Deep de-carbonization of the electric power sector is indispensable to achieving climate change mitigation. This work explores how aggressive reductions in electricity sector emission levels can be achieved, what the associated costs would be, and how these costs may be minimized. Integrating increased levels of intermittent renewable energy sources into the electricity grid poses new challenges to system planning, operation, and reliability, increasing the need for models that can merge the capabilities of capacity-expansion and production cost simulation models.
I describe the operational detail I have incorporated into the long-term investment framework of the SWITCH model to allow for more accurate evaluation of both the potential contribution of intermittent renewable technologies to electricity decarbonization and the associated system flexibility requirements. I have implemented a series of enhancements to the model's treatment of system operations and generator types -- the SWITCH "system flexibility module" -- in order to simulate unit commitment as realistically as possible, at an unprecedented resolution for a capacity-expansion model of a large geographic area, offering some of the most detailed treatment to date of day-to-day system operations in an investment model.
I run a range of scenarios to explore the effect of various sources of uncertainty for system development between present day and 2050 in the Western Electricity Coordinating Council (WECC). I include sensitivities for technology costs, fuel prices, technology availability, demand profile, and availability and cost of system flexibility options. I find that meeting a carbon emissions reduction target of 85 percent below 2050 levels is feasible across a range of assumptions. The cost of achieving the goal is highly uncertain, but a number of opportunities to contain costs exist. In the 2030 timeframe, lowering the cost of solar technologies to the SunShot target is the main cost-reduction strategy. Achieving the ARPA-E battery cost target has a small impact on system costs through 2030, as other sources of flexibility are available to the system, including gas generation, hydro, and CAES. The price of natural gas is key to its utilization in the 2030 timeframe, but is not an important driver in 2050 when natural gas flexibility is of high value yet fuel use is limited by the carbon cap.
Solar PV deployment is the main driver of CAES and battery storage deployment: its diurnal periodicity results in opportunities for daily arbitrage that these technologies are well suited to provide. Storage operation is very different from present day patterns - storage tends to charge during the day when solar PV is available and discharge in the evening and at night. Similarly, the ability to shift loads to the daytime solar peak could have cost-reduction benefits for the system. Wind output exhibits large seasonal variations; because it can remain at very low (or very high) levels for extended periods of time, it does not benefit from CAES and battery storage (operating as providers of daily arbitrage) as much as solar PV does, and instead requires storage with a large energy subcomponent.
CSP with thermal storage is an important component of the 2050 power system, but it directly competes with the combination of solar PV and batteries. If low solar PV costs and low battery costs are achieved, the two technologies may be deployed at large-scale, displacing CSP with thermal storage. The combination of SunShot solar technology and advanced battery technology has the largest impact on total storage capacity deployment in 2050. This combination can provide substantial savings through 2050, greatly mitigating the cost of climate change mitigation and outperforming the nuclear-dominated scenario given the costs assumed here.
Policy goals for storage deployment should incorporate both the power subsystem component and the energy subsystem component of energy storage. In addition, storage deployment requirements should be set as part of overall system development goals as system flexibility needs will vary depending on the rest of the grid mix. Policy ought to be technology-neutral and support a comprehensive portfolio of system flexibility options, allowing flexible generation, demand response, and flexible electric vehicle charging, which can provide comparable services, to compete with storage on a level playing field. The increase in system flexibility requirements can be managed through a system-wide approach including regional cooperation to strategically plan for transmission interconnection and geographic diversity of renewable resource deployment to mitigate the variability of overall output. System-level planning is critical to ensure that appropriate incentives are put in place for all grid assets to fully recover their costs and justify investment while providing the most value to the system and ensuring cost-effective system development over time.