Inpower engineering,transmission congestion occurs when overloadedtransmission lines in anelectrical grid are unable to carry additionalelectricity flow due to the risk of overheating. During grid congestion, thetransmission system operator (TSO) has to direct the providers to adjust theirdispatch levels to accommodate the constraint.[1] In anelectricity market a power plant may be able to produce electricity at a competitive price but cannot transmit the power to a willing buyer.[2] Congestion increases the electricity prices for some customers.[3]
There is no universally accepted definition of the transmission congestion.[2] Congestion is not an event, so it is frequently not possible to pinpoint its place and time (in this respect it is similar totraffic congestion[4]). Regulators define congestion as a condition that prevents market transactions from being completed,[2] while atransmission system operator sees it as inability to maintain thesecurity of the power system operation with thepower flow scheduled for the grid.[3]
A congestion is a symptom of a constraint or a combination of constraints in a transmission system,[3] usually the limits on physical electricity flow are used to prevent the overheating,unacceptable voltage levels, and loss of system stability. Congestion can be permanent, an effect of the system configuration, or temporary, due to a fault in the transmission equipment.[5]
Avoiding the congestion is essential for a competitiveelectricity market and is "one of the toughest problems" of its design. The goal is to ensure that a power flow as defined by the wholesale market result does not violate the constraints during the normal operation of the grid and in the case of failure of any one particular component (so calledn-1 criterion).[6]
The existing markets use a range of approaches to solve the problem. On one end of this range is "uniform pricing" that ignores the transmission constraints altogether and lets the market find a single price for all the locations ("nodes"). On the other end "locational marginal pricing" accommodates all the constraints by defining a separate pricing for each node (thus another name, "nodal pricing").[6]
The uniform pricing has an advantage of transparent market design and quick clearing, so auctions can happen frequently, typically they start a day ahead of the delivery ("day-ahead" auction) and continue until the delivery (so called "intra-day" auctions).[citation needed] However, the market result might violate the congestion constraints and thus cannot be implemented at the time of delivery (in "real-time"). If this is the case, the TSO intervenes and uses so calledsystem redispatch by changing the schedules of the generators in a way that the load can be served.[6] Redispatch payments are usually negotiated in advance and providers are paid as they bid in a "command and control" fashion, without creating a market.[7]
With nodal pricing all grid constraints are accounted for during the clearing and different prices are set for different nodes, this typically requires theindependent system operator (ISO) to manage the market clearing.[8] The drawback of the nodal pricing is that the local markets might not have enough participants to efficiently function. In particular, in theload pockets (areas of the grid with concentrated load and lack oftie lines to the rest of the system) a large generator might exhibit significantmarket power, forcing the price for this node to be directly regulated on a cost basis.[citation needed]
The zonal pricing represents a compromise where the grid is split into relatively large zones, electricity price within each zone is uniform (and thus intra-zone congestion need to be resolved with a redispatch), but the inter-zone constraints are accounted for during the market clearing via different prices for different zones.[9]
The "discriminatory pricing" the providers in case of acceptance of their bids by the system operator are paid the amount of their bid ("pay-as-offered",[10] "pay-as-bid").[11] The discriminatory pricing is also used in a market-based redispatch scenario (counter-trading).[7]
To avoid congestion, it might be necessary to deny some transmission transactions. One way to do it is through thetransmission rights. The owner of a transmission right is entitled to transport a predefined amount of electric power from a source location on the network to the destination. There are two types of transmission rights:[12]
In a simple example of FTR operation,[13] locations A and B are connected with a 1000 MW line. Location A has a load of 200 MW and two generation companies:
Location B has a load of 2500 MW and a single generator GB with 2000 MW capacity and marginal cost of $30/MW.
The electricity market with locational pricing will fully engage the 1000 MW line andsettle on:
GA1, standing to gain most if the links between A and B are improved, decides to build another 1000-MW transmission line. Now there is no congestion, and the market will settle at the same price in both A and B ($30, since GA1 and GA2 cannot satisfy all demand, and the price will be determined by the cost of GB). GA1 will hold the FTR for 1000 MW, but will not collect anything from this right, instead pocketing the difference between its $10 cost and $30 price.
A new plant, GA3, is constructed in A with capacity of 1000 MW and marginal cost of $9/MW. Now the pricing in A is $15 again (determined by GA2), pricing at B is still $30. Although the line built by GA1 might now be effectively used by GA3, GA1 as a holder of FTR receives the congestion rent for electricity transmitted over the line that GA1 had invested into. The arrangement works as if GA1 had leased the line to GA3 for the full value of the line, so FTRs are similar totradable securities, but with automated trading.[13]
Sometransmission system operators offer the transmission rights owner to collect the transmission fees for them. For example, in California theCalifornia Independent System Operator (CAISO) offers the PTR owners a scheme where the owners hand over theoperational control of their infrastructure to CAISO in exchange for the "Transmission Revenue Requirement" (TRR) that recoups the owner's costs. CAISO in turn collects theTransmission Access Charge (TAC) from the utilities based on thegross load,[14] and utilities bill TAC to their customers.