaking point. Transmission-grid infrastructure typically takes at least 10 years to build in the U.S., while applications for new generator connections totaling twice the current installed generation capacity of the U.S. are already backed up waiting for this new capacity. States should be implementing policy that requires a “connect and manage” approach, ahead of upgrading the system. This has proven successful in Texas (and in the United Kingdom and Europe), where generators have the option to accept curtailment risk, i.e., the loss of generation export at times when the grid cannot accept it. In addition, FERC Order 1000 requires local and regional transmission-grid planning processes to take account of public policy requirements. This led to the State Agreement Approach (SAA) being implemented within the PJM territory (a regional transmission organization that oversees the wholesale electricity market across 13 states) to incorporate New Jersey’s 7,500 megawatt offshore wind target into PJM’s regional transmission planning process. A similar approach should be adopted in other states to enable strategic transmission investments while also implementing “connect and manage” to release the backlog of generation projects currently in the queues. “Connect and manage” will provide the added benefit of clarifying the highest-value upgrades to reduce curtailment once it is clear which generation projects from the queue will be built.
  
  It is crucial that in addition to “connect and manage,” Grid Enhancing Technologies (GETs) are implemented to provide additional capacity on existing lines. States should also require regional planning processes to deliver strategic upgrades and consider High-Voltage Direct Current (HVDC) technology to integrate the nation’s transmission grid; as of 2021 China has installed 253 gigawatts of HVDC systems, whereas the U.S. has installed 20 gigawatts. HVDC can move power across the nation more efficiently and with more controllability, which will be beneficial when connecting the three transmission systems (Eastern Interconnect, Western Interconnect, and Texas Interconnect) to each other. Utilities have limited capacity for construction projects, and it is critical that construction resources be spent on building the backbone of the nation’s electric infrastructure. These projects should be prioritized if we are to share the benefits of different generation sources and profiles across the country.
  
   

• Lower administrative barriers and soft costs for technology adopters 
  The costs of solar panels, electric vehicles, or any other DER solution, are not within the control of individual states. However, permitting and local ordinances can present significant complexity and cost to those looking to adopt DER or develop sites for renewable energy. Soft costs, which include these costs and others, are not typically falling as quickly as hardware costs. It has been estimated that the cost of solar installation in the United States can be two-to-three times greater than in other advanced energy economies due to outdated paperwork approaches. Automating the application processes for permits and approvals, and reducing unnecessary bureaucratic and regulatory obstacles would significantly speed up timelines and reduce the costs borne by homeowners and commercial applicants alike.

  Another initiative that would enable the market to more easily provide customers with a range of technology and bill savings opportunities is to make it easier for vendors and specialists to access web-based electric rates. The current electric rates and their historic variations should be provided via web services and made available for download. Electric rates are extremely complicated in many areas and typically only published periodically in documents online, making it very difficult to provide consumers clear answers about how much they can save by adopting new technologies, such as converting from gas heating to an electric heat pump or understanding their bill with and without solar panels and/or an electric vehicle. Transparent, accessible rate information would allow consumers to make these decisions much more quickly and with confidence, and would increase the rate of adoption of new cost-saving clean technologies.

  For larger projects, the grid connection process needs to speed up to reduce the soft costs and uncertainty for generator applications. In one significant case, a utility was fined $1 million for simply failing to meet deadlines for processing applications. At the transmission level, we are beginning to see AI used to solve the interconnection backlog, but there also needs to be a change in the way the planning studies are performed to include “connect and manage” options, as discussed in the previous section.
  
  

• Harness flexibility to reduce the need for distribution grid upgrades
  The current grid is planned and built to handle peak load during one or more contingencies, typically experiencing 80 to 90 hours a year under stress. An analogy for how the grid is managed is to consider a two-lane highway. Imagine that, in order to limit the risk of a very bad traffic jam, the highway were never allowed more traffic than one lane could carry, on the theory that if one lane is lost, everyone can keep moving and nobody’s journey is impacted. If demand grows over time, the only way to accommodate it would be to build another lane, so that now it is a three-lane highway. This is in essence how the capacity is managed on the American electric grid. In practice, this means a large amount of grid capacity goes unused, reserved only to support reliability during outages. This approach made sense when the system was originally built, since it delivers a highly reliable system when power is flowing one way from a smaller number of large generators to customers, but it fails to capture the value and opportunity presented by DER, electrification, and new technology. The result is a core IOU business model that encourages IOUs to build more grid infrastructure as opposed to enabling customer technology solutions that are cheaper, faster, and less disruptive to the communities they serve.
  
  There are clear alternatives. Non-Wires Solutions (NWS) take a different approach to grid upgrades to meet customer demand. These projects typically involve the utility employing a competitive process to identify generators, batteries, and demand-response providers who can reduce the strain on the grid and avoid the upgrade. One of the earliest and best-known projects of this type in the U.S. is the Brooklyn Queens Demand Management (BQDM) project, where Con Edison (the IOU) deferred a $1.2 billion substation upgrade by contracting with and dispatching DERs. The idea of harnessing flexible demand to reduce peak demand is also being discussed in the U.S. with respect to interconnecting new data center loads. In the United Kingdom, such approaches have been adopted by all distribution IOUs, establishing flexibility markets around identified utility needs. States should implement NWS using these flexibility approaches.

  
  The same approach to redundant grid capacity can be used by planners when analyzing larger generator project applications. The developer often has to pay for the system to be upgraded to accommodate the output of its project during a contingency when a grid component is lost (a lane closing in our highway analogy) at a time of stress on the grid. This kind of approach is called Flexible Interconnection in the United States and has been extensively used in the United Kingdom, where it is known as Active Network Management (ANM), to connect hundreds of projects to distribution systems previously considered full. In Germany, small amounts of curtailment have delivered vast savings in grid upgrades to connect renewables, with a dynamic curtailment of 5% of the energy generated from solar increasing the grid connection capacity of solar by around 225% without new grid investment. This model needs to become business as usual across the United States and could deliver capital savings in the tens of billions of dollars. States can and should prioritize the implementation of NWS and flexible interconnection at the distribution level to speed up new generator connections and avoid unnecessary and expensive grid upgrades.
  
  

• Reform the utility business model with revenue for shared savings
  Both NWS and Flexible Interconnection should be approached as a shared savings opportunity for the IOUs. This has already been proven in some pilots in New York for NWS, where the utility can earn 30% of the net benefits of the project. Flexible Interconnection, which can deliver much cheaper and quicker grid connections for renewable generators and storage, should also be eligible for a similar shared savings approach to NWS.

  
  These approaches do not need to be proven further; they are ready for deployment. It is time for these methods to be implemented, not as trials or pilots, and to be made available across utility-service territories to speed up interconnection, reduce upgrade costs, and defer or avoid capital. If properly implemented, both NWS and Flexible Interconnection will reduce the need for new grid infrastructure and could significantly contribute to lower customer bills by delivering more capacity in the system without adding more to the regulated asset base of the IOU.

  But making this happen also means realigning the system’s current incentives. Right now, an IOU’s main goals are to maximize shareholder return and meet the expectations of regulators. IOUs are not incentivized to focus on sharing savings with customers. By introducing a shared savings model for reduced capital, IOUs would gain a significant new revenue stream as they enable the system to carry much more energy and achieve higher asset utilization throughout the year. Because a significant part of customer bills are costs that IOUs simply incur and pass through without a profit, including generation costs, surcharges, taxes, and fees, the utility has no interest in reducing those costs. But there are significant savings to be had if utilities benefited from cost reductions in this part of the bill as well. To take one simple example: Speeding up the connection of clean and cheap renewable energy at distribution should reduce generation costs overall. The IOU should have an incentive to deliver these savings and share them with customers.

  The next step in performance-based regulation of IOUs should include focusing on outcomes such as avoiding capital expenditures; bill savings; and adding megawatts of flexible generation, storage, and demand capacity to the system. This, too, needs to be a meaningful and comparable revenue opportunity for the IOUs. This does not mean an end to grid upgrades; but any required upgrades should be clearer and more justifiable once NWS and Flexible Interconnection options have been exhausted. 

Conclusion

This paper has provided some implementable recommendations for the advancement of the U.S. power sector. These recommendations identify win-win opportunities, where existing IOUs can pursue commercial interests that are aligned with lowering customer bills and delivering a clean, flexible, and reliable system. Reforms such as these are a step toward addressing the pressing issues of affordability, reliability, and finan-cial efficiency as the U.S. grid becomes cleaner and more resilient.