Coal has dropped to about 42% of Indiana's net electricity generation — from more than 80% a decade ago — and the infrastructure replacing it involves natural gas plants sized for Amazon data centers, federal emergency orders keeping damaged coal units running at six-figure daily costs, and a Duke Energy capital plan unlike anything Indiana has seen before. For Indiana manufacturers, this is your cost and reliability exposure for the next three to five years, not just another story about the energy transition.

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Indiana's Generation Mix and Mammoth Solar: What's Actually Being Built

Indiana's 2024 mix ran roughly 42% coal, 36% natural gas, 9% wind, and 6% solar. Industrial load accounts for about 43% of total in-state electricity consumption — this is an industrial grid first, and that matters when costs shift.

On the solar side, Doral's Mammoth Solar project in Pulaski and Stark counties is one of the clearest examples of new capacity coming online. The project is 1,600 MW total. The first 480 MW came online in July 2024. Phases two and three — about 900 MW combined — are financed at roughly $1.5 billion and are under construction now, with completion targeting late 2026 or early 2027.

At the same time, NIPSCO is retiring its coal units at Schaeffer between 2026 and 2028 and replacing them — through a new subsidiary called NIPSCO GenCo — with 2,300 MW of new natural gas generation and 400 MW of battery storage. The load driver is Amazon data centers in northern Indiana. NIPSCO's planning documents show that once those data centers are counted, the utility's energy needs more than double. Every dollar of that infrastructure investment goes into the rate base. Rate base is where utility earnings come from. You pay for it.

Duke Energy Indiana's $103 Billion Capital Plan Is Already in Your Bills

The IURC approved new Duke Energy Indiana rates in early 2025, adding roughly $295.7 million in annual revenue. For customers, that works out to an overall average bill increase of about 11% — phased in as approximately 8% in February 2025 and another 3% in early 2026. Duke had originally requested around $491 million. The OUCC recommended a lower number. Duke has filed for reconsideration, so that rate case is not closed.

Duke's five-year capital plan totals $103 billion across its six-state footprint — the largest of any regulated utility in the U.S. Duke's CEO has said publicly that hyperscalers are required to cover their own infrastructure costs under Indiana's "growth pays for growth" framework. The stated position is that your rate pressure is coming from grid hardening and transmission investment, not from subsidizing data centers. Watch Duke's reconsideration filing and any new rate case that follows — pay particular attention to how C&I tariffs are structured relative to residential and large industrial rates.

DOE Emergency Orders Are Keeping Aging Coal Plants Online — and the Costs Are Landing Somewhere

On December 23, 2025, DOE Secretary Chris Wright issued emergency orders under Section 202(c) directing NIPSCO and CenterPoint — along with MISO — to keep Schaeffer Units 17 and 18 in Wheatfield and Culley Unit 2 in Warwick County operating past their planned December 31 retirement dates. Those orders were extended March 23, 2026 and run through at least June 21, 2026. Nationally, DOE emergency orders have paused or delayed at least 4.4 gigawatts of coal retirements.

The cost of keeping these plants online is not speculative. Analysis prepared for public interest groups estimates Schaeffer is running about $174,000 per day in extended operating costs; Culley adds roughly $21,000 more. Schaeffer Unit 18 has been offline since July 2025 due to a damaged turbine — NIPSCO has told regulators it could take six months or more to restore. NIPSCO has already filed at FERC seeking a MISO tariff mechanism to spread those costs across the broader grid. Attorneys general in Minnesota and Illinois have filed legal challenges arguing DOE overstepped. How that legal fight resolves determines how much of that daily cost lands on your tariff. C&I customers typically absorb a disproportionate share of these cost allocations compared to large industrial customers and residential ratepayers.

Questions for Your Morning Huddle

Q: How will NIPSCO's 2,300 MW natural gas build for Amazon data centers affect long-term electricity costs for Indiana manufacturers? A: Every dollar NIPSCO invests through GenCo goes into its rate base and gets recovered from ratepayers over time through future rates. Manufacturers in NIPSCO territory should use conservative rate increase assumptions — not flat ones — in any three-to-five-year energy cost forecast.

Q: What's our financial exposure to the DOE emergency orders at Schaeffer and Culley, and how does that cost reach our bills? A: Schaeffer is running about $174,000 per day in extended operating costs; Culley adds roughly $21,000 more. NIPSCO is seeking FERC approval to spread those costs across MISO. C&I customers typically absorb a disproportionate share of these allocations, and your energy budget scenarios should account for this exposure before the next rate case decision is issued.

Q: Given Duke's $103 billion capital plan and ongoing rate case activity, how accurate are our three-to-five-year energy cost forecasts? A: Duke's rate increases are not finished — the utility has filed for reconsideration and its capital deployment runs through 2030. If your facility-level forecasts assume flat or modest rate growth, they are likely too optimistic. Build your scenarios around the high end of any reasonable range.

Watch the DC Circuit case on the DOE emergency orders and any FERC ruling on cost allocation — together they determine how much of the Schaeffer and Culley tab lands on your tariff. For a deeper look at how utility infrastructure investments translate into demand charges and C&I rate exposure, see our Canon post on demand ratchets and how Indiana utilities recover infrastructure costs through your bill.

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