Why We Aren’t All Driving Hydrogen Cars

Hydrogen fuel cell vehicles sound like a dream. They promise fast refueling, long range and zero tailpipe emissions. Yet, decades after the technology emerged, hydrogen cars remain rare. The answer lies in the century-long evolution of hydrogen infrastructure. It was built not for cars, but for heavy industry.

A brief history: pipelines and industrial customers

The first dedicated hydrogen pipelines didn’t serve motorists at all. In the 1940s Air Liquide constructed a 400 km pipeline running from northern France to Belgium to serve refineries and petrochemical plants. Meanwhile U.S. cities distributed “town gas” (30 to 50 percent hydrogen) via local gas mains until natural gas replaced it in the 1950s.

As demand for pure hydrogen grew, three companies became dominant suppliers. Air Products, Air Liquide and Linde, which later became Praxair, came to dominate the market:

• Air Products started as an oxygen supplier in the 1940s. In 1957 it secured a contract to produce liquid hydrogen for the U.S. Air Force and NASA, supplying rockets from Apollo to the Space Shuttle. By the 1980s it was leading hydrogen supply for Gulf Coast oil refineries. Its Gulf Coast Connection Pipeline, completed in 2012, now links more than twenty plants across six hundred miles and delivers over one billion cubic feet of hydrogen per day.

• Air Liquide expanded from Europe into the United States by acquiring several gas companies in the 1980s. Today it operates a three hundred thirty-mile pipeline network along the Gulf Coast and runs the Spindletop underground cavern, which stores four point five billion cubic feet of hydrogen. Its La Porte steam methane reformer alone produces over one hundred sixteen million standard cubic feet of hydrogen per day.

• Linde (Praxair) traces its U.S. roots to 1907. It provided super insulation for NASA’s liquid hydrogen tanks in the 1960s and now operates five liquid hydrogen plants, twenty-one tube trailer filling stations and a three hundred forty mile pipeline network serving more than fifty refineries and chemical plants. It also owns one of the world’s largest underground hydrogen storage caverns in Texas.

Today, these three companies control nearly 90% of all merchant hydrogen production, 90% of the 1,600‑mile hydrogen pipeline network in the U.S., almost all of it along the Gulf Coast, and 75-80% of the Industrial-gas market.

Built for refineries and fertilizer, not cars

Petroleum refining dominates hydrogen demand. An Energy Futures Initiative report notes that about fifty seven percent of U.S. hydrogen demand comes from the refining industry. When ammonia and methanol are included, over ninety percent of U.S. hydrogen consumption is concentrated in these heavy industries, with refining alone accounting for more than half. Europe shows a similar pattern: refineries use about forty nine percent of hydrogen, ammonia plants thirty one percent, and the chemical sector (including methanol) thirteen percent. These customers need hydrogen to remove sulfur and upgrade heavy crude into cleaner fuels, and fertilizer plants use it to synthesize ammonia. Because their demand is large and steady, they justify on-site steam methane reformers and long pipelines. On‑site production (captive hydrogen) accounts for roughly seventy percent of capacity, while merchant production and by‑product hydrogen each represent only about fourteen percent. That means most hydrogen never leaves refinery gates.

Refinery hydrogen units sometimes have spare capacity. When demand dips, these captive units can supply merchant customers; but when demand rises, they revert to serving the refinery. The U.S. Energy Information Administration estimates that about twenty four percent of U.S. hydrogen is produced as a by‑product from chemical and industrial processes; this hydrogen is sold into the merchant market at prices low enough to compete with on‑site production. Industrial processes like chlorine and caustic soda manufacture also generate excess hydrogen, which is collected, purified and distributed to other users, mostly by truck and, where pipelines exist, through dedicated hydrogen lines.

These merchant supplies are a lifeline for smaller industries, electronics, food processing, metals and glass, but they are limited. Liquid hydrogen production is costly, requiring chilling to –451°F, and only a handful of plants exist. Liquid hydrogen represents a small fraction of total hydrogen volume but supplies the most vulnerable users; a refinery‑driven shortfall of even one percent can consume more than twenty percent of merchant liquid availability. Moreover, hydrogen pipelines along the Gulf Coast operate at around ninety to ninety five percent utilization, with no spare capacity. When these pipelines exceed capacity, the merchant market becomes the release valve. New liquefaction plants and pipeline expansions take four to five years to build, and the supply of low‑cost by‑product hydrogen is shrinking as chlorine plants close and refineries run less. In short, the merchant hydrogen market depends on excess capacity and by‑products, delivered by cryogenic trucks and small pipelines. A small uptick in refinery demand can quickly absorb this excess, leaving little room for new uses like fuel‑cell vehicles.

Hydrogen for other uses is different. Outside the Gulf Coast, there are virtually no pipelines to deliver fuel to stations for hydrogen cars. Compressed gas is delivered in tube trailers to scattered users. Without substantial new infrastructure, the small merchant market cannot support a nationwide fleet of fuel cell vehicles.

Technical and economic hurdles

Hydrogen molecules are much smaller than methane molecules, and they behave very differently in pipes. Hydrogen can permeate seals, valves and joints and even diffuse through plastic membranes. When atomic hydrogen diffuses into steel, it can combine with carbon and cause embrittlement, making pipelines and welds brittle and prone to cracking. Hydrogen’s flammability range in air is wide, and its flame is nearly invisible; any leak presents a higher safety risk, requiring more sensitive leak‑detection and monitoring systems. These properties mean that steel pipelines designed for natural gas often need thicker walls, corrosion‑resistant alloys and special coatings, and compressors must be designed to handle hydrogen’s higher volumetric flow. The National Institute of Standards and Technology calculated that hydrogen‑specific steel pipelines can cost up to 68 percent more than natural‑gas pipelines because of the materials and construction needed to prevent embrittlement and leakage. Even with higher‑strength alloys, thicker walls and more frequent inspection remain critical.

Building new hydrogen pipelines is capital and time intensive. Analysts note that hydrogen pipelines are the lowest‑cost option for moving large volumes over distances greater than 300 kilometers, but they require high and stable demand to justify the investment. Compressors must operate at three times the speed required for methane, adding to operational costs. Repurposing existing natural‑gas pipelines is technically possible and could reduce costs by as much as 60 percent, but modifications are still needed to address embrittlement, leakage and safety. Regulators must also coordinate federal and state permitting; interstate hydrogen pipelines do not fall under Federal Energy Regulatory Commission authority, so developers need to seek approval from each state. The fragmented regulatory landscape adds uncertainty and delays.

For smaller volumes and early markets, compressed‑gas tube trailers and liquid‑hydrogen tankers are alternatives. Tube trailers carry only 500–900 kilograms of hydrogen per trip and are limited to about 250 bar in the United States; they are useful for flexible distribution but cannot support high‑volume fuel‑cell vehicle adoption. Liquid hydrogen transport requires cooling hydrogen below −253 °C and is energy intensive; the U.S. Department of Energy reports that the liquefaction process consumes about one‑third of the hydrogen’s energy content (the theoretical minimum is about 10 percent). Because of these high energy costs, liquid hydrogen production is currently limited to nine small plants in North America sized for the merchant market. Liquefaction plants, cryogenic tanks and specialized trailers all require large capital outlays, and boil‑off losses during transport can further reduce delivered volumes.

A Department of Energy roadmap identifies several other cost drivers: the installed capital cost of hydrogen pipelines and rights‑of‑way, the cost and reliability of pipeline compressors, the high capital cost of composite tube trailers, the energy intensity of liquefaction and boil‑off losses, and the need for accurate hydrogen quality monitoring and leak detection. Material and labor costs for hydrogen pipelines are significantly higher than for comparable natural‑gas lines; a DOE program record notes that a one‑inch hydrogen pipeline costs roughly $37,000 per mile for materials and $17,000 per mile for labor, and a large compressor station (300 000 kg per day) costs more than $2.6 million. To make pipeline delivery economical—around $0.50 per kilogram—an operator must move large volumes (tens of tones per day per kilometer of pipeline) and space compressor stations hundreds of kilometers apart. At early stages of hydrogen deployment, demand is too small to justify such investments, so tube trailers and liquid tankers remain the default, despite their higher per‑kilogram costs.

These technical and economic hurdles, material compatibility, leak detection, high energy use for liquefaction, limited capacity of tube trailers and the need for large demand to justify pipelines, explain why hydrogen delivery infrastructure has evolved slowly and why building a nationwide network for fuel‑cell vehicles remains such a daunting challenge.

Understanding the gap

Given this history and the current state of infrastructure, hydrogen powered cars remain a long way from mainstream. The pipelines and liquefaction plants built for refineries and fertilizer plants cannot support a nationwide fleet of fuel cell vehicles. Merchant hydrogen supplies come from excess capacity and by‑product streams and are delivered by trucks or short pipelines; they are small, volatile and easily absorbed by refiners. Until new production and transport infrastructure is built, sustainable hydrogen autos will remain out of reach.

Stay tuned for my next article, involving how Toyota missed a tremendous opportunity to leverage an already existing infrastructure to deliver hydrogen to fueling stations.  A move that would have certainly moved us closer to hydrogen mobility as a reality.