Considerations for Transporting a Blended Hydrogen Stream in Interstate Natural Gas Pipelines


June 11, 2021

Hydrogen has been widely touted as a solution to achieve ambitious emissions reduction goals. But in order to unleash hydrogen’s potential as a viable energy source to meet current targets, it needs to be produced in larger quantities than it is today without generating large amounts of undesirable emissions during the production process, and at a cost that is not prohibitive.[1]

Hydrogen production from “zero carbon” electricity sources, such as solar and wind, is estimated to be about $5/kg, or roughly 2.5–4 times more costly than hydrogen derived from fossil resources.[2] That may change in the future. On June 7, 2021, US Secretary of Energy Jennifer M. Granholm launched the Energy Earthshots Initiative to accelerate emerging decarbonization technologies. One of the initiative’s “big, hairy, audacious goals” is to reduce the cost of hydrogen produced from renewable sources to $1/kg within a decade.[3]

Even assuming net-zero hydrogen production can be produced economically in the future, the industry will need to overcome another barrier: transportation and delivery on a wide scale. Hydrogen, like other fuels, is typically transported in either liquid form by rail or vehicle, or in gaseous form by pipeline, but on too small a scale to usher in the “hydrogen revolution” proselytized by some industry commentators. Vehicle and rail transportation alone will not be sufficient to support mass adoption of hydrogen in cross-sector applications, leaving pipelines as the lowest cost and most efficient alternative to move massive quantities of hydrogen from production sites. However, there is only a limited amount of dedicated hydrogen pipeline infrastructure available today—approximately 1,600 miles of pipeline dedicated mostly to commercial and industrial concerns. Scaling out a nationwide hydrogen pipeline network seems unlikely anytime soon. Rising development costs and siting issues have always posed significant risks to pipeline projects. Now, regulatory uncertainty, growing anti-pipeline activism, and a slew of legal challenges can derail these projects entirely. Even so, a robust interstate hydrogen pipeline network is still possible. It will just take time and considerable expense.

In the meantime, researchers and stakeholders all over the globe are weighing alternatives to dedicated hydrogen pipelines. Existing natural gas infrastructure presents an attractive opportunity.[4] In the United States alone, natural gas pipelines span approximately 3 million miles to form a highly integrated network. Equally as important, the US natural gas industry already has extensive experience substituting multiple combustible gases into the gas stream (i.e., gas interchangeability).[5]

We discuss key interchangeability benefits and challenges below.

Benefits of a Hydrogen–Natural Gas Blend

Blending hydrogen into existing natural gas streams offers several distinct benefits.

First, blending provides an alternative to risky new projects. Piggybacking hydrogen on natural gas pipelines means transporters could avoid complex permitting and regulatory burdens for new construction and limit exposure to messy legal challenges. Delivery straight to end uses that require pure hydrogen, such as vehicle fueling, is also possible by extracting hydrogen from the blended gas stream. A technical study by the National Renewable Energy Laboratory (NREL) suggests that three methods—pressure swing adsorption (PSA), membrane separation, and electrochemical hydrogen separation—could be used to extract hydrogen from hydrogen–natural gas blends in this manner. NREL observed that the efficacy and cost of performing hydrogen extraction varies based on, among other things, the method used, the scale of the hydrogen recovery, the concentration of hydrogen present in the blended stream, and the extent to which the natural gas remaining from the extraction process needs to be recompressed for injection back into the pipeline.[6]

Second, hydrogen provides a carbon abatement opportunity for power producers. Independent generators and utilities alike are increasingly announcing significant carbon reduction or net-zero targets by or before 2050. Although less carbon intensive than other fossil fuels, natural gas still produces approximately .91 pounds of CO2 per kilowatt hour (kWh). Burning a hydrogen–natural gas fuel blend, which some gas generators are already equipped to do, can further reduce the overall carbon cost of power production on a kWh basis.

Third, a hydrogen blend can reduce the indirect upstream emissions associated with natural gas production. Introducing hydrogen into the pipeline system at delivery points near shale production areas could displace natural gas, potentially leading to reduced emissions from production-adjacent activities, such as fracking and flaring, especially if the blended hydrogen is produced by renewable sources.


Industry and government regulators will need to address a number of technical and legal barriers before stakeholders can realize the benefits of blending and transporting large quantities of hydrogen in natural gas pipelines across state lines.


The interstate natural gas pipeline system was designed to transport methane, the primary component of natural gas, albeit with some variability in the gas stream. The introduction of hydrogen in increasing quantities would pose challenges for pipeline operators, which must weigh the benefits of higher hydrogen concentrations against the costs and risks associated with retrofitting the pipeline system. As has been widely studied, hydrogen has the ability to degrade metal components used in pipeline infrastructure over long periods of time. The rate of any degradation or operational risk will also be dependent on the concentration of hydrogen in the gas stream. Some international projects are piloting blends with hydrogen concentrations as high as 20%, but the long-term impact of hydrogen on materials and equipment is not yet well quantified.

The risks can be mitigated with lower concentrations of hydrogen. Relatively low concentrations of hydrogen ranging up to 20% by volume appear to be feasible with few modifications to existing pipeline systems or end-use appliances.[7] But those concentrations may not be tenable in the marketplace, especially if downstream extraction of pure hydrogen is a primary goal. NREL estimates that, using the PSA method, the cost for hydrogen extraction is $3.3–$8.3/kg for a 10% hydrogen blend with an 80% recovery factor. The costs go down to $2.0–$7.4/kg with a 20% hydrogen blend and the same recovery factor. Those costs must also be considered along with upstream production costs, any losses during transportation and distribution, and the cost to recompress and reinject natural gas after the extraction process. The result is a relatively high cost for hydrogen on a kilogram basis.


Safety issues may arise with higher concentrations of hydrogen in the natural gas stream. In particular, because hydrogen is a more mobile molecule than methane, it may introduce the risk of leakage.

At the federal level, the Pipeline and Hazardous Materials Safety Administration (PHMSA) implements a variety of safety-related regulations to address hazardous leaks and pipeline integrity. While PHMSA may draw on its experience regulating hydrogen pipeline infrastructure, the agency will likely need to augment its existing rules applicable to natural gas pipelines or develop new standards to address blended gas streams containing hydrogen.

For example, the PHMSA’s integrity management regulations under 49 CFR Part 192 require pipeline operators to implement distribution integrity management programs (DIMPs) to improve the safety of pipeline transportation of energy product. DIMPs are entity-specific plans that require each operator to, among other things, closely evaluate its system design, operating conditions, and maintenance history in order to identify and rank risks that could impact safety or system reliability. However, those regulations are specific to gas pipelines.

State-regulated operators at the distribution level will also need to account for the increased safety risks and ensure that their systems are equipped to meet state and local requirements. NREL estimates that permeation rates for hydrogen are about 4–5 times faster than for methane in typical polymer pipes used in the US natural gas distribution system.

Regulation of Transportation Services

Federal jurisdiction over rates for interstate hydrogen-only pipelines resides with the Surface Transportation Board (STB), the successor agency to the Interstate Commerce Commission.[8] However, a pipeline carrying a hydrogen-methane blend on existing natural gas infrastructure is far more likely to be regulated as a traditional interstate natural gas pipeline subject to Federal Energy Regulatory Commission (FERC) jurisdiction.

FERC has broad authority under the Natural Gas Act to regulate the terms and conditions for wholesale natural gas pipeline service, as well as certificated construction activities. FERC’s authority extends to the tariffs that set the parameters for transportation service, which include gas quality specifications and interchangeability requirements. Those requirements can vary significantly based on the location and scale of a pipeline system, as well as the physical characteristics of the gas. Generally speaking, FERC’s interchangeability policy requires pipeline gas quality specifications to balance safety and reliability concerns against the need to maximize supply.[9]

In order to facilitate the injection of greater quantities of pure hydrogen or a higher concentration hydrogen-methane blend, pipelines will likely need to revisit interchangeability requirements and undertake capital improvements that may result in more onerous quality standards and higher costs for shippers. Pipelines will ultimately bear the burden of demonstrating that any gas quality restrictions are necessary to address system needs and that any rate increases are just and reasonable and not unduly discriminatory. Pipelines will also need to coordinate any specification adjustments with their downstream transportation and distribution counterparts.


Blending hydrogen into the natural gas stream may provide pipelines, shippers, and power producers significant commercial and carbon abatement benefits while leveraging the efficiencies and economies of scale of existing natural gas pipeline infrastructure. Although there are challenges to overcome, industry participants and federal natural gas pipeline regulators have the tools necessary to facilitate the transition of existing natural gas infrastructure that will harness the energy potential of hydrogen.

[1] Most hydrogen today is produced using fossil sources, such as the natural gas steam-methane reforming process or coal gasification. See US Department of Energy (DOE), Hydrogen Production: Natural Gas Reforming.

[2] US DOE Office of Fossil Energy, Hydrogen Strategy: Enabling a Low-Carbon Economy (July 2020).

[3] US DOE, Secretary Granholm Launches Energy Earthshots Initiative to Accelerate Breakthroughs Toward a Net-Zero Economy (June 7, 2021).

[4] For example, the European Hydrogen Backbone—a group of European gas infrastructure companies—hopes to develop a hydrogen pipeline transport system across Europe by 2040 primarily through repurposing existing gas infrastructure, supplemented by targeted investments in dedicated hydrogen pipelines. See European Hydrogen Backbone, (last visited May 31, 2021).

[5] The Natural Gas Council, a coalition of natural gas trade associations, defines “interchangeability” as “[t]he ability to substitute one gaseous fuel for another in a combustion application without materially changing operational safety, efficiency, performance or materially increasing air pollutant emissions.” NGC Gas Interchangeability Task Group, White Paper on Natural Gas Interchangeability and Non-Combustion End Use (2005).

[6] NREL suggests that recompression costs can be significant, but can be avoided if hydrogen is extracted at a pressure-reduction facility so natural gas does not need to be recompressed.

[7] See Congressional Research Service, R46700 Pipeline Transportation of Hydrogen: Regulation, Research, and Policy at 7 (Mar. 2, 2021).

[8] The STB is tasked under the Interstate Commerce Act with oversight of pipelines transporting a commodity other than “water, gas or oil.” 49 USC § 15301(a); see also Congressional Research Service, R46700 Pipeline Transportation of Hydrogen: Regulation, Research, and Policy at 10.

[9] Policy Statement on Provisions Governing Natural Gas Quality and Interchangeability in Interstate Natural Gas Pipeline Company Tariffs, 115 FERC ¶ 61,325 (2006).