The next megawatt has a location

Market question. If a $10/MWh generator has enough capacity to serve the whole system, why can another node still clear at $80/MWh?

Step 1

Price one additional megawatt, not the average fleet

A locational marginal price asks how total feasible production cost changes when load at one location increases by one MW. The dispatch must still balance injections and withdrawals while respecting the modeled network. FERC describes LMP as containing marginal energy, congestion, and loss components. This lesson uses a lossless radial network, so it can calculate energy and congestion but deliberately omits losses.

LMP at node = marginal energy + marginal congestion + marginal losses

Locational marginal price decomposition

Without a binding limit, the next MW in West or East can come from the same $10/MWh West resource. In the lossless teaching model, both nodes therefore have a $10/MWh marginal price. Equal prices are not caused by equal distance; they follow from a common feasible marginal resource.

Hub–East transfer capacity 100 MW

The network clears at one $10/MWh price because transfer capacity is available.Prices are the modeled incremental cost of serving one more MW at each node.

Why losses are zero here

Real network models can assign a marginal loss component because serving another MW changes electrical losses. The teaching engine does not model impedance, power-transfer distribution factors, reactive power, or marginal losses. Writing the modeled East price as $10 energy + $70 congestion + $0 modeled losses is an audit of this abstraction, not a claim that real losses are zero.

Step 2

Bind the Hub–East interface and redispatch locally

Worked example

Thirty megawatts can enter East

Assume a synthetic West resource offers at $10/MWh, an East resource offers at $80/MWh, East load is 80 MW, and the Hub–East transfer limit is 30 MW. Both resources have sufficient capacity for the quantities assigned.

Lossless two-area dispatch with a binding interface
Quantity	Value	Economic role
West offer	$10/MWh	Upstream marginal energy
East offer	$80/MWh	Local redispatch option
East load	80 MW	Withdrawal to serve
Hub–East limit	30 MW	Maximum import

The least-cost feasible dispatch imports 30 MW from West and produces the remaining 50 MW in East:

East local dispatch = 80 MW load − 30 MW import = 50 MW

Required East redispatch

modeled production cost = 30 × $10 + 50 × $80 = $4,300 per hour

Constrained production cost

The interface is already full. One additional MW of East load cannot be imported, so the East resource must increase by one MW at $80/MWh. At West, another MW can still be supplied at $10/MWh. Thus the modeled West/Hub price is $10/MWh and the East price is $80/MWh.

For this lossless case, the East decomposition is $10/MWh marginal energy + $70/MWh marginal congestion + $0/MWh modeled losses = $80/MWh. The $70 is the incremental cost consequence of the binding interface relative to the upstream energy component; it is not a toll based on miles traveled.

Hub–East transfer capacity 30 MW

Prices separate. West: $10/MWh, Hub: $10/MWh, East: $80/MWh. The Hub–East interface is constrained.Prices are the modeled incremental cost of serving one more MW at each node.

Pause and predict

With East load fixed at 80 MW, what happens if the Hub–East limit rises from 30 MW to 100 MW and no other constraint binds?

Step 3

Use observed prices without reverse-engineering a cause

ERCOT publishes nodal, hub, and load-zone price products as well as correction archives. A June 5, 2026 ERCOT notice says real-time prices for operating day January 24, 2026 were significantly affected by a software defect and that corrected CSV/XML files would be posted. Therefore any January 24 spatial-price analysis must use those corrected files.

This lesson does not quote an interval value from the preliminary series or claim that one constraint caused observed separation. A corrected price spread can establish that locations settled differently; explaining the cause also requires topology, binding constraints, shadow prices, losses, dispatch, adders, and timestamp alignment.

Apply the mechanism

In the synthetic network, West offers at $10/MWh, East offers at $80/MWh, East load is 80 MW, and the Hub–East limit is 30 MW. Calculate East local dispatch and the modeled East price, then explain why it separates from West and name the omitted LMP component.

Your response

Takeaways

A nodal price is the incremental cost of serving load at a location under the modeled constraints.
In the exact synthetic case, 30 MW is imported and 50 MW is locally redispatched; East clears at $80/MWh while West/Hub clears at $10/MWh.
The lossless decomposition is $10 energy + $70 congestion + $0 modeled losses; real LMPs can include a loss component.
Observed price separation does not identify its own cause, and corrected ERCOT files supersede preliminary January 24, 2026 values.

Selected sources

Sources and model boundaries

Federal Energy Regulatory Commission: Energy PrimerRetrieved 2026-08-03.
A broad federal primer; it does not substitute for market-specific tariff and operating-rule analysis.
Federal Energy Regulatory Commission: Understanding Energy MarketsRetrieved 2026-08-03.
High-level market-design context; regional implementation details vary by organized market.
ERCOT: Market PricesObserved: Operating day 2026-01-24; corrected RTM files approved 2026-06-01.Retrieved 2026-08-03.
ERCOT publishes observed prices and correction archives. January 24, 2026 analysis must use corrected RTM files; prices alone do not reconstruct dispatch, offers, constraints, losses, adders, or settlements.
ERCOT: Market Notice: January 24, 2026 Price CorrectionObserved: Notice issued 2026-06-05 for operating day 2026-01-24.Retrieved 2026-08-03.
The notice says January 24 RTM prices were significantly affected and directs use of corrected CSV/XML files. It does not itself report the corrected interval values or identify a congestion cause.