Across the country, states have been enacting legislation requiring gas and electric utilities to decarbonize their systems. Often, these bills complement statewide initiatives to reduce either total greenhouse gas emissions or specifically buildings-related emissions.
For decades, states have required electric utilities to reduce the emissions of their portfolios, primarily through renewable portfolio standards (RPS). An RPS requires utilities to sell an increasing percentage of their electricity from renewable energy sources, such as solar, wind, nuclear, or geothermal power. All but 14 states have an RPS, although six states’ goals have expired and three are voluntary.
But these standards only cover electricity. States are beginning to turn to similar mechanisms to decarbonize building operations — including Minnesota’s Sustainable Building Standard or clean heat standards, which exist in Colorado, Vermont, and a smattering of other states.
System-wide fuel switching is a challenge, particularly when utilities that have relied on piped gas switch to electricity. Some utilities are exploring alternative routes to cutting their emissions that would let them rely on their existing infrastructure and pipeline systems: Blending renewable natural gas (RNG), hydrogen, or both with natural gas and feeding the mixture into gas appliances.
Dominion Energy began testing a blend of hydrogen and methane fuels in Ohio in January 2024. Minnesota Energy Resources’ request to mix RNG into its distribution systems was approved by the Minnesota Public Utilities Commission in April 2024. And Xcel Energy paused its plans to introduce hydrogen, ramping from 2 percent to 10 percent hydrogen, into its system’s natural gas mix in March 2024. The current residential fuel mixes represented via primary space heating fuel in these states provide insight into their relative progression in decarbonizing their heating (Table 1).
Table 1: Residential primary space heating fuel in select states
Source: Residential Building Characteristics Dashboard, Atlas Buildings Hub
All three states’ residential buildings relied heavily on natural gas and propane in 2020, when the Residential Energy Consumption Survey was most recently performed.
While most natural gas is extracted from underground, “renewable natural gas” refers to reprocessed waste methane. This methane is captured where it naturally arises in places like farms (from manure management and, yes, cow farts) and landfills (from anaerobic decomposition of organics) and processed to remove impurities. Without being captured and used for space heating, this methane would drift into the atmosphere, where it has a global warming potential about 28 times stronger than carbon dioxide. Still, when it is combusted, it generates carbon dioxide just like fossil gas, and can leak from processing and distribution infrastructure.
Hydrogen is appealing to many utilities because, unlike with RNG, combusting it produces only water vapor. Yet like RNG, it can be blended into existing gas networks with little trouble. When hydrogen is mixed with fossil gas, it is slowly introduced in increasing percentages. A 2013 study found that blending hydrogen and fossil gas at less than 15 percent hydrogen does not represent a significant safety risk. Getting the rest of the way will be a challenge. Additionally, the way hydrogen is produced is incredibly important to lifecycle emissions of the fuel.
Today, most hydrogen is produced from fossil gas via a process known as steam methane reformation. This process generates about nine kilograms of carbon dioxide-equivalent per kilogram of hydrogen. If the carbon dioxide generated in the steam methane reformation process is captured and permanently stored, the hydrogen could be considered carbon neutral, making it more attractive from a decarbonization standpoint. Carbon capture equipment, however, adds costs and requires additional power to run, complicating the profitability of creating hydrogen this way.
Green hydrogen, on the other hand, is produced via electrolysis of water powered by electricity generated from zero-carbon sources like wind, solar, or nuclear. This process is much more straightforward than steam methane reformation coupled with carbon capture and storage but has its own issues. Chiefly, electrolysis is expensive and requires a dedicated source of zero-carbon electricity — the International Energy Agency estimates that from 2022-2027, global green hydrogen production could require 50 GW of dedicated zero-carbon power generation capacity. Additionally, green hydrogen is likely to be important for segments of the economy such as heavy industry and aviation fuels that have few or no alternative decarbonization options, so utilities will need to weigh where it is most needed.
Utilities face several different pressures to decarbonize what they offer customers, and some of them are turning to lower-carbon gaseous fuels using their existing distribution infrastructure. Federal and state programs designed to help utilities decarbonize their operations are catching momentum, and regardless of whether the utilities choose heat pumps, RNG, or hydrogen, those programs will need to maintain support to attain emissions reduction goals.
