The Effect of Decarbonization Factors on Deeply Decarbonized Electrical Systems: Texas Case Study

Abstract

The expectation of continued CO2 emissions reduction in the power sector has prompted interest among policymakers, regulators and utilities in expanding electrification of other end-use sectors as a way to meet long-term economy wide decarbonization goals. Expanded use of electrification in these sectors to displace fossil-fuel use, such as for heating or transportation, is appealing not only because it eliminates distributed sources of CO2 emissions and has associated efficiency benefits, but also because it leverages existing end-use technologies and infrastructure. However, the full CO2 emissions benefit of electrification is contingent on deep decarbonization of electricity systems. This work is centered on the impact of factors that contribute to the deep decarbonization of power systems, under a high electrification assumption and taking Texas as the case study.

The factors studied are the availability and cost of generation and storage technologies; electrification level; demand flexibility; demand response; and the coupling of the power system with the industry to supply electricity-driven hydrogen supply to supply process heat. By means of a Capacity Expansion Model, GenX, and a design of experiments (DOE) framework, each factor is studied in depth at different CO2 emission intensity targets, starting with the unconstrained system, and then ranging from 85% up to 100% decarbonization (total CO2 mass yearly offset with respect to 2018). The impact of each factor is quantified in terms of its effect on average system cost (SCOE); installed power capacity; storage needs; wholesale prices distribution and system operation.

Results show that: (1) under no CO2 constraints (a "No Policy" scenario), the power system tends to decarbonize itself to a level of 72%, driven by assumed cost projections for 2050 and the high availability of variable renewable energy (VRE) in Texas. (2) Achieving a 98% decarbonization implies reaching a system average cost of $41/MWh, or an increase in system average cost of 17% from the No Policy case. (3) The various factors evaluated here impact power system outcomes (system costs, system total power capacity, wholesale electricity price distribution, reliability) differently depending on the emission constraint. A combination of factors is generally found to lead to favorable outcomes on multiple dimensions. (4) The most impactful factor is the costs of VRE, followed by hydrogen use in the industry and availability and cost of long duration storage (LDES) technologies. (5) Increasing share of VRE generation increases the number of hours of zero wholesale electricity prices, implying that technologies have to rely on only a few hours to recover investments in energyonly markets. Deployment of dispatchable generation sources such as the Allam cycle, LDES, and activating the coupling with the industry to supply electricitydriven hydrogen, reduces instances of zero wholesale electricity prices. (6) Demandside management factors (demand flexibility and demand response) prove mainly to contribute to reduce the system footprint, reduce price volatility and to a lesser extent, system costs. (7) Higher electrification of energy demand is found to be beneficial not only to increase the cost-effectiveness of decarbonization via VRE generation owing to overlap between peak demand and VRE resource availability, but also contributes to reduce system SCOE and VRE curtailment levels.