#Fuel Delivery and Storage

The fuels model covers the delivery and storage of fuels required to connect primary supply and conversion to the point of end-use. In reality, fuel delivery networks are highly complex. US-REGEN captures these activities at a relatively high level and does not attempt to resolve these networks in detail. It is primarily designed to reflect the economic costs of the storage and delivery components of alternative energy pathways, but it does include an explicit structural representation of inter-regional pipeline flow and storage requirements for temporal balancing of hydrogen supply and demand. Intra-region costs for pipeline gas and hydrogen delivery, similar to electricity, are represented as levelized costs. For liquid fuels, which have much higher energy density and thus lower relative costs of delivery and storage, the model assumes a flat levelized cost adder to reflect aggregate distribution costs. Levelized cost estimates are based on observed differences in wholesale and retail prices in current EIA data.

The model includes the option to move and store hydrogen with new dedicated infrastructure. The assumptions for bulk storage of hydrogen are based on an underground geologic reservoir in a salt cavern or similar formation.^[1] Capital costs are divided into those costs that scale with withdrawal capacity ("door" costs) and those that scale with reservoir storage capacity ("room" costs). Withdrawal capacity costs include compression and drilling of wells, while reservoir capacity costs include geology, excavation, brine disposal, and cushion gas. The costs for these options are shown in Table 1, with a comparison to equivalent costs for natural gas infrastructure.

US-REGEN considers the option to blend several gas commodities together for delivery through existing natural gas infrastructure. In addition to conventional fossil-based natural gas, the blend can include renewable natural gas (from either waste methane sources of via gasification of cellulosic biomass), synthetic natural gas (from hydrogen and captured carbon), and hydrogen, up to a share of 20% of by volume, which translates to roughly 7% in energy terms. There are no constraints on the blended shares of renewable and synthetic natural gas, as these are considered to be essentially identical substitutes. The model includes the flexibility to allocate different blend ratios to different end-use sectors, for example to allow for compliance with sector-specific CO₂ goals. For electric generation, hydrogen can be blended with gas at the unit level at higher ratios than 20% in designated dual-fuel capable turbines.

Intra-regional fuel delivery costs for non-electric fuels are shown in Table 2. Hydrogen delivery costs are based on an assumed pipeline network, with higher levelized costs for smaller customers in the residential and commercial sectors. Note that assumed hydrogen delivery costs are significantly lower than observed costs today based on smaller scale truck deliveries. Transport applications also include the cost of dispensing hydrogen at pressure into vehicles, which is a significant cost component, even assuming declines relative to today based on scale and learning. For hydrogen used directly for electric generation or other upstream activity, the model applies delivery costs for a large industry customer. In some cases, these infrastructure costs could be lower with co-located production and use. Delivery costs for ammonia are based on observed differences in producer and consumer prices from the USDA.