We assess the economic viability of nuclear cogeneration by investigating three different modes—fixed dispatch, fully flexible dispatch, and flexible dispatch with minimum heat supply requirements. The analysis focuses on an existing pressurized water reactor (PWR) integrated with thermal energy storage (TES). Heat production costs are estimated under these modes for two U.S. electricity markets, the Electric Reliability Council of Texas (ERCOT) and the Pennsylvania–New Jersey–Maryland Interconnection (PJM). A sensitivity analysis is conducted at varying heat market prices to evaluate the profitability of PWR–TES cogeneration. Results indicate that fixed heat dispatch inflates heat production costs, often rendering projects economically feasible only at higher heat price levels. In contrast, fully flexible dispatch lowers heat production costs by an average of 43 % compared to fixed dispatch. However, the current 30% thermal dispatch limit may be insufficient to serve high baseline industrial demands cost-effectively; a higher maximum dispatch rate could enhance project economics. Additionally, while markets with higher and more volatile electricity prices (e.g., ERCOT) offer greater total energy sales potential (i.e., heat and electricity), they also increase opportunity costs if restrictions on heat production scheduling are required. In contrast, lower-price, less volatile markets (e.g., PJM) experience a smaller impact from such constraints and provide greater flexibility in accommodating varying cogeneration modes. Overall, these findings provide a framework to guide nuclear plant operators in aligning cogeneration strategies with industrial process requirements and electricity market conditions.
