Here are three things power sector policymakers are reaching agreement on: The mid-century goal is a zero emissions economy; wind and solar alone cannot do that; and green hydrogen may be a solution.
Green hydrogen is produced by a renewables-powered electrolyzer that splits water (H2O) to make hydrogen (H2) gas. The process makes renewable hydrogen (RH2) gas more expensive than the wind or solar used to create it, but it can generate zero emissions electricity in turbines or fuel cells, be stored in higher densities and lighter weights than batteries to meet long duration storage needs, and be used in high-heat industrial processes.
As renewables deployments rise and costs fall, "there is likely to be a good business case for renewable hydrogen," Rocky Mountain Institute (RMI) Senior Principal for Industry and Heavy Transport Thomas Koch Blank told Utility Dive. "Utilities would be well served by understanding the technology and developing some hydrogen capacity before it is needed."
Green hydrogen is not new, but today's zero-emissions ambitions and abundant, low cost wind and solar are demanding reconsideration of its value and affordability.
A groundbreaking project led by the Los Angeles Department of Water and Power (LADWP) will use an H2-natural gas blend and pilot RH2 storage at the site. These may be big steps toward a business case for RH2 in a zero-emissions economy.
A green hydrogen economy?
"Hydrogen is a key industrial commodity around the world that we know how to use and store, but over 99% is derived by using fossil fuels, which aggravates the climate crisis," Green Hydrogen Coalition Founder and President Janice Lin told Utility Dive. "Green hydrogen can accelerate decarbonization."
RH2 can be "stored for long periods and used on demand" for grid balancing and can be "combusted to generate high-temperature heat for industry," a November 2019 Center for Climate and Energy Solutions paper reported. RH2 may also be "particularly useful" as an emissions-free fuel for large vehicles like buses, trucks, airplanes and ocean shipping.
"The business model for green hydrogen will begin with those applications," Lin said.
At a renewables penetration of "about 60%," RH2, or comparable long duration storage, "will be necessary" for grid reliability, University of California, Irvine, Chief Scientist of Renewable Fuels and Energy Storage Jeffrey G. Reed told Utility Dive. Alternatives like overbuilding wind and solar or batteries would be much more expensive, he said.
That high renewables penetration is coming. Nine states, districts and territories, 13 counties, 159 cities and six leading utilities have committed to 100% renewable energy by 2050, according to Sierra Clubs' Ready for 100 project. As many as 15 other states are working toward 100% commitments, Sierra Club spokesperson Stephanie Steinbrecher emailed Utility Dive.
The market potential is large. The U.S. produces 10 million metric tons of H2 with fossil fuels annually, according to the Department of Energy. Only 1% to 4% is RH2, which "signifies both the long way the technology has to go but also the potential for significant growth," according to Navigant Research.
Many of the business cases for green hydrogen depend on the relative prices of RH2 and electricity, UC Irvine's Reed said. "Through the 2020s and 2030s, production costs will likely come down dramatically as the need for what green hydrogen can do becomes greater" and scale production grows.
Today's almost "non-existent" demand could "reach 275 million metric tons by 2050," according to an August 2019 BNEF assessment. Today's price of RH2, which ranges from $2.50/kg to $6.80/kg, will be as low as $1.40/kg by 2030 and $0.80/kg by 2050, which is about $6/MMBTU, Bloomberg forecasted.
UC Irvine's more conservative analysis forecasted slightly under $2/kg in 2050, Reed said. "That is $16/MMBTU and would produce $0.10/kWh electricity from a combined cycle power plant. At $1/kg, it would be about $0.05/kWh, which is cost competitive for firm, fast-responding power and less expensive than other types of storage."
The Feb. 21 NYMEX natural gas futures price was $1.90/MMBTU, which shows the challenge RH2 still faces before it can be widely competitive with other generation sources.
But today's price forecasts are not the whole story. The higher the penetration of low-cost wind and solar, the more economic RH2 will be for power generation and the more it will be needed in reliability applications, Reed, Koch Blank and others told Utility Dive.
And the recent offer of $2.67/kg price for RH2 delivery in 2022 delivery by a hydrogen supplier H2 V Energies, suggests LADWP may surprise skeptical analysts.
Green hydrogen power plants
The two-unit 840 MW combined cycle natural gas-H2 Intermountain Power Project in northwestern Utah, led by LADWP, will replace an 1,800 MW Utah coal facility. It already has a secure water supply, a 2,400 MW high voltage direct current transmission link to the high-demand LA region, and it will interconnect with large existing and potential supplies of wind, geothermal, hydropower and solar.
In addition, the project will be built over unique underground salt caverns that are "ideal for storing hydrogen at high pressures," according to LADWP. A proposed 160 MW Compressed Air Energy Storage (CAES) pilot project would test storing wind and solar generation that would otherwise be curtailed as RH2 for seasonal reserves.
The turbines "will be able to burn a 30% renewable hydrogen/70% natural gas blend when the plant goes online in 2025," LADWP Intermountain Power Project Operating Agent Gregory Huynh told Utility Dive. "There will be a pathway to retrofit the units with modifications to get to 100% renewable hydrogen by 2045, to meet the Los Angeles zero-emissions mandate."
"Electrolyzer costs are coming down and more adoption could drive that faster, like it did with solar. Our goal is to be cost competitive, but we need steps like these to get there."
Operating Agent, LADWP Intermountain Power project
The initial 30% blend could be RH2 produced with imported or onsite renewables-generated electricity, Huynh said. "That is all still very preliminary."
As a first-of-its kind project, Intermountain's "economics remain to be seen" and "could be quite expensive," he acknowledged. "But electrolyzer costs are coming down and more adoption could drive that faster, like it did with solar. Our goal is to be cost competitive, but we need steps like these to get there."
LADWP has had "preliminary discussions on the feasibility" of producing or using hydrogen at its other natural gas plants and is "tracking the industry's progress," Huynh added. RH2 is an "important" potential solution to problems for getting to a zero emissions economy and could provide utilities with other revenue streams, "but we're focused on the first revenue stream right now, which is making electricity."
LADWP's plan to store large volumes of RH2 is an innovative recognition of the market's coming need for longer-duration, multi-day and seasonal storage, Green Hydrogen Coaliton's Lin said. Stored RH2 from low-cost renewables is likely to be more cost-effective than batteries and "can serve energy, capacity and ancillary services markets."
It is also important for utilities to see that "hydrogen strategies are electrification strategies," UC Irvine's Reed added. Because green hydrogen's "feedstock" is "largely renewable electricity," utilities can increase kWh sales by using it for hard-to-meet needs of the power, industrial and transportation sectors.
Early business case
A key early RH2 business case will be "arbitrage of power market prices," RMI's Koch Blank said. "Utilities can produce and store hydrogen when [electricity] prices are low and use it to generate power when prices are higher. In the near-term, that will be where over-generation is curtailed. Assets would be underutilized, but the virtually free power makes that business case feasible if the price differential is big enough."
When demand for seasonal storage is greater and RH2's price has come down, "its high energy density will allow humongous storage without a battery the size of Iowa," Koch Blank added.
"Leading turbine manufacturers like Mitsubishi and Siemens know it is not technically daunting to retrofit [natural gas plant] turbines for green hydrogen."
Jeffrey G. Reed
Chief Scientist of Renewable Fuels and Energy Storage, UC Irvine
The LADWP project may demonstrate another RH2 opportunity for utilities, he said. The falling price of energy and increasing value of peak demand capacity that comes with high renewables penetrations "has introduced volatility in demand and price that utilities and their customers do not like, and the storage potential of green hydrogen could reduce that volatility."
Finally, RH2 will allow leveraging some existing natural gas infrastructure built for its methane molecule "to avoid totally stranding those assets," UC Irvine's Reed said.
"Leading turbine manufacturers like Mitsubishi and Siemens know it is not technically daunting to retrofit [natural gas plant] turbines for green hydrogen," he said.
Mitsubishi has natural gas units in operation using blends of up to 90% hydrogen, Mitsubishi Marketing Vice President Todd Brezler told Utility Dive. The turbines it will bring to market "will be engineered to burn 30% hydrogen blends by 2025 and they will eventually be retrofitted to burn 100% hydrogen by basically swapping out combustion system parts during planned maintenances, at costs similar to replacing other parts."
RH2 and methane are "different molecules, but engineers will figure out the chemistry equations at costs that will allow green hydrogen to compete economically," he added. "By 2030, electrolyzer costs will be down enough to make renewable hydrogen cost-competitive and turn potentially stranded natural gas system assets into assets that can provide carbon-free power."
The Southern California Gas Company's (SoCalGas) natural gas storage facilities, which are depleted oil formations, "could be as good as salt caverns for storing hydrogen," Reed said. Building new pipelines or retrofitting existing ones "would have costs, but existing rights-of-way will be very valuable, and if we can reuse or evolve that system, it could help make green hydrogen cost effective."
SoCalGas is working "to repurpose our existing infrastructure to meet California's carbon neutrality and climate goals," SoCalGas Public Policy and Planning Manager Tanya Peacock told a Verdexchange audience Jan. 27. Delivery of natural gas-RH2 blends through the existing system can "help in the evolution of renewables."
That evolution could happen at the distribution system level as well.
Distributed green hydrogen
The cost and complexities of a new or retrofitted pipeline system could delay the vital decarbonizing of the transport and industrial sectors, Koch Blank, Reed, Lin and others agreed.
Fossil fuel combustion is today's best option to get the "continuous" or "on demand" temperatures of over 300°C, and often over 800°C, needed to manufacture vital commodities like cement, steel and plastics, Columbia University Center on Global Energy Policy Senior Research Scholar Julio Friedmann's October 2019 paper reported.
RH2 combustion could, however, soon be cost-competitive enough to replace fossil fuels in powering industrial processes, Friedmann concluded. But delivery of RH2 to industrial sites remains a challenge.
Delivery also remains a challenge for RH2 in transportation.
With adequate policy and incentive support, there could be a "hydrogen transportation sector" by "the mid to late 2020s," UC Irvine's August 2019 report to the California Energy Commission concluded. "Dozens of new renewable hydrogen production facilities will be needed to meet demand by 2030."
Support for RH2 in transportation was recently endorsed by a December 2019 Southern California Edison white paper and a February 2019 Pacific Gas and Electric regulatory filing.
"Green hydrogen is in the money right now" for some industrial vehicles, Green Hydrogen Coaliton's Lin said. And medium and heavy-duty long distance, high utilization, and heavy payload transport like some bus and truck fleets, long-flight jumbo jets and shipping "will be a really good fit."
"Electric utilities need to pay attention to green hydrogen because, like EVs, it is a potentially growing load they never before had access to."
Founder and President, Green Hydrogen Coalition
And there is a way to bypass the delivery obstacle, green hydrogen advocates agreed.
"A dedicated hydrogen pipeline would be a super gamechanger," Lin said. "But water could also be electrolyzed at the site where green hydrogen is used."
Electrolyzers producing RH2 from water and renewables-generated electricity at industrial and medium and heavy-duty fleet sites "makes sense," Koch Blank said.
Utilities could use managed charging methods developed for electric vehicles (EVs) to get similar or greater system benefits, he added. And co-locating electrolyzers and RH2 storage at fast charger and fuel cell refueling sites could help reduce load spikes.
Regulators could support utility participation in electrolyzer deployment in the same ways they supported EV charger infrastructure deployment, UC Irvine's Reed agreed. There is "a compelling regulatory argument" in load management benefits and new revenues.
"Electric utilities need to pay attention to green hydrogen because, like EVs, it is a potentially growing load they never before had access to," Lin added. "Innovation that is hard to imagine is coming" and "the transition to green hydrogen offers something for every incumbent, from electric and gas utilities to policymakers and private developers."