Here’s what goes into your electricity bill — and what could change

What’s in your utility bill?

Amid fierce customer pushback to high electricity bills and increasingly frequent hikes, Indiana officials are reconsidering utility risks, profits and key charges in a bid to bring prices down — ahead of a major regulatory transition.

Five large investor-owned utilities serve roughly 80% of Indiana electricity customers: AES Indiana, CenterPoint Energy Indiana South, Duke Energy Indiana, Indiana Michigan Power Co. and the Northern Indiana Public Service Co. They are monopolies in their service areas in exchange for submitting to state regulators.

The Indiana Utility Regulatory Commission, or IURC, decides how much they’ll assess customers based on evidence from the companies themselves, customer advocates and other stakeholders.

Here’s what goes into what you owe.

Fixed charges

All residential customers pay a service or facilities charge that stays flat no matter the amount of electricity used.

It’s intended to spread out the cost of servicing ratepayers, like meter readings, bill preparation and customer service.

The charge ranges from CenterPoint’s $11 at the low end to AES’ $17 at the high end.

Variable usage

Next up is the amount owed for the actual electricity consumed. This is the part of a bill impacted by base rates.

Regulators have agreed to reconsider the $71 million base rate increase approved for AES in June. CenterPoint, Duke and NIPSCO all received approval for base rate hikes last year, while I&M’s base rates date back to 2024.

Under the outgoing system, utilities generally can’t file for an increase to their base rates sooner than 15 months since their last request for a base rate hike was filed. But that’s changing.

Lawmakers and Gov. Mike Braun approved House Enrolled Act 1002 in March. Regulators will set base rates and schedule increases over a three-year period under the new system. Utilities may earn more or less money from customers depending how well they perform on affordability and post-outage service restoration metrics.

Duke, as the utility with the most customers, must petition first under this setup by mid-December. The rest will follow under a schedule laid out in statute.

“The worst-case scenario I envision under the multi-year rate making platform structure that we have now is adhering to the status quo,” said Sarah Freeman, who left the IURC last year after nine years as a regulator.

She now works as a principal for the Regulatory Assistance Project, a nongovernmental organization focused on the U.S. and the world’s other largest energy markets.

“By that, I mean a situation in which a utility complies with the multi-year rate plan and performance incentive statutes and does not roll in all of their trackers,” Freeman continued. “That, on a bill, would very likely look the same as what bills look like now.”

Trackers

Bills also carry a list of rate adjustment mechanisms — also called trackers or riders — that allow utilities to recover costs from customers in between base rate cases.

Some providers offer a “detailed” bill with a list of every charge, including trackers; others don’t. But the breakdown must be provided upon request, Freeman said.

Trackers generally fall into capital and operational expenditures.

All of the investor-owned utilities, except I&M, have a transmission, distribution and storage system improvement charge.

They’re part of five- or seven-year infrastructure plans, with 80% of the costs recovered from the tracker and the rest deferred to the utility’s next base rate case.

Freeman was a staff attorney working on utility law at the Legislative Services Agency when the TDSIC statute was enacted in 2013.

“When TDSIC came about, I would say that rate cases were more spread out than they are now,” she said. “And this was a way to incentivize a slightly tighter timeframe, while ensuring that projects intended to address reliability concerns were happening and being paid for in a timely manner.” 

Demand side management is another capital tracker that pays for the new lights, appliances and more offered to help customers reduce energy usage — and make up for the revenue lost to those efficiency measures.

The utilities also have trackers for federally mandated investments.

Some capital trackers could be rolled into base rates in the coming years, however.

In their first multi-year rate submissions, the utilities must submit plans for incorporating planned capital expenditures into their subsequent rate proposals.

The hardest-hitting tracker for customers, however, is an operational one called the fuel adjustment clause.

Utilities set fuel costs in their base rates, but jumps and dips beyond that are collected or returned to customers at levels that can change every three to six months.

It’s a passthrough, meaning that utilities don’t profit off the changes.

Other operational trackers account for the money utilities spend to be part of regional transmission organizations, as well as the energy they buy and sell on regional markets.

The IURC has launched two investigations to prepare for the onset of multi-year rate plans, including one on changes in risk — and therefore to regulated profits — and another on how both kinds of trackers will fit into the new system.

“The 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,” IURC Chair Anthony Swinger said at a technical conference last month.

Utilities don’t have all the same variable costs.

CenterPoint, for instance, has several charges for securitization to retire generation plants.

Sales tax

Indiana’s 7% sales tax applies to utility service. This is another passthrough to customers.

The IURC, in an affordability report released in July, asked the General Assembly to consider repealing the sales tax for utility bills.

But such legislation, largely sought by Democratic lawmakers, has failed repeatedly in the past — despite supportive sentiment from across the aisle. Some officials, including Lt. Gov. Micah Beckwith, have publicly backed ditching it.

But that elimination would cost the state $615 million annually in tax revenue.

Correction: This article was updated to reflect the prevalence of the transmission, distribution and storage system improvement charge.