Nearly two decades of incentives and energy policies have spawned a remarkable duality in renewable energy. Solar accounts for just 3.9% of total U.S. electricity, yet California produced so much solar energy, the state essentially threw it away. This has prompted lawmakers to cut back on incentives and delay installations, but nationally there are few signs of solar abating (Osaka, 2024). In February of 2023, for example, the EIA estimated that over half of new U.S. electricity generating capacity would come from solar, compared to just 11% from wind and 14% from natural gas (Fasching & Ray, 2023). If solar proliferation continues, even modestly, this presents both infrastructure and policymaking challenges. Furthermore, the United States’ commitment to 100% carbon-free electricity by 2035 (WH, 2021), necessitates a massive investment in renewable energy. This is further supported by the IRA, IIJA, and FERC order 2222 which not only encourages distributed energy resources like rooftop solar, but requires utilities to integrate DER into the grid. Yet, as the California case shows, the intermittent nature of renewables lends such energy sources to extreme cycles of boom, bust, and waste.
The seasonal characteristics of renewables have made storage a critical component of the green ecosystem. In fact, while the storage conversation centers around lithium-ion solutions, the concept of batteries is broad and often far removed from chemical processes. Pumped hydro and thermal storage are two examples, however, as this paper argues, hydrogen presents an intriguing alternative that can be both green and renewable at scale. Moreover, hydrogen compliments the ancillary, short-term application of traditional batteries by providing robust seasonal energy for those months where little solar is available. In this, hydrogen does not compete with battery storage but instead fills a gap that would otherwise be covered by fossil fuels.
This paper explores the policies that advance hydrogen’s use as a grid-scale energy source in three capacities: a seasonal supplement to intermittent renewable energy, a store for excess renewable energy, and onsite industrial energy supply. The benefits of such applications are threefold. First, committing excess renewable energy to hydrogen production avoids waste as is currently happening in California. Second, as the mix of renewables grows, the impact of intermittent supply will become more apparent. Stored hydrogen provides both cheap and reliable energy to a wide range of customers and helps FERC meet its obligations in those areas. It also helps smooth supply dips, reduces risks to infrastructure and helps RTOs and ISOs ensure adequate, affordable supply to their regions. Finally, stored hydrogen, particularly in industrial capacities, helps reduce congestion by alleviating transmission loads during peak usage periods.
Background & Literature Review
The use of hydrogen is nothing new. In fact, heavy industries around the world produce large quantities of hydrogen for use in everything from fertilizers to steel. It is not, however, widely used as a source of electricity, and its application in this domain remains largely theoretical. That said, hydrogen possesses intriguing potential as a long-term supplement to intermittent renewables. Similarly, it has potential as an alternative power source to energy intensive industries like manufacturing and computing, and as a capacity management system that reduces congestion through DER.
To begin with, however, it’s important to acknowledge the limitations of hydrogen as an energy source. For example, Both Lambert (2007) and McWilliams & Bruegel (2021) write that hydrogen is not as energy efficient nor as cheap as traditional batteries. This is, in part, because traditional lithium-ion batteries store electricity while hydrogen fuel cells manufacture it. This process produces electricity, heat, and water instead of simply releasing electricity (DOE, n.d.). For this reason, hydrogen energy systems are not an ideal solution for intra-day applications. However, both Lambert (2007) and McWilliams & Bruegel (2021) believe it is cost-effective and environmentally favorable when deployed at scale over several months (for example, during winter). Energy efficiency also declines through the process of manufacturing and storage. Flux power (Flux, 2021) writes that hydrogen produced by electrolysis is only 30-40% efficient, while Bloom Energy (Bloom, 2023) was more optimistic, citing efficiencies as high as 60% in certain applications. Regardless, energy loss is a consideration. Furthermore, Edwards et al (2007) cite the “significant energy penalty” (p. 1050) associated with hydrogen storage, not to mention further losses incurred if the gas is used to make steam. Therefore, good policy must consider how hydrogen is to be used, its strengths, weaknesses, and appropriate applications.
Nonetheless, long-term storage is perhaps the most obvious grid-scale application of green hydrogen. Lambert (2020) and McWilliams & Bruegel (2021) each note the potential for hydrogen to be used as a seasonal load balancer, during periods when renewable sources aren’t as plentiful. This seasonal use compliments ancillary systems, like batteries and spinning reserves, by assuming a long-term, base-load role. Moreover, unlike lithium-ion batteries, hydrogen fuel cells do not need to be recharged so long as the supply of fuel remains constant (DOE, n.d.). Moving hydrogen, however, presents both incentives and disincentives for grid-scale applications. On the one hand, Edwards et al (2007) write that the current transportation system cannot be easily converted to carry hydrogen. Moreover, moving hydrogen at scale, they write, will require significant research and development. Lambert (2020), however, cites studies suggesting the existing natural gas infrastructure is indeed capable of handling pure hydrogen. Either way, it’s fair to assume that infrastructure investment will be required to bring hydrogen power to market in large quantities.
Alternatively, these risks can be mitigated by producing hydrogen onsite. In fact, onsite electricity production presents an intriguing opportunity for industry, regulators, and policymakers alike. For example, while residential customers number over 154 million, there are just 900,000 industrial consumers. Yet those customers draw over 25% of domestic electricity, the majority of which is bought from suppliers (Shively & Ferrare, 2019). In fact, according to the EIA (2023), just 15% of industrial electricity is produced onsite, with most of that coming by way of combined heat and power (CHP) generation. In that, there is an opportunity for green hydrogen. Edwards et al (2007) write that hydrogen-based CHP is up to 85% energy efficient, making it an intriguing replacement to natural gas. Such energy efficient solutions take on increased importance as the EIA expects total energy needs to more than double by 2050, with a majority of that being supplied by intermittent renewables (AEO, 2023).
The issue then becomes one of supplying power cheaply enough to economically manufacture hydrogen on-site. This could entail entering into exclusive power purchase agreements or standing up dedicated transmission lines to meet those needs. As with all aspects of the hydrogen solution, transmission is not without complications. Shively & Ferrare (2019) and Robertson & Palmer (2023) both express the difficulty in setting up new transmission lines, and RTOs face significant challenges bringing energy to customers when lines cross multiple jurisdictions. Nonetheless, onsite hydrogen production avoids transportation challenges while also absorbing excess energy from the grid. Perhaps most importantly, locally produced electricity reduces congestion by feeding it directly to the load.
Finally, it’s necessary to discuss some of the existing policies, their challenges and unintended consequences as they relate to hydrogen. To begin with, hydrogen production has many applications outside of electricity that compete for attention. For example, McWilliams & Bruegel (2021) note the challenge for policymakers lies in knowing where hydrogen fits in the green economy. Its power producing capabilities are one potential use, but it possesses a wide range of industrial applications that make knowing how it should be used more difficult.
Perhaps more crucial is green hydrogen’s dependence on cheap energy. Edwards et al (2007) write that though commercial hydrogen is 75% energy efficient, the cost of electrolysis is still several times higher than hydrocarbon-derived production (p. 1047). Over ten years later, the Department of Energy continues to cite the cost of electricity as the single biggest prohibitor to hydrogen production (Peterson et al, 2020 p. 13). Therefore, the success of hydrogen is directly coupled to policies that promote cheap energy. In that, the discussion has come full circle, returning to the dilemma faced by California lawmakers who have curtailed solar incentives due to an overabundance of supply. Rogers & Wisland (2014) summed up this problem rather succinctly, writing that DER integration is not a technical challenge, it is largely one of economics. Specifically, who pays for the cost of transmission when the flow of electricity is reversed (p. 4), or as was the case in California, when prices go negative.
On that note, federal policies have produced both benefits and drawbacks to DER, and by extension, green hydrogen. The Infrastructure Investment and Jobs Act directs federal funds toward the research and development of clean hydrogen energy systems. It also directs research toward more efficient electrolysis and establishes clean hydrogen hubs for developing and promoting new technologies (Christensen et al, 2021). These policies along with a trend of energy decentralization, suggest that renewable energy will be cheaply available to green hydrogen producers over the long-term. On the other hand, serious concerns exist over supply chains and ongoing trade disputes with China, Southeast Asia, India, and others. Nikos et al (2021) write that tariffs put in place under the U.S. Trade Act of 1974 have increased the price of Chinese PV cells by upwards of 60%. The increased costs are one reason solar prices are higher in the United States than in most of the rest of the world (p. 16). Runde & Ramanujam (2020) similarly argue that the pandemic highlighted the United States’ overreliance on foreign supply chains, and suggest a need to reshore American manufacturing. In summary, federal and state policies aimed at the proliferation of DER necessitate supply chains capable of meeting that demand. Consequently, achieving grid-scale green hydrogen as mentioned by the IIJA, is likewise dependent upon international supply chains and trade policy.
Policy Options
As the preceding discussion has shown, green hydrogen offers a compelling solution to seasonal inconsistencies in renewable energy. It is, however, predicated on an abundance of cheap, renewable energy, making it directly dependent on DER and susceptible to international trade policies. Fortunately, it’s not necessary for policymakers to solve a grid-scale problem in one initiative. Much in the way today’s DER initiatives are predicated on over forty years of prior policy, hydrogen adoption can, and arguably should, be done incrementally.
As a starting point, policymakers can target specific industries. For example, Ohio might partner with heavy manufacturers while Arizona and Texas might choose to work with industrial computing. The goal of such programs would be to reduce congestion and enable growth by promoting onsite power production. Under such a program, industry partners could receive abatements, carbon credits, or property tax adjustments based on the percentage of power they generate onsite. Two roughly parallel models exist for this approach: PURPA’s avoided cost stipulation (Shively & Ferrare, 2019) and property tax breaks for homeowners who install DER (Rogers & Wisland, 2014). Such policies are effective in 45 states and carry broad public support. In either case, adapting these policies to industrial customers could incentivize onsite energy production and help meet EIA growth projections while reducing congestion.
It’s important to note that onsite power production doesn’t necessarily require grid-ready fuel cell technology. As was reported by the EIA (2023), most onsite power production comes from CHP processes. The extent to which hydrogen could replace natural gas is a critical point for R&D, however, hydrogen and natural gas blends are an alternative that could work with existing infrastructure. For example, tests have proven blends containing 5-10% hydrogen were compatible with existing technology, and Europe is testing concentrations as high as 20% (Lambert, 2020). Therefore, regulators could stipulate a hydrogen transition that mirrors ethanol additives in fuel, rewarding companies who produce or use green hydrogen in lieu of natural gas.
More importantly, excess energy must be both affordable and accessible. Congestion is one of the biggest risks to supply and often necessitates establishing new lines. Given the difficulties in building new transmission cited by Shively & Ferrare (2019) and Robertson & Palmer (2020), it’s important for RTOs to begin the planning process early. One policy approach could be to build on FERC order 2222 and require utilities to provide hydrogen producers with direct access to excess energy, provided that excess is derived from renewables and used to produce green hydrogen. In that, RTOs and utilities are compelled to build new transmission lines, while industrial consumers are rewarded for investing in green hydrogen DER. Furthermore, Villarreal (2020) advocates for adopting policies that compel utilities to invest in DER, noting that their multi-year planning processes benefit from the flexibility DER provides. Taking industrial demand off the grid reduces both technical and bureaucratic risk.
Finally, ensuring abundant, cheap energy is essential to the success of clean hydrogen, however, as California has demonstrated, incentives lose effectiveness when excessive energy is produced. Nonetheless, for states lacking California’s solar boom, there are effective policies available. For example, Rogers & Wisland (2014) write that net metering and property tax breaks still hold value in most areas. Others, like Ünel & Zerbe (2022) argue that net metering fails to compensate DER owners for the full value of their investment. In that, homeowners should be paid for both the utility and environmental avoided costs (pp. 5-6). Alternatively, requiring utilities to invest in clean energy is another option. For example, as part of their renewable portfolio standard, New Jersey requires 35% of energy sold in state to come from renewables (NJ, n.d.). A final approach, not discussed in any of the literature reviewed here is to require solar on all new construction. This could reasonably be limited to areas conducive to solar generation, and is more appropriate for markets like California where incentives are no longer effective. As with all of these solutions, however, supply concerns exist for such large-scale production initiatives.
Policy Recommendation
Any policy must contain clear scope and success criteria. Therefore, the recommendation in this paper is to create abundant, cheap electricity through DER and provide that energy to industrial partners for the purpose of creating clean hydrogen. McWilliams & Bruegel (2021) advocate for a similar approach, noting the unpredictability of the residential market, appliance compatibility, and a host of other technical complications as reasons to avoid consumer-based solutions. Alternatively, industrial customers often exist in clusters with dedicated infrastructure, some of which is hydrogen compatible, or capable of supplying the power required to manufacture it onsite (pp. 5, 10, 20). Industrial customers are fewer but also have the most to gain from self-managed DER. Provided overhead is sufficiently reduced, supplementing their energy consumption with clean hydrogen may prove cost advantageous, particularly in those periods where renewables are unavailable. Achieving partial grid separation would also help insulate them from extreme price spikes that occur on an intra-day basis.
McWilliams & Bruegel (2021) write that finding an industrial partner willing to share some of the risk is essential to the technology’s success. In this, regulators have an opportunity to incentivize industrial cooperation by providing tax breaks, carbon credits, and direct access to cheap (or free) renewable energy. If opportunities do not already exist for the private sector to partner with the DOE, policymakers should consider expanding the IIJA to include such programs. Local governments could work with specific companies to install, upgrade, or test existing infrastructure for use with hydrogen CHP. The DOE’s EV-focused Workplace Charging Challenge is a good example of what such a policy could look like. The important point is that such policies produce real world infrastructure from which data can be collected.
Finally, amending FERC order 2222 to require RTOs to provide excess green energy directly to industrial customers is a great long-term strategy. There is unfortunately, likely no way around the difficulties of building new transmission lines, though to the extent possible, regulators can work to streamline the process. This policy provides transmission operators with a destination for their excess energy while also incentivizing industry to invest in DER. It’s worth noting that residential incentives are not recommended due to the uncertainty of green hydrogen’s compatibility. In that, it is important that policymakers limit scope as described and work with a handful of participants, perhaps by holding a lottery, where government agrees to share the capital costs associated with green hydrogen infrastructure. On a longer-term basis, regulators need to establish real targets, like those stated around emissions reductions. For example, converting 50% of onsite energy production to green hydrogen by 2050 is one goal. Having all industrial customers fully independent, sustainable, and renewable by 2060 is another objective. Either way, real world infrastructure and measurable definitions of success are critical.
Conclusion
Clean hydrogen presents a terrific opportunity to provide seasonal energy when solar and wind are not available. The risks of hydrogen, including infrastructure compatibility, DER dependence, and international policies, make its viability far from certain. Therefore, policymakers must consider options that are both targeted and carry well-defined measures of success. To that degree, a focus on industrial customers, infrastructure support, including direct access to cheap energy, and active federal partnerships are essential to the success of clean hydrogen.
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