In order to fully integrate wind and other dispersed sources of energy into the system, America’s patchwork transmission networks need to be more closely interconnected and synchronized. An...
Solve the Seams
The big challenge facing the Northeast energy markets.
Council of Texas, and elsewhere.
The need for location-specific price information is driven by regional transmission organizations that have adopted standard market design-compliant market structures, as well as for market participants in regions that have yet to adopt nodal pricing but need to assess locational impacts consistent with FERC’s SMD initiative. Moreover, the use of LMPs as part of a congestion management system is viewed favorably by FERC for its ability to convey appropriate price signals to market participants. It creates the need for market participants to forecast nodal prices to assess generation or transmission system improvements, and to assess the value of congestion revenue rights in mitigating congestion exposure.
LMPs capture the cost of supplying the next megawatts of load at a specific location. LMPs are calculated using a security-constrained unit commitment dispatch model. A security-constrained model goes beyond security constraints typically included in zonal models—such as operating reserves, unplanned outages at generating facilities, and transportation-like representation of key regional transmission paths—to introduce additional constraints tied to a detailed description of the transmission network. These include transmission links and interface limits, and complex operating schedules tied to multiple interfaces.
The hourly dispatch and commitment data, along with bid curves of the units, are passed to the optimal power flow (OPF) model and an accompanying detailed transmission network model. The OPF simulation utilizes the initial EnerPrise Market Analytics Module zonal solution and cost-and-performance characteristics of generators, combined with a detailed electrical model of the entire transmission network—including important constraints associated with the electrical network—to minimize power costs subject to generator bids or costs.
Figure 5 is a visual illustration of a nodal analysis. Blue signifies an area where nodal prices are $30/MWh or less, green signifies approximately $35/ MWh nodal prices, and red signifies prices $40/MWh or more. The nodal price snapshots assist in visualizing hourly nodal prices. This type of price visualization technique assists in identifying load (red zones) or generation pockets (blue zones), as well as the congestion expected to occur within the region (spanning the red and blue zones).
Solving this range of seams issues that prevent the Northeast energy markets from operating efficiently is a key challenge for all market participants. Federal and state regulators should continue to encourage solutions and force the framing of issues in an effort to reach settlement of the differences.
1. NPCC and RFC are two of the eight the North American Electric Reliability Council (NERC) regional reliability councils in the Lower 48 U.S. states and Canadian provinces.
2. Price and resource data also is provided for the neighboring market zones denoted APS and VP.
3. “Promoting Transmission Investment Through Pricing Reform,” FERC Order 679, issued July 20, 2006. This rule is applied on a case-by-case basis and the applicant must justify his use of the specific incentives FERC has identified as allowable.
4. National Electric Transmission Congestion Study, U.S. DOE, August 2006.
5. DOE comment period ended Oct. 10, 2006.