Ask Ed Bell about energy trading and risk management (ETRM) technology and he’ll likely bring up his days with Enron back in the early 1990s. Bell—now a principal at Houston-based technology...
Retirement is Coming
Preparing for New England’s capacity transition.
England for new capacity are limited. Demand resources have widespread political support among the New England states, but might be limited by the availability of economic opportunities in sufficient magnitudes and where needed to meet reliability needs. And for economic and political reasons, few seem to have the appetite to pursue new nuclear-, coal-, or even oil-fired projects.
Given these factors and underlying economics, natural gas is—and in all likelihood will continue to be—the resource of choice in New England markets. Yet there has also been a strong push by states to integrate New England’s vast quantities of on- and off-shore wind resources, and there is strong interest among developers and neighboring Canadian provinces to build new transmission interconnections into the Northeast U.S. to tap wind and hydro resources in that region. 9
The analysis was constructed in consideration of these market and political circumstances. It used General Electric’s Multi-Area Production Simulation (MAPS) model and Analysis Group’s database on loads, resources, and input prices. 10 It was assumed that the new resources were interconnected at buses within the same load zone as the coal-fired capacity retirements (Boston/NEMA). The specific scenarios include a reference case, and five scenarios that assume retirement of coal-fired capacity, and add new capacity in the following quantities and configurations:
• Reference: New England load in 2020, existing resources plus additional renewable resources as needed to meet New England’s renewable portfolio standard requirements through 2020.
• Scenario 1 (1,200 MW Wind): Change the Reference case by retiring coal-fired capacity, and adding 1,200 MW of wind resources.11 This scenario involves only the dispatch of the variable wind resource, without specific balancing or backing by another resource type. Consequently, from an annual energy perspective, it’s roughly equivalent with Scenarios 2 and 3 (400 MW of capacity each).
• Scenario 2 (400 MW Wind and Hydro): Change the Reference case by retiring coal-fired capacity, and adding 400 MW of wind resources, but with hydro resources available to fill in up to 400 MW when wind output is less than that amount.12
• Scenario 3 (400 MW Gas): Change the Reference case by retiring coal-fired capacity, and adding 400 MW of natural gas combined cycle (NGCC) resources.
• Scenario 4 (1,200 MW Wind and Hydro): Same as Scenario 2, except add 1,200 MW of wind and hydro capability instead of 400 MW.
• Scenario 5 (1,200 MW Gas): Same as Scenario 3, except add 1,200 MW of NGCC instead of 400 MW.
• The results (see Figures 3-6) reflect the differences in dispatchability between Scenario 1 (wind-only) and the other scenarios, the differing level of new resource additions (400 MW vs. 1,200 MW), and, from an emissions perspective, the differences between renewable and gas-fired capacity.
Regional Market Prices
Not surprisingly, removing coal-fired generation from the resource mix increases regional electricity prices. But also not surprisingly, in every one of the scenarios—introducing new inframarginal NGCC generation, or production from wind or wind-and-hydro resources—the reduction in prices associated with the new generation results in overall price decreases, more than displacing the upward price impact of