Indiana officials are re-evaluating utility risks, profits, and various customer charges in a bid to lower electricity prices, responding to significant customer objections regarding high bills and frequent rate increases. This reconsideration comes ahead of a major regulatory shift impacting the five large investor-owned utilities that serve approximately 80% of the state's electricity customers: AES Indiana, CenterPoint Energy Indiana South, Duke Energy Indiana, Indiana Michigan Power Co., and the Northern Indiana Public Service Co. These companies operate as monopolies in their service areas, submitting to state regulation.
The Indiana Utility Regulatory Commission (IURC) is tasked with determining the charges customers will incur, relying on evidence presented by the utilities, customer advocates, and other relevant parties. All residential customers are subject to a flat service or facilities charge, designed to cover costs like meter readings, bill preparation, and customer service. This charge varies among providers, ranging from CenterPoint's $11 to AES's $17.
Beyond this flat fee, customers pay for the electricity they consume, an amount influenced by base rates. Regulators have agreed to reconsider a $71 million base rate increase for AES that was approved in June. Last year, CenterPoint, Duke, and NIPSCO all received approvals for base rate hikes, while I&M's base rates were established in 2024.
The current system generally prevents utilities from requesting a base rate increase sooner than 15 months after their last request was filed. However, a significant change is underway. Lawmakers and Gov. Mike Braun approved House Enrolled Act 1002 in March, which introduces a new system. Under this framework, regulators will establish base rates and schedule increases over a three-year period. Utilities will have the potential to earn more or less money from customers, depending on their performance regarding affordability and the speed of post-outage service restoration. Duke, which serves the largest number of customers, is mandated to submit its first petition under this new structure by mid-December, with other utilities to follow according to a statutory schedule. Sarah Freeman, who served nine years as an IURC regulator before leaving last year, expressed a concern that the "worst-case scenario I envision under the multi-year rate making platform structure that we have now is adhering to the status quo," meaning bills might not look different if utilities don't consolidate all their trackers.
Beyond base rates, electricity bills include rate adjustment mechanisms, also known as trackers or riders, which enable utilities to recover costs from customers between formal base rate cases. While some providers offer detailed bills itemizing every charge, including trackers, customers can request this breakdown. Trackers typically fall into two categories: capital and operational expenditures.
All five investor-owned utilities utilize a transmission, distribution, and storage system improvement charge (TDSIC). These charges are tied to five- or seven-year infrastructure plans, with 80% of the costs recovered through the tracker, and the remaining portion deferred until the utility's next base rate case. Freeman, who worked on utility law when the TDSIC statute was enacted in 2013, noted that it was intended to incentivize faster project timelines and ensure timely payment for reliability-focused projects. Another capital tracker, demand side management, covers costs for programs like new lights and appliances offered to help customers reduce energy usage, while also offsetting the revenue lost due to these efficiency measures. Trackers also exist for federally mandated investments. In the future, some capital trackers could be integrated into base rates; utilities are required to submit plans for incorporating planned capital expenditures into their subsequent rate proposals as part of their initial multi-year rate submissions.
The most significant operational tracker for customers is the fuel adjustment clause. While utilities set initial fuel costs within their base rates, fluctuations beyond these set levels are either collected from or returned to customers, with adjustments occurring every three to six months. This is a passthrough mechanism, meaning utilities do not profit from these changes. Other operational trackers cover expenses for utility participation in regional transmission organizations and the buying and selling of energy on regional markets.
In preparation for the implementation of multi-year rate plans, the IURC has initiated two investigations. One focuses on changes in risk, which impacts regulated profits, and the other examines how both capital and expense trackers will integrate into the new system. IURC Chair Anthony Swinger stated at a recent technical conference that this investigation "will consider the development of guidelines for the commission, utilities and additional parties to use in evaluating the role that expense trackers and capital trackers will play within the (new) regulatory framework."
Utilities also have varying specific costs. CenterPoint, for example, includes several securitization charges related to the retirement of generation plants. Furthermore, Indiana's 7% sales tax is applied to utility service, acting as another passthrough charge to customers. An affordability report released by the IURC in July called on the General Assembly to consider repealing the sales tax on utility bills. While such legislation has historically been sought by Democratic lawmakers, it has repeatedly failed to pass, even with support from some officials across the aisle, including Lt. Gov. Micah Beckwith. However, eliminating this sales tax would result in a loss of $615 million annually in state tax revenue.