A Structural Map of the Seven US Organized Wholesale Electricity Markets

Seven organized wholesale electricity markets cover much of the United States: CAISO (California), ERCOT (Texas), ISO-NE (New England), MISO (Midwest and Central), NYISO (New York), PJM (Mid-Atlantic and Midwest), and SPP (Great Plains). They share a recognizable architecture, but the differences between them are large enough that no model, dataset, or bidding strategy transfers cleanly from one to another without adaptation. This article maps the common structure first, then the divergences that matter.

What an ISO/RTO is

An Independent System Operator (ISO) or Regional Transmission Organization (RTO) is a nonprofit entity that operates the high-voltage transmission grid for a region and runs the wholesale markets on top of it. The distinction between the two labels is largely historical and regulatory; functionally, both do the same job: they take offers to sell energy and bids to buy it, solve a large constrained optimization problem to decide which resources run, and set prices from that solution.

The operator exists because electricity is not an ordinary commodity. Supply and demand must balance continuously, power flows follow physical network laws rather than contract paths, transmission capacity is finite, and many generators cannot change output instantaneously. A market outcome is therefore inseparable from a physical dispatch problem. Three consequences follow for anyone modeling these markets:

1. Location matters. Injecting one more megawatt at one point on the network can relieve or worsen congestion elsewhere.
2. Time is coupled. Unit commitment, ramp rates, minimum run times, and storage state of charge connect decisions across intervals.
3. Reliability constraints are binding economic constraints. Reserves, contingencies, and transmission limits can dominate the pure energy signal.

The Federal Energy Regulatory Commission (FERC) regulates interstate wholesale markets and approves the tariffs (the governing rulebooks) of six of the seven operators. ERCOT is the exception: because its grid sits almost entirely within Texas and has minimal interstate connection, it is primarily regulated within Texas and has a distinct legal and market structure.

The shared architecture

Across all seven regions, the market machinery has the same skeleton:

• A day-ahead market that commits and schedules resources for the following operating day. The operator solves a security-constrained unit commitment problem: a mixed-integer optimization with binary on/off and startup decisions, subject to energy balance, unit limits, ramping, minimum up/down times, reserve requirements, and transmission constraints.
• One or more reliability or commitment processes between day-ahead and real time, adjusting schedules as conditions change.
• A real-time market that repeatedly re-dispatches resources using updated telemetry, load, renewable output, and outages. The core engine is security-constrained economic dispatch (SCED), typically a linear program or close relative, often with look-ahead intervals.
• Ancillary-service markets, co-optimized with or linked to energy. Ancillary services are reliability products such as regulation (fast frequency control), spinning and non-spinning reserve, and market-specific products like ramping. Co-optimization creates opportunity costs: capacity awarded to reserves cannot simultaneously sell energy.
• Financial mechanisms for congestion and for differences between the two settlements.

The two-settlement system is the economic core. A participant is paid at the day-ahead price for its day-ahead scheduled quantity, then pays or is paid at the real-time price for any deviation between actual and scheduled quantity. Participants therefore care about both absolute price levels and the real-time minus day-ahead spread. Virtual bidders (traders with no physical asset) trade this convergence spread directly.

Prices are locational marginal prices (LMPs): the marginal cost of serving one additional unit of load at a specific location, conceptually decomposable into energy, congestion, and marginal loss components. Mathematically, LMPs are dual variables of the constrained dispatch problem. A price forecast is therefore an implicit forecast of which transmission constraints will bind and which resources will be marginal.

Because congestion makes prices differ across locations, every market offers financial instruments on congestion-price differences between a source and a sink. These are called financial transmission rights (FTRs) in most markets, congestion revenue rights (CRRs) in CAISO and ERCOT, and transmission congestion contracts (TCCs) in NYISO. Same concept, different names and auction details.

The seven markets at a glance

The structural differences that matter

Energy-only versus capacity markets. A capacity market pays resources for being available in the future, separately from energy actually produced, as a mechanism to ensure resource adequacy. PJM, ISO-NE, NYISO, and MISO run capacity constructs (MISO's is zonal). ERCOT deliberately does not: it is an energy-only design in which scarcity pricing mechanisms push energy prices high during tight conditions so that the energy price itself funds investment. CAISO relies on a state-administered resource adequacy framework rather than an ISO-run capacity auction. For a modeler, this changes both the revenue stack a participant optimizes and the tail behavior of energy prices.

Regulatory footprint. Six operators are FERC-jurisdictional and span one or more states; ERCOT is primarily regulated within Texas. Single-state operators (CAISO, ERCOT, NYISO) interact with one state's policy environment; multi-state operators (MISO, PJM, SPP, ISO-NE) reconcile many.

Pricing and settlement granularity. All seven use nodal LMP for the dispatch solution, but settlement structures differ. ERCOT settles generation nodally and load at zonal prices; NYISO similarly prices generation nodally and load zonally. These details determine which price series a participant is actually exposed to.

Real-time market design. All operators run repeated security-constrained economic dispatch, but interval lengths, look-ahead structure, commitment logic within real time, and scarcity adders differ by market. ERCOT's real-time SCED with its scarcity mechanisms is the canonical example of a design where administrative price adders are central.

Rule details that do not generalize. Beyond the headline design choices, the following vary by market and should never be assumed uniform: price caps and floors, ancillary-service product definitions, virtual-bid eligibility and settlement, storage state-of-charge representation, multi-part offer treatment (startup and no-load costs), market power mitigation and reference levels, uplift allocation (make-whole payments when market revenues do not cover a committed unit's costs), congestion-right terminology and auction cadence, and the timing of day-ahead, reliability, and real-time processes.

What this means for a modeling stack

The practical consequence is a common core with market-specific adapters. The algorithmic core that generalizes is probabilistic forecasting plus constrained optimization. What stays market-specific is everything that touches the rulebook: bid formats, gate closure times, product eligibility, dispatch conventions, credit requirements, mitigation, and settlement.

Common inputs across regions include market calendars and bid formats, load and renewable and weather signals, outage and topology data, nodal and zonal day-ahead and real-time prices, participant constraints, and settlement rules. When building datasets, prefer sources in this order: current tariffs and market manuals, operator data APIs and market result files, market monitor reports, FERC orders and filings, reproducible academic datasets, and only then vendor or news summaries. Rules change over time, so a reproducible dataset should snapshot the manual or tariff version that governed each trading date. Rules are features.

Glossary

• ISO/RTO: Independent System Operator / Regional Transmission Organization; the nonprofit entity that operates the grid and runs the markets for a region.
• FERC: Federal Energy Regulatory Commission; regulates interstate wholesale markets and approves the tariffs of six of the seven operators.
• Tariff: The FERC-approved (or, for ERCOT, Texas-approved) rulebook governing a market.
• LMP: Locational marginal price; the marginal cost of serving one more unit of load at a location, decomposable into energy, congestion, and loss components.
• Day-ahead market: The market that commits and schedules resources for the next operating day via security-constrained unit commitment.
• Real-time market: The market that re-dispatches resources on short intervals via security-constrained economic dispatch (SCED).
• Two-settlement system: Settlement at the day-ahead price for scheduled quantity plus settlement at the real-time price for deviations.
• Ancillary services: Reliability products such as regulation and reserves, co-optimized with energy.
• Capacity market: A market paying resources for future availability, separate from energy; used by PJM, ISO-NE, NYISO, and MISO but not ERCOT.
• Energy-only market: A design (ERCOT) with no capacity market, relying on scarcity pricing to support investment.
• FTR/CRR/TCC: Financial instruments on congestion-price differences between two locations; names vary by market.
• Virtual bidding: Financially settled day-ahead positions, with no physical asset, that reverse in real time.
• Uplift: Make-whole payments to committed resources when market revenues do not cover their offered costs.