Indiana’s electric grid is being asked to do a lot at once. Generation grew by more than 13 percent in 2025, the fastest jump of any state in the Midwest. Coal ran harder to meet that demand even as the national coal fleet shrank. Retail electricity prices climbed 10.5 percent in a single year.

Even as Governor Braun’s administration moves to preserve coal capacity, Hoosier electricity rates are rising faster than the national average, and the state’s utilities are still planning a generation buildout that’s 77 percent solar through 2028.

This report sources from the February 2026 edition of Electric Power Monthly, from the U.S. Energy Information Administration (EIA). The February 2026 data is current through December 2025, offering us a look under the hood before the Electric Power Annual releases later this year.

Here’s how Indiana’s electric grid changed in 2025.

Generation

In 2025, Indiana generated 110,188 gigawatt-hours of electricity in-state, up from 97,400 GWh in 2024. That 13.1 percent increase far outpaced national growth of 2.8 percent and the wider East North Central region’s 5.0 percent. Indiana had the fastest generation growth of any Midwestern state and the third-fastest in the nation, behind only New Hampshire and Wyoming.

Indiana’s grid remained predominantly fueled by coal, which comprised 44.9 percent of total electricity generation. That’s up from 41.6 percent in 2024, as coal generation grew by 8,788 GWh — roughly 70 percent of Indiana’s total generation increase. Coal plants ran harder in 2025, with the fleet’s capacity factor jumping from 36.4 percent to 44.2 percent, even as no significant coal capacity was added or retired.

Natural gas followed at 36.2 percent of generation, down from 40.9 percent in 2024. Gas generation was essentially flat year-over-year. Indiana’s combined cycle fleet ran at roughly 60 percent capacity factor, well below its technical ceiling, but the state leaned on coal anyway. That’s a good thing for ratepayers, since coal plants are older and more likely to be depreciated assets, so the marginal cost of running them is fuel and operations, not cost recovery. Running a paid-off coal plant harder is cheaper for ratepayers than building and financing new generation.

Wind generation was flat at 10,309 GWh, unchanged from 2024, holding at 9.4 percent of total generation. Solar more than doubled. Utility-scale solar generated 6,730 GWh in 2025, up from 3,091 GWh in 2024, for a 117.7 percent increase. Utility-scale solar’s share of total generation jumped from 3.2 percent to 6.1 percent in a single year.

Indiana also generated 2,536 GWh of electricity from “other fossil gas” — primarily blast furnace and coke oven gas from its steel mills — up 20 percent from 2024. Hydroelectric and biomass together made up less than 0.5 percent of generation, and Indiana has no nuclear power.

Thermal generation totaled 83.3 percent of Indiana’s 2025 electricity. Wind, solar, hydro, and biomass combined for 16.3 percent. Every megawatt of solar that Indiana intends to add will need firming capacity that ratepayers pay for twice — once for the panels, once for the gas turbine or battery that covers for them.

Net Summer Capacity

Indiana’s 2025 net summer capacity, which the EIA defines as the maximum output generators can supply to the grid during peak summer demand, was 30.8 gigawatts, up from 27.8 GW in 2024. Coal, natural gas, petroleum, and other fossil gas together accounted for 21.9 GW; wind, solar, hydro, and biomass totaled 8.5 GW at utility scale. Coal held steady at 12.7 GW, natural gas combined cycle units at 3.9 GW, and natural gas combustion turbines reached 3.8 GW after adding 453 MW during the year. Battery storage capacity quadrupled, from 81 MW to 337 MW.

Indiana is expected to add about 5,500 MW of new net summer capacity between 2026 and 2028. About 77 percent of that, or 4,223 MW, is solar photovoltaic. Another 580 MW is onshore wind, 400 MW is natural gas, and 270 MW is battery storage.

Indiana retired essentially no utility-scale generating capacity in 2025, only posting a 6.3 MW decline of small industrial and commercial units. But some are on the horizon, which would need replacement funded by Indiana ratepayers.

Schahfer Units 17 and 18 (722 MW, NIPSCO) and F.B. Culley Unit 2 (90 MW, CenterPoint) were scheduled to retire December 31, 2025. On December 23, the U.S. Department of Energy issued Section 202(c) emergency orders under the Federal Power Act, requiring the plants to remain available. The orders were extended through June 2026.

Governor Mike Braun signed executive orders in April 2025 directing state agencies to support coal life extensions and explore new nuclear generation. Duke Energy Indiana has signaled delaying retirement of its 3,132 MW Gibson plant — the second-largest coal plant in the country — from 2035 to 2038. AEP’s I&M Rockport units (2,600 MW combined) remain scheduled for end-of-2028 retirement. AES Indiana is proceeding with conversion of the last coal units at Petersburg to natural gas, with Unit 3 expected to enter commercial gas operation in June 2026 and Unit 4 in October 2026.

Most Indiana utilities operate in the Midcontinent Independent System Operator (MISO) footprint. Indiana Michigan Power and part of northeast Indiana sit in PJM. Both markets have tightened significantly. MISO has flagged resource adequacy concerns in recent planning assessments, and PJM’s 2025/26 capacity auction cleared at nine times the prior year’s price. Keeping existing coal capacity in service is the right call for reliability and for consumers’ wallets.

Annual Capacity Factors

An electric resource’s “capacity factor” is the ratio of electricity actually produced to the theoretical maximum if the unit ran at full power continuously. Thermal plants can modulate output to meet demand; wind and solar produce what they can when weather permits.

In 2025, Indiana’s wind fleet had an average annual capacity factor of 30.6 percent, while utility-scale solar ran at 17.0 percent. Both are below the national averages of 34.2 percent for wind and 24.4 percent for solar photovoltaic. Indiana’s solar capacity factor looks a bit low because the utility-scale solar fleet nearly doubled during 2025, and much of that capacity came online late in the year. Adjusted for mid-year additions, Indiana’s solar likely produced closer to 22 percent, but that’s still well below the national average.

Planned additions through 2028 are 77 percent solar and 7 percent natural gas, which means Indiana will be counting on solar showing up during summer evening peaks, when Indiana’s air conditioning load is highest and solar production falls off.

Average Electricity Prices

In 2025, the average all-sectors price of electricity delivered to Indiana customers was 12.57 cents per kilowatt-hour, up 10.5 percent from 11.38 cents per kWh in 2024. That one-year jump is the second-largest annual increase Indiana has recorded in EIA data going back to 2001, trailing only the 12.6 percent spike in 2022 when natural gas prices surged globally.

Indiana’s all-sectors rates remain lower than the national average of 13.63 cents per kWh and the East North Central regional average of 13.28 cents per kWh. But the historical affordability advantage has eroded sharply over the past two decades.

In 2007, Indiana’s average all-sectors rate of 6.50 cents per kWh was 28.8 percent below the U.S. average of 9.13 cents. By 2024, that gap had narrowed to 12.1 percent. Over the same period, Indiana’s prices rose 75.1 percent — almost exactly twice the national growth rate of 41.7 percent. Through 2025, Indiana prices are up 93.4 percent since 2007, compared to a 49.3 percent national increase. Hoosiers still pay less than the rest of the country, but the margin is shrinking fast.

Conclusion

Indiana’s electric generation grew sharply in 2025, with coal carrying most of the additional load. Indiana’s utilities and state government are pushing for more reliable baseload power by postponing coal retirements, converting some units to natural gas, and exploring new nuclear. But the state’s affordability is already being jeopardized by solar additions, which comprise 77 percent of planned additions through 2028. Preserving Indiana’s coal fleet needs to be top priority for policymakers.