How traders hedge congestion risk on the grid.
In an LMP-based market, the price of electricity differs by location. A generator in western Pennsylvania might see an LMP of $30/MWh while a load in New Jersey pays $45/MWh — the $15 difference being the congestion component caused by a binding transmission constraint between them.
This price uncertainty creates a business problem. A New Jersey utility that contracts with a Pennsylvania generator for power at $30/MWh will still pay $45/MWh at its delivery point — the congestion cost eats the savings. And that congestion cost varies hour to hour, day to day, season to season. Without a hedging instrument, buyers and sellers face unpredictable basis risk — the risk that the price difference between two locations will move against them.
Financial Transmission Rights (FTRs) are the market's answer to this problem. An FTR is a financial contract that pays its holder the congestion price difference between two specific points on the grid. If you hold an FTR from Bus A to Bus B for 100 MW, and the congestion component from A to B is $15/MWh in a given hour, you receive $15 × 100 = $1,500 for that hour.
FTRs come in two basic forms:
Obligations: The holder receives payment when congestion flows in the FTR's direction, but pays when congestion flows the opposite way. These are the most common type and can have negative value — an important risk that traders must manage.
Options: The holder receives payment when congestion flows in the FTR's direction, but owes nothing when congestion reverses. Options are more expensive to acquire but eliminate downside risk.
ISOs/RTOs allocate FTRs through periodic auctions. PJM, for example, runs both annual and monthly FTR auctions. Participants bid for FTRs along specific paths — say, from the Western Hub to the Eastern Hub for 50 MW during peak hours in July. The ISO clears the auction using a model of the transmission network, ensuring that the set of awarded FTRs is simultaneously feasible: the total FTR positions cannot exceed the physical capacity of the grid.
This feasibility requirement is crucial. The ISO funds FTR payments from congestion revenue — the money collected when LMPs differ across locations. If FTRs are allocated within physical limits, congestion revenue should be sufficient to pay all FTR holders. In practice, revenue adequacy is imperfect due to transmission outages and modeling approximations, but the principle holds.
Load-serving entities (utilities, retail suppliers) are the natural hedgers. They buy FTRs along paths from generation sources to their load zones, locking in the delivered cost of power. A utility serving Philadelphia might buy FTRs from western PJM generation hubs to the Philadelphia zone, insulating itself from congestion price spikes.
Generators use FTRs to guarantee that the price they receive at their bus translates to a competitive delivered price at major trading hubs.
Financial traders buy and sell FTRs speculatively, profiting from superior knowledge of congestion patterns. Some firms employ meteorologists, grid modelers, and data scientists to forecast which transmission paths will congest — and when. This speculative activity provides liquidity and, in theory, improves price discovery.
FTRs have been controversial. In 2018, the FERC-commissioned Brattle Group report found that financial traders in PJM had earned over $400 million in FTR profits over several years, raising questions about whether the FTR market was functioning as intended. Critics argued that traders with superior information were extracting rents from the system at the expense of consumers.
The fundamental tension: FTRs are designed as hedging instruments for physical market participants, but they trade in a secondary market where financial firms dominate. Whether this financial participation improves efficiency (through better price signals) or extracts value (through informational advantages) remains actively debated.
One of the subtler aspects of FTR markets is the concept of counterflow. If most power flows from west to east, an FTR from east to west is a counterflow FTR. Counterflow FTRs can be valuable because they free up capacity for prevailing-direction FTRs — the ISO can award more west-to-east FTRs if some participants hold east-to-west counterflows that net out against them.
But counterflow FTRs are also risky. If congestion patterns shift unexpectedly, counterflow holders can face large losses. Several spectacular trading losses in FTR markets have involved counterflow positions that went wrong.
The GreenHat Energy Collapse (2018)
In June 2018, a small trading firm called GreenHat Energy defaulted on $179 million in FTR obligations in PJM — the largest default in the history of U.S. power markets. GreenHat had accumulated an enormous portfolio of FTR positions, many of them counterflow, betting that historical congestion patterns would persist. When new transmission upgrades and changing generation patterns altered congestion flows, GreenHat's positions turned deeply negative.
The firm's two principals — a former PJM employee and his partner — had exploited a loophole: PJM's FTR market had minimal credit requirements for existing positions, allowing GreenHat to build a multi-billion-dollar notional portfolio with almost no collateral. When the positions went bad, GreenHat simply couldn't pay.
The loss was socialized across other PJM market participants — ultimately, electricity consumers in 13 states. The episode prompted sweeping reforms to PJM's credit policies and renewed scrutiny of financial participation in electricity markets. It was a vivid reminder that financial instruments designed to manage risk can, in the wrong hands, create it.