A no-holds-barred interview with the electric industry’s chief architect of wholesale electric market design.
Retirement is Coming
Preparing for New England’s capacity transition.
coal unit retirements. 13
The magnitude of overall price impacts is significant (see Figure 3) . Annual load-weighted average marginal price reductions (compared to the reference case) range from $0.21/MWh for the 1,200 MW wind-only scenario, to $3.28/MWh for the 1,200 MW wind-hydro scenario. These price impacts translate into significant energy market cost reductions for the region’s rate payers. Reduced costs are maximized in the 1,200 MW wind-hydro scenario, equal to approximately $449 million in the year 2020. For the 400 MW wind-hydro and natural gas scenarios, and the 1,200 MW intermittent wind scenario, the reduced costs range from $28 million to $119 million (see Figure 4) .
The results reveal that the 1,200 MW wind-only case generates the smallest cost reduction of all scenarios. This is because the variability in output in the 1,200 MW wind-only case (Scenario 3) significantly dampens its impact on prices, highlighting the value of combining the intermittent resource with hydro or some other resource capable of filling in wind output efficiently, to maximize the value and benefit of any associated transmission; for instance, the 1,200 MW wind-hydro scenario achieves annual average LMP reductions roughly 15 times larger. This dampened price effect is due to the fact that in wind-only dispatch mode, the wind resource is at reduced output in many high-load/high-price hours. In fact, as can be seen in Figure 5, average output for the wind-only case is highest in lowest-price hours, and lowest in highest-price hours. It is, of course, highly unlikely that a transmission line sized to carry 1,200 MW of wind—when available—wouldn’t carry other forms of power when the wind isn’t blowing. But from the perspective of both price and emission impacts, what fills the remaining space on the line will matter. The example modeled in this analysis—a combined wind-hydro product (Scenarios 2 and 4) would dramatically increase reductions in energy market costs and emissions.
Each of the scenarios modeled represents minor changes in capacity relative to the total quantity of generating capacity dispatched in the model. With this in mind, results associated with the potential for reductions in CO 2 are significant. With respect to emissions of CO 2, the wind-only and combined wind-hydro cases generate the greatest quantity emission reductions in 2020 relative to the reference case, with the NGCC cases leading to smaller reductions. 14 For example, the wind-only and 400 MW wind-hydro cases produce reductions of roughly 2 million tons in 2020 relative to the reference case, while the 1,200 MW wind-hydro case leads to CO 2 emissions reductions more than twice this amount. The natural gas cases yield lower reductions relative to the reference case—between 0.8 and 1.4 million tons (see Figure 6) .
Like many U.S. regions, New England over the next several years will face a period of significant turnover of transmission and generation infrastructure that will flow from market dynamics, regulatory developments, and aggressive policy-driven expansion of renewable resources. The combination of forthcoming EPA regulations and continued—if delayed—expectations of control requirements for CO 2 likely will lead to reductions in coal- and oil-fired