Developers want to connect data centers quickly, with as much firm grid service as possible. Across six US markets, getting that service means choosing among different financial commitments, operating restrictions and potential obligations to a generation partner. Applying with paired generation can change the study or service available.

The Federal Energy Regulatory Commission (FERC) is reviewing those pathways through its June 2026 Show Cause orders. It directed the operators under its jurisdiction to justify or reform their rules for data centers, including protections for existing customers. ERCOT follows a separate Texas framework and has its own process for large load interconnection.

Key takeaways

• SPP, MISO and NYISO link load and generation, but pairing changes the study in SPP and MISO and the service rights in NYISO.
• Financial obligations for load interconnection vary: a 500 MW load would owe a $25 million deposit in ERCOT, while MISO proposes a $250,000 fee.
• MISO targets an agreement 120 days after a complete application, under a quarter of NYISO's 545-day study sequence.
• Only 7% of ERCOT's requested load reaches the 2030 forecast, against 49% in PJM. Fees and deposits separate committed projects from speculative data center applications.

Paired generation changes the study or the service data centers can receive

In SPP, MISO and NYISO, the value of pairing depends on what the operator studies and how generation supports the campus's grid service.

SPP links the load and its generation but studies them separately, through the High Impact Large Load process and the High Impact Large Load Generation Assessment (HILLGA). HILLGA has been effective since January 15, 2026. MISO instead proposes assessing load and generation in parallel through its Large Load Addition Resource Study (LARS), filed on October 2.

In contrast to both, NYISO's proposal puts the emphasis on service: a Partner Resource's contribution to reliable supply supports the campus's firm withdrawal rights. Those rights let the campus take grid power, subject to operating conditions. NYISO’s Management Committee approved its Large Load Integration Procedures on October 28. Modo Energy previously covered the process as Bulk Electric Large Loads (BELL).

Elsewhere, the arrangements address flexibility, information or on-site generation. CAISO’s Board approved a flexible interim load interconnection service on October 28, ahead of a planned FERC filing. FERC accepted PJM’s registry for large loads on October 9, but rejected its paired-generation and interim-service proposals. ERCOT’s private-use election covers generation behind the load’s meter, but Batch Zero studies and energization approvals have been paused since August 3.

Entry payments determine financial commitments for data centers and their generation

Load and generation post different amounts, and the split differs by market. The figures below assume a 500 MW pairing, with each side requesting 500 MW. In MISO, SPP and NYISO the per-MW amounts scale with requested interconnection capacity, not accredited capacity, so every technology posts the same costs.

ERCOT's load-side commitments total $25.1 million in the example, including a $25 million security floor of $50,000/MW. Allocated upgrades can increase the security. NYISO’s $4.6 million covers both parties, while MISO proposes a non-refundable $250,000 fee from the load's transmission customer. In contrast, PJM charges nothing itself, but utility-level charges run from $250,000 for Dominion to $2.5 million for ComEd.

For generators, MISO proposes $15.49 million at 500 MW of requested service, including a $30,000/MW milestone. SPP’s HILLGA requires $4.27 million at 500 MW, less than a third of MISO’s. ERCOT’s posted generator fees total $17,000, before transmission-provider costs and security.

Separate generation queues have their own entry requirements. PJM's generation-only Expedited Interconnection Track (EIT) requires $8 million for a 500 MW request. CAISO’s $755,000 is the entry cost of its generator queue, before agreement security and network upgrades.

MISO's withdrawal provisions show that a posted amount is not always the amount at risk. Its $30,000/MW generator milestone is refunded in full on withdrawal before the agreement is executed, and is at risk afterward. A developer's exposure therefore depends on the payment type and when it withdraws, rather than the headline amount alone.

MISO's study timeline to an agreement is 120 days, under a quarter of NYISO's 545 days

MISO, SPP and NYISO each set a study timeline from a complete application to a tendered interconnection agreement, and the targets differ by more than a year. MISO proposes an agreement in 120 days, under a quarter of NYISO's 545-day sequence. SPP's 150 calendar days cover validation, study and negotiation, plus up to 10 business days to tender the agreement. NYISO’s 545 days are two 90-day studies and a 12-month assessment that runs once a year.

For projects with associated generation, study approval can tie the generator to the load for years. MISO proposes a 15-year pairing obligation from the day the load begins LARS transmission service. MISO's stated reason is to stop a generator using a load application as a shortcut into the queue.

NYISO proposes the same 15-year term for a Partner Resource, and the campus’s firm rights last only while the resource stays in the capacity market. SPP's load-limited rights last 5 years and begin at the generator's commercial operation.

In all three markets, the campus's delivery schedule becomes part of the generator's commitment, well beyond the initial application.

Two routes bring generation online beside data centers: a pairing, or a separate generation queue

Pairing puts the generator in a dedicated track connected to a named load. In SPP that is HILLGA, with exports capped at the paired load's forecast, and in MISO it is LARS, with at least 200 MW of requested Network Resource Interconnection Service. In NYISO the Partner Resource goes through the standard cluster study and is tied to the load's application.

The second route is the expedited generation queue that MISO, SPP and PJM opened to meet load growth, which has favored natural gas in the first two. Natural gas is 69% of the 32 GW in MISO's Expedited Resource Addition Study (ERAS) and thermal plant 72% of SPP's equivalent track. PJM is the exception: its first EIT intake of 2.1 GW is 78% batteries.

ERCOT has no expedited generation queue. Instead, the 11 Batch Zero loads that elected private-use networks name 15.4 GW of generation behind their meters, 83% of it natural gas.

Only 7% of ERCOT's requested data center load reaches the 2030 forecast, against 49% in PJM

Modo Energy’s Q4 2026 estimate of data center capacity added in 2026 to 2030 is 32.6 GW in ERCOT and 29.6 GW in PJM. That is 7% of the 494 GW requested in ERCOT and 49% of the 60 GW in PJM.

Fees, deposits and readiness requirements give operators evidence of which developers are prepared to commit. These screens help distinguish credible projects, but equipment availability and construction schedules still constrain delivery. As projects clear those screens, planners gain better evidence for the transmission and generation required to support the load.

ERCOT's 494 GW, classified in Batch Zero, is 542% of its 91 GW record peak. No other market's reported pipeline exceeds 52% of its current record peak demand. Many of these requests are speculative and never reach an agreement.

Upcoming filings could change the routes developers can use

The November 16 filings are the next point to reassess the available service options and protections for existing customers. MISO has requested December 2 tariff effectiveness with a proposed LARS launch in early 2027. Texas has a separate calendar: the Public Utility Commission of Texas has an open meeting scheduled for December 17.

For campuses, earlier power may come with operating restrictions or a continuing obligation to paired generation. For generators, pairing can tie the investment to the customer’s delivery schedule and ongoing service. The next decisions matter because they could change those terms, including which rights developers can obtain and what they must commit to retain them.