#Pipeline Gas

In contrast to other fossil fuels, natural gas demand increases relative to today in the Reference scenario, while results indicate a wide range of possible outcomes across Net-Zero scenarios (Figure 30). In the Net-Zero All Options scenario, natural gas consumption in 2050 is similar in scale to today. It is used with CCS for power generation and hydrogen and ammonia production, and it continues to be used without CCS in buildings and industry, offset by negative emissions, although this direct use is lower than in the Reference case due to end-use efficiency, electrification, and fuel-switching. The model also considers the possibility of blending natural gas with other products to decarbonize the supply of fuel provided through existing gas pipeline infrastructure. These could include renewable natural gas (from either waste methane sources such as landfill gas or via gasification of cellulosic biomass) or synthetic natural gas (from methanation of hydrogen), which are assumed to be “drop-in” equivalent to fossil-based natural gas, as well as hydrogen blended to a maximum share of 20% by volume (which corresponds to roughly 7% on an energy basis). In the Net-Zero All Options case, the supply of pipeline gas includes hydrogen blending up to the assumed limit, as well as a small amount of renewable natural gas from waste methane (denoted ‘LFG’ for landfill gas in Figure 30).

In the Net-Zero Higher Fuel Cost scenario, the higher supply costs for natural gas, as well as a higher implicit carbon price, leads to reduced supply and demand of pipeline gas, which fall to roughly half of today’s levels. Gas use for electric generation is offset by higher shares of renewables, and some hydrogen production from gas is offset by production from electrolysis. Additional end-use efficiency, electrification, and fuel-switching drives lower direct demand. The deployment of direct air capture accounts for a small increase in gas demand (also with capture) to supply the thermal energy input. The supply mix is similar to the Net-Zero All Options case, with smaller overall demand for pipeline gas, implying smaller volumes of blended hydrogen.

In the Net-Zero Limited Options scenario, there remains some use of pipeline gas in buildings and industry, but almost none for power generation and none for hydrogen production. However, the supply mix shifts to primarily renewable and synthetic natural gas, as well as hydrogen up to the 7% limit, with very little fossil-based natural gas. This shift is accompanied by much higher commodity prices for pipeline gas due to the higher supply costs of these alternatives. The total volume of pipeline gas use is much lower than today, around 5 quad Btu per year or around 17% of current levels.

Although pipeline gas consumption is lower in energy terms in the Net-Zero Higher Fuel Cost and Limited Options scenarios, the infrastructure capacity needed to serve peak energy demands remains. Figure 31 shows nominal capacity (in terms of TBtu per hour) of gas-using capital stock in the electric, industrial, and buildings sectors. The total amount of nominal pipeline gas delivery capacity is similar across future scenarios and declines by only about a third in the Net-Zero Limited Options case despite much lower gas consumption in energy terms. This result implies lower utilization rates for gas infrastructure serving both the electric sector (driven by increased shares of intermittent renewables) and the buildings sector (driven by increased use of electric heat pumps for space heating). In both sectors, the remaining gas is used to fuel peak demands, in particular during periods of low renewable output (see Figure 25) and in cold climates with hybrid heat pump systems using gas back-up (see Buildings section). The modeling in this analysis finds that maintaining gas capacity and infrastructure is part of a least-cost economy-wide approach to achieving a net-zero target, despite lower utilization of these assets. These results suggest that utility cost recovery models may need to evolve in order to maintain capacity and reliability, and to enable expanded use of low-carbon fuels in the pipeline mix.

As the scale and composition of gas demand change, the seasonal profile of delivered gas changes, Figure 32 shows the weekly demand shape across scenarios for the New York and Southeast model regions. In New York, gas use in buildings declines in the net-zero scenarios—especially the Limited Options case—but it is not eliminated, as continues be used for peak heating demand in hybrid heat pump systems. In the industrial sectors, some gas use remains in the Net-Zero All Options case, but is largely replaced through electrification and fuel-switching to hydrogen and other low-carbon fuels in the Limited Options case. In the power sector, gas use also declines to near zero in energy terms, but as noted, capacity remains important for adequacy. The results is the annual profile of gas delivery becomes even more concentrated in the winter months as space heating represents a larger share of total demand. In the Southeast model region, gas use for space heating in buildings declines, but in the Net-Zero All Options case, gas use for power generation increases due to the deployment of gas with CCS, which operates at a roughly constant rate across the year. Thus the seasonal shape declines in winter but increases during the rest of the year relative to today. In the Limited Options case, increased electrification drives gas even lower in buildings and industry. Winter peaks are much lower both because of the milder climate and the higher share of all-electric heat pump systems. With the constraint on CCS, there is very little gas use for power generation. Thus both total consumption and peak weekly consumption are significantly lower. However, capacity needs for peak demand in the power sector and remaining building uses are realized on an hourly basis even as the weekly peak declines.

While the scenarios in this analysis are framed in terms of net-zero CO₂ emissions, there are also important implications for energy-related emissions of methane, another greenhouse gas (GHG). Methane emissions arise from the energy system via fugitive releases associated with upstream oil and gas production as well as leakage from the downstream pipeline gas transmission and distribution system. There are also methane emissions associated with coal production, but the potential for future methane emissions in the net-zero scenarios in this analysis is driven by the extent to which oil and gas use remain in the system. Figure 33 shows estimated energy-related methane emissions associated with oil and gas across scenarios. Uncertainty exists about the magnitude of base year emissions, with most detailed assessments suggesting a higher rate of emissions than officially estimated by the U.S. EPA inventory. This analysis assumes base year energy-related methane emissions equivalent to an overall leakage rate of 1.8% of total gas volumes, which translates to roughly 250 MtCO₂-e.^[1] This corresponds to about 5% of base year energy-related CO₂ emissions. Projections going forward are partially driven by changing activity levels in upstream oil and gas production and downstream gas use, with 70% of leakage attributed to upstream activity and 30% attributed to downstream. Note that downstream emissions arise from any mix of hydrocarbon gas, whether fossil, renewable, or synthetic. However, future projections also depend on anticipated declines in leakage rates over time, driven by improved leak detection and monitoring and potentially by strengthened regulatory incentives and targets for mitigation. Based on the time series data in the U.S. EPA inventory and EIA, leakage rates for energy-related methane relative to total gas volumes have declined at an average rate of roughly 2.5% per year over the last three decades. Figure 33 illustrates projected methane emissions rates based on two possible future decline rates, one consistent with the historical rate, and one double the historical rate to reflect accelerated efforts to detect and repair leaks. The results indicate that even in the Net-Zero All Options case, where gas use in the energy system is similar in scale to today, energy-related methane emissions could be much lower, in the range of 50–100 MtCO₂-e. These residual emissions correspond to roughly 5-10% of total negative CO₂ emissions in this scenario, suggesting that a relatively small increase in CDR deployment could fully offset positive methane emissions associated with continued gas use. In the other net-zero scenarios, methane emissions are even lower, with only 10-20 MtCO₂-e remaining in the Limited Options case. Further research will explore the trade-offs between decarbonization and energy-related methane in more detail.