​MISO's Expedited Resource Addition Study (ERAS) promises Generator Interconnection Agreements (GIAs) in three months instead of the 2.5 to 5 years required under the Definitive Planning Process (DPP). However, for merchant BESS developers, those savings are inaccessible. ERAS requires an executed off-take agreement, 100% site control, and regulatory confirmation of capacity need. As a result, gas captured 75% of capacity in Cycles 1 and 2. All four BESS projects that qualified are utility-owned or have contracted off-take.

In this research, we examine:

• How ERAS eligibility requirements exclude merchant BESS
• What Cycles 1–2 results reveal about fuel mix and ownership
• Why most BESS developers will remain in the DPP queue

Key takeaways

• ERAS saves years but costs more. A 100 MW BESS pays $2.8 million through ERAS versus $1.1 million through DPP, buying 30+ months of timeline acceleration.
• The off-take agreement requirement excludes developers without utility contracts, ownership, or other a bilateral off-take agreement with an industrial customer.
• Gas dominates ERAS applications. Natural gas captures 75% of ERAS capacity across Cycles 1 and 2. BESS represents just 8%.
• All ERAS BESS projects are utility-affiliated. Four projects totaling 989 MW have qualified. None are merchant.

How does ERAS differ from the standard interconnection queue?

ERAS compresses years into months. Specifically, a project entering in Q1 can receive its GIA by Q3 of the same year. In contrast, the DPP averages 2.5 to 5 years for the same outcome.

Six stages separate queue entry from GIA. Notably, application review and study periods run concurrently with state regulatory processes.

However, the speed comes at a price.

ERAS requires $24,000 per MW in M2 deposits (due at the application window) versus $8,000 per MW under DPP. Additionally, D1 application fees run $100,000 compared to $5,000. Projects must also demonstrate 100% site control at application; DPP requires only 50%.

How much does ERAS cost?

A 100 MW BESS pays $2.82 million upfront through ERAS versus $1.13 million through DPP. Consequently, the $1.7 million premium buys 30 months or more of timeline acceleration.

At 400 MW, ERAS costs reach $10.1 million. The $24,000/MW M2 deposit drives this scaling. But, for projects with firm commercial operation dates tied to utility contracts, that acceleration can justify the cost.

Who can use ERAS?

Four requirements combine to filter out merchant generation:

• Off-take agreement: Projects must have an executed power purchase agreement, tolling agreement, or utility ownership. As a result, merchant developers building for wholesale markets cannot qualify.
• 100% site control: Applicants must demonstrate full site control at application. In contrast, DPP requires only 50% initially.
• Three-year COD: Commercial operation must occur within three years of GIA execution.
• RERRA support: The Relevant Electric Retail Regulatory Authority (RERRA) must confirm the project addresses a capacity need. In practice, this typically means utility commission approval.

Together, these requirements create a structural barrier. Merchant BESS developers rarely have off-take agreements before interconnection studies confirm project viability. Standard development runs: queue position first, then PPA negotiation, then financing. ERAS inverts this sequence entirely.

What do the first two cycles reveal?

Gas dominates ERAS applications. Across Cycles 1 and 2, natural gas accounts for approximately 9,150 MW, or 75% of total capacity. Meanwhile, solar, BESS, and wind each captured roughly 8%.

The technology split in ERAS diverges sharply from MISO's broader queue. In DPP 2025, BESS represents the largest fuel type by capacity. In ERAS, however, it ranks last among major technologies. Gas projects with utility off-take dominate instead.

ERAS is currently evaluating two Study Cycles (1 and 2) while pending projects include those who have applied for ERAS but were not selected for either cycle.

Geographically, pending projects are clustered along the Gulf Coast and in the Upper Midwest. Louisiana hosts multiple gas projects exceeding 1 GW, driven by LNG export demand and industrial load growth. Similarly, Wisconsin's two largest pending projects are Invenergy gas plants serving utility capacity needs.

The four BESS projects share a common characteristic: utility affiliation.

DTE, Ameren, and Otter Tail are vertically integrated utilities developing storage for their own systems. NextEra's Louisiana project has an executed off-take agreement with a utility counterparty. Notably, no merchant BESS project appears in either cycle.

What does this mean for BESS developers?

Merchant BESS will remain in the DPP queue. The off-take requirement alone disqualifies most independent developers. Furthermore, the ERAS premium of $1.7 million per 100 MW makes sense only when a utility contract exists and a specific commercial operation date drives value.

The 8% BESS share in ERAS does not reflect market opportunity. Instead, it reflects which projects happen to have utility backing. The 51 GW of BESS in MISO's DPP queue faces different economics: longer timelines, but no off-take requirement and lower upfront deposits.

Ultimately, ERAS will accelerate utility-owned storage serving integrated resource plan targets. It will not accelerate the merchant development that dominates MISO's interconnection queue.