NiSource — Building for Load That May Not Arrive
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Decision date and information cutoff: December 10, 2024, 4:00 p.m. Eastern Time
Decision scope: How NIPSCO should govern generation procurement and sequence capacity additions as it retires coal units and plans for possible large-load growth
Case convention: This is an author-created management decision exercise. The assignment and alternatives are hypothetical; company disclosures and regulatory actions are historical. No private deliberations are represented. Use only information available before the cutoff. NIPSCO's 2024 Integrated Resource Plan (IRP) is dated December 9, 2024. Later comments, filings and outcomes are outside the case.
The decision
On December 9, 2024, Northern Indiana Public Service Company (NIPSCO) submitted a new Integrated Resource Plan to the Indiana Utility Regulatory Commission (IURC). The plan described a path to retire the utility's remaining coal units, maintain reliable supply under changing MISO capacity rules, and prepare for possible new data-center demand. It also left important choices conditional: the timing and amount of large-load growth were uncertain, and future capacity could come from utility ownership, build-transfer agreements (BTAs), power purchase agreements (PPAs), or some combination.
NIPSCO's parent, NiSource, planned nearly $19.3 billion of capital investment across its utilities from 2025 through 2029. NIPSCO's next resource commitments would compete for capital and management attention with gas and electric infrastructure work across six states. [S1] [S3]
Assignment: As a hypothetical member of NiSource's senior leadership team preparing for the next implementation review, recommend how NIPSCO should govern procurement and sequence resource additions over the next five years. Should it favor utility ownership, contract more supply from outside developers, or use staged choices tied to reliability and load milestones? Specify the decision gates and evidence required before NIPSCO commits to resources for possible data-center loads.
The assignment does not imply that management reopened its submitted IRP or that every proposed resource is still available. You cannot rank the 2024 bids by price: disclosed materials do not provide complete bid prices, final rankings or executed contracts. Your recommendation should distinguish energy from accredited capacity, a planning assumption from a signed load, and a filed plan from an approved project.
A regulated utility at a transition point
NiSource is a holding company whose businesses include regulated natural-gas utilities and NIPSCO, an Indiana gas and electric utility. NiSource held an 80.1% controlling indirect stake in NIPSCO; Blackstone Infrastructure Partners held the remaining 19.9% after contributing $2.16 billion in 2023. The capital partnership may matter to financing and governance, but the public record does not say it determines NIPSCO's resource choices. [S2]
NIPSCO's power system operates within the Midcontinent Independent System Operator (MISO) market. In 2023, NIPSCO-generated units—including projects developed under BTAs—served 49.5% of its system load. Power purchase agreements and the MISO market supplied the rest. The existing portfolio therefore combined utility-related generation with external purchases. [S2]
By September 30, 2024, NIPSCO reported IURC-approved PPAs with 1,400 MW of nameplate capacity and BTAs with 1,950 MW for wind, solar and solar-plus-storage projects. The utility also reported $1.15 billion of guarantees connected to its future performance under renewable BTAs. The guarantees were scheduled to decline as projects reached substantial completion; their stated amount was not a forecast of losses. NIPSCO had received approval for full ownership of several solar projects, which the company said would allow it to use federal tax credits more effectively than the prior tax-equity arrangements. [S2]
The ownership structures were not interchangeable. With a BTA, a developer would build a project for transfer to NIPSCO under the agreement. A PPA would purchase energy or capacity under contract terms. Direct ownership would place construction and operating responsibilities with NIPSCO and could involve different financing and tax-credit treatment. Market purchases could add flexibility but would have to be evaluated for duration, deliverability and contribution to resource-adequacy requirements. The public information did not provide enough project-level contract terms to compare the structures on a common customer-cost basis.
The transition plan
NIPSCO's IRP retained the scheduled retirement of Schahfer Units 17 and 18 by the end of 2025 and Michigan City Unit 12 by 2028. It described approximately 2,100 MW of previously approved replacement resources planned to enter service through 2028: roughly 1,700 MW of renewable resources and a 400 MW gas peaker. At the cutoff, those resources were a mixture of completed, under-construction and pre-construction projects; they were not all operating. [S1] [S2]
The IRP also described additional capacity steps tied to changing MISO rules. To address the Direct Loss of Load (D-LOL) capacity-accreditation rule, which FERC had approved in October 2024, NIPSCO said it planned to add 900–1,150 MW of storage and 350 MW of short-term thermal PPAs by 2028–2029. It said it would monitor MISO accreditation and adjust storage procurement over time. The plan was not an executed procurement award, and storage nameplate capacity would not translate one-for-one into accredited peak capacity. [S1]
NIPSCO separated resources it expected to need regardless of large-load growth from additions that would depend on contracted new data-center demand. If such loads were contracted, the company said it was prepared to meet their capacity and energy needs with an equivalent amount of installed combined-cycle gas turbine (CCGT) capacity. Potential sources included PPAs, BTAs, self-build projects or a mix. NIPSCO also said it would prepare for additional gas peaking resources if future emissions rules constrained CCGT operating capacity factors. These were conditional pathways, not approvals to build a specified set of plants. [S1]
Exhibit 1. Resource position and plans at the cutoff
| Resource / step | Capacity or timing | Status at cutoff |
|---|---|---|
| NIPSCO generation, BTA projects, PPAs and MISO market | Generated units served 49.5% of 2023 load; remainder from PPAs and MISO | Historical supply mix; energy share, not capacity share |
| Wind, solar and solar-plus-storage agreements | 1,950 MW under BTAs; 1,400 MW under PPAs | IURC-approved agreements reported as of Sept. 30, 2024; nameplate capacity |
| Schahfer Units 17 and 18 | Retirement by end-2025 | Scheduled in the IRP; not a statement of completed retirement |
| Michigan City Unit 12 | Retirement by 2028 | Scheduled in the IRP; not a statement of completed retirement |
| Previously approved replacement resources | About 1,700 MW renewables and 400 MW gas peaker through 2028 | Mix of completed, construction and pre-construction projects |
| Storage and thermal PPAs for D-LOL capacity needs | 900–1,150 MW storage; 350 MW short-term thermal PPAs by 2028–29 | Planned additions; not executed awards |
| Additional resources for data-center load | CCGT capacity equivalent to contracted load; source could be PPA, BTA, self-build or mix | Conditional on contracted load; no fixed procurement decision shown |
Sources: NiSource Q3 2024 Form 10-Q, Note 19, “Generation Transition”; NIPSCO 2024 IRP, §1.1, pp. 1–2. [S1] [S2]. Values described as nameplate MW should not be read as MISO-accredited capacity.
A solicitation with interest but no public price ranking
To inform the 2024 IRP, NIPSCO ran four competitive solicitation events: intermittent resources such as renewables and storage; non-intermittent resources; bridge resources such as near-term energy and capacity; and up to 10 MW of distributed energy resources. NIPSCO described its first two events as an all-source effort. The evaluation process considered cost and non-cost factors, including levelized energy or capacity cost, reliability and deliverability, development risk and asset-specific characteristics. [S3]
In October, NIPSCO reported 58 project proposals totaling approximately 9.63 GW of project installed capacity across three states. It reported 1,166 MW of solar, 2,338 MW of solar-plus-storage, 3,892 MW of standalone storage, 1,438 MW of thermal or other resources, and 800 MW of zonal resource credits (ZRCs). The company said no wind projects had been bid into the solicitation. This proposal volume suggested options, particularly for storage, but did not show which bids would be chosen or whether they would meet NIPSCO's deliverability, timing or capacity needs. Some asset-sale prices were redacted. [S3]
Exhibit 2. 2024 RFP project proposals
| Proposal type | Project capacity reported (MW ICAP) |
|---|---|
| Solar | 1,166 |
| Solar plus storage | 2,338 |
| Standalone storage | 3,892 |
| Thermal / other | 1,438 |
| Zonal resource credits | 800 |
| Total | 9,634 |
NIPSCO reported 58 individual projects and no wind proposals. Proposal ICAP is not awarded or accredited capacity; ZRCs are capacity credits, not physical generation assets. Source: NIPSCO, 2024 IRP Stakeholder Advisory Meeting 5, Oct. 28, 2024, RFP appendix, pp. 111–113. [S3]
Capital and customer considerations
NiSource's October 2024 guidance described a $19.3 billion base capital plan for 2025–2029, expected annual rate-base growth of 8–10% and expected adjusted earnings-per-share growth of 6–8%. The plan covered the parent company's regulated operations, not just NIPSCO generation. Adjusted EPS was a non-GAAP measure reconciled in the company's release. The forward estimates were management guidance, not guaranteed investment returns. [S4]
NIPSCO's IRP used customer cost, rate stability, environmental sustainability, reliability, flexibility and local economic impacts as planning objectives. It compared scenario portfolios using company and consultant models, including revenue-requirement measures and stochastic analysis of load, weather, fuel prices, renewable output and generator availability. Those results reflected planning assumptions and were not independently verified forecasts. Neither the submitted IRP nor the Q3 parent guidance disclosed a project-level comparison of customer bills for an owned asset versus a PPA. [S1] [S3]
Some questions therefore remained open. How much accredited capacity would storage deliver under the evolving rule? Would the contracted load arrive, and on what schedule? What firm capacity and energy could each procurement structure deliver? How would costs be allocated if a large new customer drove an addition? What risks would NIPSCO bear if it owned a project, signed a long-term contract or waited for later market purchases? Public sources did not disclose final bid prices, rankings, executed future contracts, detailed customer-class bill impacts or a validated distribution of data-center load.
Alternatives for the leadership team
Own more of the next resource tranche. Utility ownership could give NIPSCO greater control over dispatch, operations and long-term asset decisions, with potential regulated returns and tax-credit value. The approach would put more construction, cost-overrun, operating and financing exposure on NIPSCO. It would require evidence that a project can be delivered on schedule and at a lifetime customer cost that compares favorably with alternatives.
Contract for more of the resource portfolio. PPAs or other supply contracts could let developers finance and construct projects, while NIPSCO focuses on system planning and delivery. Contracting could reduce direct construction exposure and preserve capital for other utility needs. The company and customers would still face contract, counterparty, profile, congestion, capacity-accreditation and market risks. Contract terms and delivered capacity would matter as much as headline price.
Sequence resources behind firm gates. NIPSCO could carry forward the near-term plan for reliability resources, while setting separate decision gates for storage, thermal contracts and any capacity associated with data centers. Under this approach, new large-load capacity would be committed only after load, credit, timing and cost-allocation terms reached defined thresholds. Staging could preserve flexibility, though waiting might increase development, equipment, interconnection or market risk.
The alternatives are discussion frames, not claims that NIPSCO formally selected them. Leadership could recommend a different approach if it is feasible and supported by the case evidence.
Questions for a decision memo
- What procurement approach should NIPSCO use for its next capacity additions, and why?
- What should be committed regardless of data-center growth? What additional evidence should trigger a separate load-driven investment?
- How would you compare ownership, BTAs, PPAs and market purchases when final bid prices and capacity accreditation are not public?
- What should a procurement scorecard measure beyond cost? Which measures should be binding gates?
- How should management distinguish system reliability, customer affordability and shareholder returns in its recommendation?
- What could the academic literature suggest about utility ownership incentives and reliability obligations? What does it not establish about NIPSCO?
- What assumptions would make your recommendation change?
Source notes
[S1] NIPSCO, 2024 Integrated Resource Plan, dated Dec. 9, 2024, especially §1.1, pp. 1–2; §4, p. 121; preferred plan and short-term action plan, pp. 284–285. IRP PDF.
[S2] NiSource, Form 10-Q for quarter ended Sept. 30, 2024, filed Oct. 30, 2024, Note 19, “Generation Transition,” and MD&A, NIPSCO Operations. SEC filing. NiSource, Form 10-K for year ended Dec. 31, 2023, Business and NIPSCO generation discussion. SEC filing.
[S3] NIPSCO, 2024 IRP Stakeholder Advisory Meeting 5, Oct. 28, 2024, resource-planning and procurement slides, pp. 20–23, 39–41, 77–78 and 111–113. Company presentation.
[S4] NiSource, “NiSource Announces Third Quarter 2024 Results,” Oct. 30, 2024, including Schedule 1 non-GAAP reconciliation. Company release.
The research dossier contains the academic source descriptions and access-depth limits. The Averch–Johnson paper is a theoretical mechanism with an original telephone/telegraph application. Carvallo et al. report historical, largely descriptive procurement patterns and interviews; they do not provide an NIPSCO-specific estimate. Delmas and Tokat is used only as provisional, abstract-level counterevidence. None provides project cost estimates for this case.