Unexpected price increases for natural gas during the past winter heating season have stimulated action by state regulators across the country. Most recently, North Carolina and New Mexico have...
Generation Reserves: The Grid Security Question
will identify a single line or generating station that, if it failed, would cause a cascading blackout. To eliminate the possibility of additional failures causing a blackout, operators change the power flows by starting some generators and reducing power to others. Contingency planning is a part of SCUC, which has been proposed in FERC's SMD.
The consumers' cost has decreased by $15 million and $74 million, respectively, for scenarios 7 and 8 compared with the no-SCUC cases, as shown in Table 4.
Similarly, the producers' costs for the day have decreased by $1.3 million and $2.9 million, respectively. This case clearly demonstrates the benefits of contingency planning across the entire network. In this case, the blackout is controlled, and as a result is confined to a much smaller area. That reduces unserved energy considerably, and consumers benefit because of increases in the efficiency of the generation. This case shows that we can obtain better security with the existing system, which is economically beneficial to the customers.
By comparing the daily costs that producers incur when contingency planning is in place with their costs when no contingency planning is used, we can quantify the cost to producers of contingency planning on a typical day when no outages occur. The two cases, besides assuming no outages or failure, incorporate 3.5 percent synchronized operating reserves. They show that the recurring cost of committing additional units and operating them at minimum loading to provide security-constrained unit commitment and economic dispatch adds $1.969 million per day ($719 million per year), which is approximately 1.95 percent more than the annual operating cost of $39 billion. In terms of total customer payments, that represents an increase of 0.04 cents per kilowatt-hour. FERC proposes both operating reserve (ancillary services) and contingency planning. Our analysis has shown that the combination of 3.5 percent synchronized reserve and appropriate N-1 and N-2 contingency planning provides the greatest benefits in a cost-effective manner.
Figure 3 shows how the contingency planning with 3.5 percent synchronized reserve can effectively eliminate unserved energy in scenarios 1 through 6. Scenarios 7 and 8 assume that the sequence of cascading outages already has taken place and the affected generators and the transmission lines are no longer available to the system operator. In reality, the SCUC may prevent the sequence of cascading outages well before the blackout takes place. Our simulations illustrate that even if the operator is unable to stop the outages, the customer disruption is contained, and unserved energy is considerably reduced.
- UPLAN-Network Power Model (NPM) is fully compliant with FERC's standard market design (SMD) and meets all the functional requirements of a regional transmission organization (RTO) proposed in FERC Order 2000. The model can accurately dispatch generators as well as forecast locational marginal and zonal prices. Locational marginal pricing (LMP) is the basis for congestion management in the proposed SMD and is used in many RTO/ISOs, including PJM and NY-ISO.
UPLAN's Security Constrained Unit Commitment (SCUC) and Security Constraint Economic Dispatch (SCED) for real-time dispatch meet all the requirements of optimally allocating generating and transmission resources