Consolidating, and comparing, battery revenues across the Eastern Interconnection's four ISOs is rarely straightforward. Unlike ERCOT, an energy-only market, the region layers capacity payments on top of energy and reserves. Ko brings these datasets together in the Terminal.

PJM, MISO, NYISO, and ISO-NE each price the stack differently. Without the full picture, it is easy to miss why two batteries recorded very different outcomes in the same week.

Ko can rank spreads across markets, test where and when to build, and identify causes of price spikes to determine a trader's strategy. Ask a question in plain English: Ko identifies the right table, writes the SQL, queries live data, and explains the result.

This guide walks through five worked examples for analysts, developers, and energy traders. In each case we show the prompt, a chart built from the data Ko returned, and the insight Ko generated.

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What Eastern Interconnection data does Ko have access to?

Modo Energy has integrated Ko with the EI market stack across all four ISOs.

• Forecasts. Modo's Central scenario projections of prices, capacity, revenue, and buildout: the forward layer, out to 2050.
• The ME BESS benchmark simulation. Per-ISO 5-minute simulated dispatch and revenue by market: the backtest layer for the past.
• Energy prices. Nodal and zonal locational marginal prices for every ISO, day-ahead (hourly) and real-time (5-minute).
• Reserves and regulation. Day-ahead and real-time clearing prices for each ISO's ancillary products, including PJM regulation market results and dispatched reserves.
• Load. Actual and real-time demand for PJM, MISO, NYISO, and ISO-NE.
• Generation by fuel type. Real-time and hourly fuel mix for all four ISOs, so a price move can be traced to what was on the margin.
• Plant and generator data. EIA-860 generator inventory (nameplate capacity, technology, owner, status, location) and EIA-923 net generation and fuel use.
• Node and zone reference. Node listings, node-to-zone, and reserve-subzone mapping.

The examples below were produced by asking Ko questions against this stack. Ko generated the SQL, queried the data, and produced the analysis. All charts were rebuilt from the same Ko response.

Market analysts: comparing spreads between ISOs

1. Across PJM, MISO, and ISO-NE, how much wider were real-time 4-hour top-bottom spreads than day-ahead in May 2026? Where was the real-time premium largest?

Output:

In all three markets, real-time spreads outran day-ahead in May 2026, confirming that weather-driven scarcity is systematically hard to forecast a day ahead. In absolute terms, PJM posted the largest premium at about $155/MW-day (real-time $389/MW-day against day-ahead $234/MW-day), reflecting the scale of the Mid-Atlantic spike.

As a percentage, ISO-NE's premium was the steepest at 83% (real-time $214 against day-ahead $117). New England is a thin, constrained market where an unexpected demand surge drives outsized real-time moves. MISO Indiana sat in between at 60% (real-time $218/MW-day against day-ahead $136/MW-day). For analysts, PJM is the highest-reward real-time market in dollar terms while ISO-NE carries the largest proportional edge.

2. In PJM, how should a 4-hour battery split between regulation and energy arbitrage in May 2026, and what is regulation clearing?

Output:

Six months after the October 2025 regulation redesign, regulation is not an add-on but the major piece of a BESS revenue stack. In May 2026 the modeled stack for a 4-hour battery was $73/kW-month: regulation $56/kW-month (77%), real-time energy arbitrage $12/kW-month (16%), and capacity $5/kW-month (7%). Regulation cleared $97/MWh, down from April's $104 but 3.4 times May 2025's $29/MWh. Pre-redesign, the fleet averaged about $20/kW-month; post-redesign it has averaged about $62/kW-month.

The practical takeaway for analysts: regulation is the structural anchor and should be bid first and continuously, while energy arbitrage is weather-contingent. Phase 2 of the redesign, due October 2026, will split the signal into separate regulation-up and regulation-down (RegUp and RegDown) products, which could redistribute clearing prices.

Developers: where to build, and when with Ko

3. Within PJM, how does the zone you connect to change a 4-hour battery's real-time top-bottom spread? Rank the zones for May 2026.

Output:

Zone choice is one of the most consequential siting decisions in PJM. In May 2026 the Mid-Atlantic dominated: Virginia (DOM) cleared a real-time top-bottom spread of about $916/MW-day, up 118%, nearly four times Pennsylvania (PPL) at about $232/MW-day. Baltimore (BGE) reached about $631/MW-day (up 124%) and Washington DC (PEPCO) about $614/MW-day (up 89%).

The premium is structural. Persistent transmission constraints between eastern load centers and western generation widen price separation during every scarcity event. The heat wave loaded those constraints exactly where they bind hardest. Western zones such as ComEd cleared less than a third of Virginia's spread.

4. According to Modo's forecasts, how do NYISO, PJM, and MISO capacity prices diverge through 2050, and what does that mean for where to build?

Output:

Under Modo's Central scenario the three markets diverge sharply from the mid-2030s. NYISO roughly quadruples from about $6/kW-month today to a peak near $24 to $25/kW-month around 2040 to 2045, driven by data-center and electrification load in one of the most constrained build environments in the US. PJM peaks earlier, around 2030 to 2033 near $18 to $21/kW-month as its large interconnection queue delivers, then falls below $5/kW-month by 2045 as supply overtakes load.

MISO stays range-bound in the low-to-mid single digits before rising in the 2040s. For a 4-hour battery, capacity revenue roughly equals the clearing price times qualified capacity until 2029.

NYISO downstate zones already clear a record $32.6/kW-month for summer 2026, and in the Central scenario that stream keeps rising for nearly two decades, though a faster build or weaker load would shift the peak earlier. PJM projects, by contrast, need to commission before the early-2030s peak.

Energy traders: where the value sits to capture now

5. Why was there a price spike in MISO in February 2026? Identify the spike and its causes.

Output:

MISO had two distinct day-ahead price spikes in February 2026. The primary event was Winter Storm Fern on 1 to 2 February, when a Midwest heating-demand surge met 11,000 to 13,300 MW of forced thermal outages and low wind output. The day-ahead peak hub reached $217/MWh on 2 February, and real-time at Indiana Hub topped $1,100/MWh.

Northern hubs averaged $51 to $52/MWh for the month against $31 to $33 in the south, a roughly $20/MWh gap from transmission constraints. A second, localised spike on 24 February briefly lifted the peak hub to $218/MWh while the daily average stayed near $39. Ancillary services moved with energy: real-time regulation cleared $94/MWh on 2 February.

Ko links your questions to real-time Modo Energy data

Across the four ISOs of the Eastern Interconnection, Ko moves from a question to the relevant data and analysis faster than the manual alternative. The value is clearest when a question cuts across markets or across the revenue stack: Ko identifies the table, returns the result, and explains what it means in context. Ko does not replace analyst judgement. It helps test the first answer, surface the data behind it, and show where deeper analysis is needed.