According to the resource adequacy outlook detailed in Section II, under the Base Case scenario, New England will need 1,500 MW of new capacityby 2024; under the Tight Supply scenario, the region could need 4,000 MW of new capacity by 2024. Connecticut will not need new in-state capacity through 2024 to meet ISO-NE’s Local Sourcing Requirement, unless the Millstone nuclear plant somehow became inoperable. However, system reliability and generation rates for Connecticut ratepayers will be affected by the higher regional capacity prices, driven by the regional capacity need.
Under our deregulated market system, new generation capacity is procured through a regional capacity auction, administered annually by ISO-NE to procure capacity to meet projected regional electricity demand three years in the future. The eighth Forward Capacity Auction (FCA 8), conducted in February 2014 for supply commitments beginning in 2017, was the first to result in a capacity shortage. The ninth auction (FCA 9) attracted capacity commitments from new resources, testing the ability of the capacity market construct to attract power plant investments in the region for the first time. Although the capacity market did attract capacity there remains some uncertainty whether it will continue to do so in the future. Adding to the uncertainty is the fact that the ISO-NE has recently instituted major changes in the capacity market rules, including the adoption of a complicated new Pay-for-Performance incentive program.
For these reasons, Connecticut needs to be prepared for the possibility that regional capacity auctions do not deliver new generation resources when called upon to meet capacity needs. If this possibility were to occur, Connecticut’s rates and reliability would be significantly impacted. This IRP recommends monitoring for market failures and developing contingency plans so that actions under state authority can be taken to avoid capacity shortages if necessary. For example, as described in Resource Strategy #2, recent court decisions regarding the participation of active DR in the energy markets, if upheld, would necessitate action by the state to insure that active DR can impact energy markets.
Beginning with the next capacity auction (for delivery years 2018/19), DEEP will look for the following signs that the market is not working to gauge if, when, and/or how much market intervention is needed:
• Large amounts of non-price retirements for reasons other than plant failures or major capital expenditure needs comparable to the cost of new generation. • Very limited new entry of low-cost resources such as DR and generation
uprates as prices rise to $5, $8, or even $10/kW-mo. If DR is allowed to participate but is not entering, it will be important to determine whether the cause is the lack of market participants’ faith in the capacity market or narrow barriers posed by ISO-NE’s participation rules for DR.
• The DR is not allowed to participate in wholesale markets.
• The forward auction fails to clear enough capacity on a three-year forward basis.
• Insufficient competition in the forward capacity auction.
• A lack of fuel source diversity in the generation capacity jeopardizing the reliability of the electricity grid in the event of a disruption to fuel supply
If any of these signs appear and DEEP projects a shortfall expected each year, assuming no competitive market-based entry, and given updated market conditions (for example, if the market is closer to the 2014 IRP Base Case, or the Tight or Abundant Supply scenarios), DEEP will recommend intervention. The Department will then consider options to fill gaps where shortfalls are projected to not be filled by the market. Such intervention could be conducted pursuant to existing state laws, including Section 16a-3b of the general statutes. Any intervention would consider the realities of resource development lead times:
• Small, short-term gaps may be best filled by short-term contracts for short lead-time, less capital-intensive projects; the best candidate resource type would be new DR, which would require as little as months to develop.
• Other short- and medium-term options may include generation uprate projects that typically require closer to a year or two (or more) to develop.
• Meeting larger, long-term gaps may require long-term contracting with larger new generation resources, such as combined-cycle gas-fired generation, or possible other resources, such as imported large-scale hydropower. Solicitations would have to occur as soon as large gaps of at least several hundred MW are within three years of occurring (and are unlikely to be filled by market response). Considering likely lead times, new simple-cycle gas- fired generation may require 2–3 years to develop depending on whether it has already begun permitting, and new efficient combined-cycle generation may
require 3–4 years to develop depending on whether it has already begun permitting.158
• Meeting larger, long-term risk to fuel source diversity necessary for grid security and reliability may require acquisition or long-term contracting with existing generation facilities such as nuclear, coal, or oil fired units. Consideration will be given to the impacts to reliability of announced and anticipated non-price retirements.
The Department does not plan to intervene solely for resource adequacy purposes unless necessary, so as to avoid the perception of undue interference in a functioning market, and to minimize the risk that contracted resources would fail to receive capacity credit under ISO-NE’s Minimum Offer Price Rule. If intervention becomes necessary, the Department would seek to work with other New England states to ensure fair allocation of costs to procure solutions that would necessarily have regional benefits. Special consideration may be given to resource types that also meet complementary policy objectives, such as gas-electric reliability and environmental goals.