For decades, utilities have relied on a synthetic, chemically stable, inert gas for protection against the devastating effects of arc flashes. Sulfur hexafluoride — commonly known as SF6 — has become the go-to medium for insulating critical high-voltage equipment because of its incredible propensity for energy absorption.

Since the 1960s, SF6 has been widely used in the power industry because of its superior ability to protect critical electrical equipment. Known as a dielectric, or electrical insulator, SF6 is extremely effective at attracting and holding the free electrons that are ripped from the air during an arcing event. If not controlled, arc flashes and subsequent explosions can be enormously destructive, with temperatures of more than 5,000 degrees (F) and blasts that can destroy equipment or be fatal to anyone working nearby.

The electro-negative properties of SF6 allow the gas to absorb the tremendous energy of arc flashes without having its state altered. If SF6 molecules do get broken, they come back together quickly, making it a self-repairing compound.

Now for the Downside

Unfortunately, the properties that make SF6 a game-changer at protecting high- and medium-voltage electrical equipment also make it the most potent greenhouse gas on the planet. The same chemical structure that allows it to absorb high-voltage electrical energy also allows it to absorb high volumes of ultraviolet light. To put this in context, 1 ton of SF6 emissions in the atmosphere is equivalent to the heat-trapping effects of 23,900 tons of CO2. In addition to this potency, SF6 doesn’t break down for approximately 3,200 years. That longevity has contributed to it becoming the target of legislative and regulatory bans around the globe.

Because of the critical importance of protecting high-voltage equipment, however, there has been a historical recognition by regulatory authorities that some leakage of SF6 is inevitable over the 30- to 40-year design life cycle of the tightly sealed compartments of substation equipment. In most jurisdictions, allowable leak rates are set to 0.5% to 1% per year.

Because leak rates are stipulated, rigorous monitoring of SF6 is required of all utilities. Regular reports must be submitted, accounting for the volumes of SF6 present in gas-insulated substations (GIS) over time, along with any volumes that have been refilled. Substantial penalties can be assessed by environmental agencies if leak rates go above allowable limits, or if a catastrophic failure of sealed compartments occurs.

Across the globe, an increasing number of governments are prohibiting SF6 entirely, recognizing that even with minuscule amounts of leakage, the potency of the gas combined with the large and growing volume of high-voltage electrical equipment in service will ultimately have a disproportionate impact on global climate change. In the U.S., California is the first and only state to implement a phaseout of SF6. However, New York may soon follow as the New York State Department of Environmental Conservation has proposed a regulation to phase out SF6 in 2026 with a complete ban by 2033 (6 NYCRR Part 495).

Alternatives Under Development

With the likelihood that environmental agencies will soon require a complete worldwide phaseout of the use of SF6, major electrical equipment manufacturers are developing some alternative process technologies that can protect electrical equipment with similar effectiveness.

The two leading alternatives: a vacuum breaker technology being developed by Siemens, and a fluorocarbon gas with far lower global warming potential than SF6 used by Hitachi and GE. The fluorocarbon gas was developed by 3M, but in 2022 3M announced that it would cease production of PFAS (per- and polyfluoroalkyl substances), including fluorocarbon gases. This resulted in the 3M patent moving into the public domain, allowing Hitachi and GE to source these gases from multiple vendors for equipment being developed by them. Due to their classifications, however, the gases are subject to PFAS regulations.

The Siemens vacuum pathway works by completely removing air from within tightly sealed containers housing the electrical equipment and then incorporating clean-air gas composed of 20% oxygen and 80% nitrogen for the balance of insulation and protection functions. This pathway has already been tested and proven effective for equipment with an operating voltage up to 145-kV.

Hitachi and GE are also making major strides in developing proprietary equipment. Their fluorinated gases still retain similar properties as SF6 in absorbing energy from an arc flash, but represent a 99% reduction in potency as a greenhouse gas. Another advantage of this technology pathway is that high-voltage equipment can remain approximately the same size, meaning that the overall footprint of GIS facilities would not have to be enlarged.

Evaluating the Options

When evaluating the two technology pathways, it is important to understand that there are certain trade-offs with the options offered. Some factors to consider include technical viability, physical size of the equipment, and cost. In fact, high costs of alternative technologies are perhaps the biggest hurdles that utilities now face in considering non-SF6 options.

The Siemens vacuum technology avoids concerns over GHG emissions, operates at lower temperatures and requires less maintenance, but would require an incrementally larger footprint within the substation to accommodate larger equipment. Currently, a vacuum/clean-air system rated for 145-kV would be roughly equivalent in size to a 230-kV system using SF6.

The Hitachi and GE equipment would require roughly the same footprint as that currently required by SF6 equipment, but still does not eliminate GHG emissions.

Cost is the greatest difference between SF6 and non-SF6 alternatives. All of the new offerings are currently priced at upwards of two to three times the cost of SF6 equipment, mainly due to limited manufacturing capacity and limited demand. This discrepancy is expected to narrow in the future as regulatory mandates are implemented, and as manufacturing is brought up to scale. In regions such as the U.K., for example, regulatory requirements for phasing out SF6 have resulted in non-SF6 equipment completely superseding their SF6 counterparts, making cost comparisons irrelevant.

Due to the existing demand and developing nature of the non-SF6 alternatives, differences also arise when evaluating lead times. However, in this area non-SF6 alternatives have the advantage. Our experience has been that lead times are typically shorter for non-SF6 equipment than for SF6 counterparts.

Regarding current voltage limitations, the manufacturers are forecasting that non-SF6 alternatives for equipment rated up to 500-kV will be widely available by 2030.

Pathways Forward

Though most utilities expect that environmental regulators worldwide will soon implement a global phaseout of SF6 — and are interested in exploring alternatives — they are wary of the high costs and operations and maintenance complexity that would be incurred from a complete changeover.

Utilities that execute small-scale pilot projects now, however, could effectively position themselves for the changes likely to come. Favorable lead times that are now available when ordering non-SF6 equipment could be one advantage. Currently, lead times of approximately a year and a half are common for non-SF6 equipment, versus approximately three years for SF6 equipment.

Getting a jump-start with pilot projects also could help operations staff gain familiarity with the new equipment. For example, the vacuum/clean-air alternative will require retraining on how it serves as an interrupter function and then how the clean air mixture serves as the balance of the insulation.

The coming decades will be defined as an era of expanding and modernizing power grids, while lowering carbon emissions at every turn. Non-SF6 equipment provides a pathway for utilities to implement their grids of the future free of the burden of the most intense greenhouse gas on the planet.


The California Air Resources Board implemented a phaseout of SF6 beginning in 2010, leading to a complete elimination by 2025, with some exceptions.

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Zach Sutherland is an electrical engineer at Burns & McDonnell, specializing in protection and controls applications for high-voltage substation projects. He has a passion for sustainability and power quality to enable a more resilient electrical grid.