After the last election in 2022, there were significant changes to state legislatures in the Midwest, including in Michigan and Minnesota, which were consolidated under one party. With the ongoing growth of renewables and distributed energy resources (DER), there is no shortage of adjustments afoot. Starting at the top, the Midcontinent Independent System Operator (MISO) is in the initial stages of planning for the substantial buildout of new transmission across its system. At the state level, there are a multitude of efforts in each state. This surfeit of policy conversations provides an opportunity to highlight leading efforts and identify conversations occurring in multiple jurisdictions. As a result, this will not attempt to cover all the happenings across the Midwest but will highlight some of the more notable efforts. In particular, there are six pro-competitive actions a state may consider as the region moves forward with greater development of renewable resources and DER. By leveraging the power of competitive markets, states can keep costs low and ensure that all stakeholders capable of providing services are fairly considered.

Implementing FERC Order No. 2222

Across the MISO footprint, states are in various stages of figuring out how to implement FERC Order No. 2222. In brief, Order No. 2222 allows for the aggregation of DER to be bid directly into organized wholesale markets like MISO. The order allows states to determine what rules need to be in place to allow aggregators to operate in their jurisdiction, but it cannot prohibit aggregators from participating; however, the state opt-out for demand response aggregation adopted in FERC Order No. 719 remains. As detailed in a report to the Missouri Public Service Commission, commissions in these states generally focus on a handful of issues:

  1. What is the commission’s jurisdiction over aggregators?
  2. What are the impacts on existing utility demand response programs, if any?
  3. What information and data are needed for aggregators to participate in a state and how to facilitate the exchange of that information?
  4. How do actions from the aggregator get relayed to the distribution utility?

These are important questions, but avoiding barriers to entry and providing a sensible regulatory structure to allow aggregators to operate in the jurisdiction is critical to realizing the goals of Order No. 2222 and enabling new opportunities for DER.

Leveraging Demand Flexibility

In conjunction with the consideration of allowing aggregators, regulators must also consider the role of demand flexibility in not only meeting future energy needs but also how it can be used as an energy resource on a daily basis. Traditional utility demand response programs are typically tied to a system emergency and focus on capacity relief. Think air conditioning cycling programs that shut off air conditioning for a period of time during peak summer conditions. With tighter reserve margins, MISO has projected potential conditions in which supply will barely be greater than forecasted demand. Traditional demand response would not be called upon until the system operator (i.e., MISO) declared an emergency. And even then, the utility might still not call on DR programs. Instead, grid operators, utilities and regulators are now calling for voluntary customer reductions during all times of the day. These consumer actions can help avoid outages, but even though they are providing a highly valuable service—demand response throughout the day—consumers aren’t compensated for this reduction. This should change. The system is increasingly in need of more flexible resources, and demand can play a vital role in this evolution. This includes using demand side more often and paying customers for that response.

Accessing Customer Usage and Grid Data

Smart meters continue to be installed across the MISO footprint. Some utilities got smart meters early, and others are just now installing them. Nevertheless, a key value of these meters is the more granular data generated (compared to older meters) and collected by the utility. This information can provide the customer with important details about how they use and consume electricity. Such information can help the customer and its authorized third party identify opportunities for cost savings and other products, such as adding solar to a house or participating in a DER aggregation service. However, the customer must be able to easily approve a third party to access that data—and the third party must be able to access it without unnecessary technical, policy or legal barriers. If customers are unable to easily access their information, and if third parties cannot easily access authorized data, then a significant component of the smart meter business case will not be realized.

Similarly, grid data can provide significant insight to DER developers that can help identify appropriate areas of DER development. Where grid data is not available, developers may rely on the interconnection process to determine the location’s viability. Such actions, however, clog the interconnection process, which delays interconnection studies and increases costs to utilities and developers. If developers already knew where to focus, they would avoid needlessly bogging down the interconnection process. An important point to note on data access is that finding the right balance between data necessary to enable a marketplace for new services and data that is too sensitive to share. Establishing foundational expectations can help regulators review utility proposals. For example, a regulator might adopt a foundational principle that all grid data should be available unless the utility can show that such information would harm its safety and security.  

Data will play an important role in the energy transition and support competitive opportunities for third parties, but only if such data is easily available. Regulators will need to ensure that utilities are not unnecessarily adding needless requirements to data access that only protect the utility’s business interests.

Using Competitive Procurement Solutions

A competitive solicitation can provide the utility and the regulator with some visibility into costs of resource needs, which then allows the regulator to compare the costs from the competitive market to the utility. This becomes even more important when a state like Minnesota seeks to be 100 percent carbon-free by a specific date. Indeed, while the Minnesota 100 percent bill may be agnostic as to how the utilities are to become 100 percent carbon-free, existing policies still favor the incumbent utility. Even Vote Solar, who was active in the bill’s development, noted that “the 100% standard as written favors traditional utility investment paths.” In most integrated resource procurement proceedings, utilities will favor choosing their own self-build options—be it new generation or new distribution or transmission—rather than choosing to procure resources from other providers, even if those options are less expensive. Without this price discovery, stakeholders—including regulators—have no means to compare utility solutions with competitive solutions. By requiring the utility to engage in a competitive procurement process, the process can provide a more transparent result by ensuring that all resources capable of providing the service—including DER—have a chance. If a regulator is looking to use a competitive solicitation model, they would be advised to consider a 2021 report on best practices for competitive solicitations.  

Supporting Grid-Enhancing Technologies

With the need to build more transmission growing, a good first step is to look at opportunities to expand the capabilities of existing transmission by incorporating grid-enhancing technologies (GETs) as “good utility practice.” Cost-of-service regulation discourages incumbent transmission owners from reducing the capital costs of transmission operations. This results in utilities foregoing the adoption of GETs, which eliminate massive levels of transmission congestion that can save billions of dollars while doubling clean energy integration. This is largely why enhancing efficiencies on existing wires is a core priority for transmission consumers. Federal regulators required MISO and its peers to implement one type of GETs: temperature-adjusted line ratings. This alone should save MISO hundreds of millions of dollars from reduced transmission congestion. It is unclear whether FERC will pursue additional GETs. MISO states should lead on pursuing further GETs applications, such as incorporating lessons on how to implement topology optimization based on a pilot in the upper Midwest. 

Closing the “Regulatory Gap” in Transmission Expansion

MISO’s economics-based regional transmission planning has been a success, yielding benefits that well exceed costs. However, it is chronically underutilized because local monopoly utilities route most transmission projects through exemptions to the regional process. This means that small, inefficient projects receive virtually no economic regulatory scrutiny either by FERC or state regulators, which escalates costs on dissatisfied customers who demand reform. Midwest state regulators and FERC commissioners agree with the imperative to close this gap. This includes minimizing exemptions to regional planning processes, which lets competitive bidding drive cost discipline. Where this is unworkable, cost recovery should be predicated on an affirmative burden to demonstrate transmission facility prudence. Better transparency and independent analysis would better inform stricter oversight of local transmission reviews, such as identifying which transmission needs are more cost-effectively met in regional planning. 


These are just a few of the possible solutions available to states across the MISO footprint. As electricity systems and technologies are constantly evolving, it is even more important for Midwest markets and policies to reflect these changes and be prepared to take advantage of them. This will reduce costs to customers and enhance the efficiency of the electric system.