Utilities are using automation and back-office systems to improve their performance on outage management and service restoration. The next generation of smart-grid technologies promises a...
Reconsidering Resource Adequacy, Part 2
Capacity planning for the smart grid.
play an active role in forecasting the impacts of these programs and determining the capacity requirements they displace in each area.Where RTOs prepare peak load forecasts for the entire RTO region, affording a greater role in forecasting future peak loads (and load reductions) to states, utilities and LSEs potentially could reduce the risk that these forecasts will fail to reasonably anticipate future peak load reductions. Should emergency purchases or firm curtailments be required due to a shortage of capacity, the costs and curtailments should be allocated to those entities that are short on capacity in proportion to their shortages, to the extent this is feasible.
Because adequacy criteria focus on curtailment of firm load, reserve margins and capacity requirements should be based upon the peak load levels expected to result under the most extreme scarcity pricing conditions, with prices and incentives at the highest possible levels and leading to maximum load reductions.
At present, reserve margins and capacity requirements are driven by forecasts of extreme peak load conditions expected to occur very rarely. As peak loads become more manageable, capacity requirements will decline and be targeted to net load levels likely to occur with much greater frequency, due to peak shaving and also the shifting of load reductions to adjacent hours. If loads on the highest load days can be managed (as needed) down to the load levels that occur many more days each year ( see Figure 3 ), much less capacity will be needed to satisfy the one-in-10 criterion, and the least-used capacity will be called upon to provide energy or ancillary services in many more hours.
As noted above, increases in peak load and capacity requirements are presently much more uncertain than they were in the past, due to uncertainties about economic growth, higher electricity prices, increasing efficiencies, and other demand-side developments. These circumstances suggest that maintaining flexibility in capacity procurement is especially valuable at this time and can reduce the risk and potential cost of procuring excess capacity, or paying excessive prices for capacity, years in advance.
The risk of procuring excessive amounts of capacity is greatest where capacity requirements are determined and committed to years ahead, for instance, where RTOs require fulfilling capacity obligations three years in advance ( e.g., the ISO-NE and PJM RTOs). However, as noted above, many of the incremental resources available at this time have fairly short lead-times. When substantial short lead-time resources are available, three-year advance mandatory procurement isn’t necessary to ensure adequate lead time to acquire needed resources for reliability, and it also may exclude or impose risks on shorter lead-time resources, who may not be prepared to offer their capacity so far in advance. Nor does mandatory forward procurement contribute in a significant way to the ability to attract major new power plants; such facilities require long-term contracts or other long-term revenue assurance.
The risk of excess procurement associated with forward procurement obligations can be reduced by providing additional flexibility in fulfilling the forward purchase obligations. A small step in this direction is accomplished by reducing the fraction of