The Utility Dive Outlook on 2021

At this time last year, few people — if anyone — could have predicted what 2020 would bring.

That tumultuous year has not yet led to a calmer one, but if January 2020 taught us anything, it's that the first days of a new year may not always be a sign of what's to come. With that being said, Utility Dive spoke to over half a dozen power sector experts who tentatively predict big changes on the horizon in 2021.

A new administration under a new party is one of many signs that 2021 will look different for policymakers, regulators, utilities and other stakeholders, but the continuation of some older trends is expected as well: Utilities will continue to invest aggressively in renewable energy resources, and the power sector will continue to evolve toward a less centralized model.

Here are 10 stories to watch in 2021:

Biden Administration, paired with Democrat-led Congress, will lead to major federal policy shift

President-elect Joe Biden during his campaign outlined a $2 trillion plan to bring the U.S. electric grid to 100% zero-carbon resources by 2035. Though stakeholders are skeptical such a plan could pass Congress, they expect a Democrat-led Senate will yield big investments in green infrastructure, and broadly lead to a greater focus on climate and clean energy at the federal level.

Analysts expect expanded and upgraded transmission along with increased electric vehicle deployment to be targets of Congress and the administration, with some experts optimistic that something like a federal clean energy standard could be set.

Accelerated investments in EVs, transmission and other green infrastructure are expected to come through a new stimulus package that would ideally target state and local aid, freeing up state budgets so that they can pursue large, comprehensive clean energy packages of their own, according to J.R. Tolbert, managing director at Advanced Energy Economy.

At the same time, the new administration creates a more optimistic outlook for renewables, as evidenced by the rise of various clean energy stocks in the wake of Democrats' two Senate victories in Georgia, while fossil fuels' future — and the practicality of investment in those resources — remains uncertain, according to analysts.

FERC will be seen as ‘linchpin' of clean energy progress

A more aggressive federal approach to clean energy will require a more aggressive Federal Energy Regulatory Commission, observers say. 

"The focus on the agency, as a linchpin of clean energy policies, has really been pretty remarkable," said Jeff Dennis, managing director and general counsel at Advanced Energy Economy (AEE). "There's gonna be a lot of expectations, and they're going to have to prioritize, given bandwidth."

Part of the commission's challenge will be in how it should address the commission's controversial expansion of the minimum offer price rule in the PJM Interconnection and its elimination of buyer-side mitigation rules in the New York Independent System Operator (NYISO) market, Dennis and other observers say. Biden is expected to name a new commission chair quickly, but FERC will still be a majority-Republican body until the end of Commissioner Neil Chatterjee's term June 30, which may make pursuing action to reverse or otherwise diminish the MOPR and BSM orders more difficult to do immediately, according to experts.

Both Democrat-appointed FERC commissioners have made it clear that climate change can and should play a role in FERC decision-making, which could mean greater consideration of greenhouse gas emissions and environmental justice when approving major gas infrastructure projects. 

Transmission planning reform is one area where there is likely to be stronger bipartisan consensus at FERC, observers say, and unlocking transmission is considered crucial to broader U.S. renewable energy deployment, making it something Congress and others parts of the Biden administration could target as well.

Gas may face reckoning

Natural gas prices have fallen dramatically in recent years and smaller, more flexible peaker plants have regularly been referred to as a "bridge fuel," or a lower-emissions alternative to coal that still operates in a central, dispatchable manner. But increased urgency and data on climate change, coupled with a new administration, could make gas a less appealing investment, according to stakeholders.

Though Biden promised to avoid a ban on fracking gas, a new FERC may make permitting trickier. Once Democrats have the majority, the commission may also be more willing to take into consideration climate and community impacts when considering building out gas infrastructure.

Commissioner Richard Glick, the longest-serving Democrat appointee on the commission, has long indicated he thinks the commission should consider greenhouse gas emissions when looking at pipeline and other gas infrastructure proposals. The commission's other Democrat, Allison Clements, has similarly indicated she believes FERC should consider climate change and other factors in its decision-making.

On the utility side, pressure to stop building out gas infrastructure is only anticipated to grow from advocates, said Leia Guccione, managing director for the Rocky Mountain Institute's Electricity Program. Though utilities are cutting carbon quickly from their electric portfolios, climate science requires even more aggressive actions, meaning utility gas subsidiaries will be targeted next.

"One thing we're waiting for with bated breath is who's gonna dare to try and be the first to talk about how they decarbonize their gas business," Guccione said. 

All eyes will be on Southeast and West energy market discussions

Southeast utilities' proposal to form a centralized energy exchange market — the Southeast Energy Exchange Market (SEEM) — could play an interesting role in the debate over whether to open more regions to wholesale market competition.

Many clean energy proponents want to see full competition in the Southeast, with research and consulting firms Energy Innovation and Vibrant Clean Energy finding such a market could save $384 billion by 2040. But advocates in the state worry the utilities' proposal could undermine legislative and regulatory efforts to open up North and South Carolina to such competition.

"What role the SEEM plays in that, if any, that's something to look at," said Mike O'Boyle, director of Electricity Policy for Energy Innovation. North Carolina regulators blocked utilities from filing the proposal with FERC until the state decides whether it should take a greater oversight role in the process.

If the SEEM proposal does get to FERC, the big question will be what the commission does with it, according to Dennis.

"Will they use it as an opportunity to engage with the states in the region, and with large customers in the region, and renewable developers in the region around what the future of wholesale markets looks like in the region?" he said, in addition to digging into whether SEEM itself is a structure they would approve. 

Developments in the largely unstructured Western markets will continue as well, say observers, and stakeholders will certainly watch as Western utilities mull the comparative benefits of newer imbalance market creations from the Southwest Power Pool or the California ISO's existing energy imbalance structure. A key issue swirling around Western market organization is ensuring California and other western states better coordinate to ensure resource needs are met, to avoid a repeat of last year's rolling blackouts in California.

Stakeholders will closely watch California's resource adequacy proceeding

How California prepares its grid for this summer is something regulators, lawmakers, regional grid operators, utilities and others are likely to keep a close eye on, according to analysts.

A major heat wave and weak resource adequacy margins triggered rolling blackouts in the state that lasted several days last August. Now, CAISO and the California Public Utilities Commission are focused on preparing for next summer, and stakeholders say how they address the issue of resource adequacy will be essential in creating a path forward for other states and grid operators as they shift toward more variable generation resources.

"It puts California in the spotlight," said James Pryde, partner in the Energy and National Resources Group at the Bryan Cave Leighton Paisner law firm.

FERC Chairman James Danly's attempt to initiate a federal investigation into the outages was rejected by the commission majority, which argued in part that getting federal regulators involved would hinder the state's process. But though some federal lawmakers have implicated solar as the culprit of the blackouts, stakeholders say it's more complicated than purely an issue of variable resources.

"It is a CAISO problem, not a clean energy problem," said Tolbert. Part of the solution will require CAISO and the CPUC to fundamentally rethink resource adequacy and how [they] will account for hybrid resources and demand response as part of that calculation, said O'Boyle.

Utilities will make more hydrogen announcements, resource plans will take a closer look at hybrid resources and portfolios

Clean energy advocates hope 2021 will see utilities be more creative in their long-term resource planning, looking to renewables-plus-storage hybrids and clean energy portfolios to replace plans to build out more natural gas infrastructure. 

New Mexico regulators in July unanimously selected a 100% renewables and storage portfolio for the Public Service Company of New Mexico to replace a portion of the soon to be shuttered San Juan coal plant. Regulators chose the renewables plan over one that would have added gas resources to replace the capacity, finding the former was cheaper and more in line with the state's requirement to reach 100% carbon-free energy by 2045.

To generate more of these kinds of commitments, there needs to be a shift in how long-term resource planning is done, said Kathleen Spees, principal at consulting firm The Brattle Group.

"A lot of the folks who do the integrated plans and the resource planning are going to have to ... rethink how they do everything," she said. "A lot of the traditional approaches are just really designed around figuring out how much of a traditional resource you need, they're really not figuring out how you can get the most out of the new tech."

Hydrogen is another zero emission resource that received a lot of attention at the end of 2020. As a result, analysts expect more utilities to include it in long-term resource plans, though cost barriers will likely prevent actual deployment in the next year.

"Investors and industry are beginning to recognize that hydrogen may be able to provide the on-demand generation that can help ensure grid reliability," Bernard McNamee, former FERC commissioner and partner at McGuireWoods law firm, said in an email. "[B]ut right now, the challenge is making it cost-effective."

Decline of U.S. coal economics expected to propel financing exit. Stakeholders will need to address transition

Coal economics have been in decline for years now and are not expected to bounce back.

Blackrock, the largest asset manager in the world, at the start of 2020 said it would exit investing in thermal coal production altogether, citing it as a "high sustainability-related risk." Other investment companies are similarly urging utilities to back away from coal-fired investments, a call that's only expected to grow louder, said Guccione.

"You're gonna start to see all of the flavors of the financial sector start to either take action or express opinions around their risk tolerance for coal, their willingness to have coal in their portfolios, [or] what they're expecting utilities or other merchant companies who own coal to be doing with it," she said. Rapid definancing of the sector raises the urgency for regulators and lawmakers to address transitioning communities impacted by the change, determining how to best finance early retirements, and finding creative ways to clean up and repurpose old coal sites.

Securitization is one approach that's been consistently raised as an option for vertically-integrated, regulated utilities by allowing them to pay off stranded asset debt, and can free up additional funds for worker release and economic development. Stakeholders in Missouri, for example, are hoping securitization legislation gets enacted this year, in an effort to encourage Ameren to retire its coal plants quicker.

A lot of questions still remain for how to address coal shutdown transitions with public and member-owned utilities though, said Guccione, and solving that problem may require federal action. 

"We see opportunities for the new administration, through various forms of federal action, to do something there," she said.

Electric vehicles will be more accessible, raising charging, load questions

Declining battery costs are expected to boost the selection and price of electric vehicle models available in the market dramatically, which experts say is key to amplifying EVs' overall market share.

"It's no longer the crazy man's or rich guy's hobby," said Morten Lund, partner at law firm Stoel Rives' Energy Development group.

Models available to U.S. customers are anticipated to more than triple in the next three years, according to the Electric Power Research Institute, jumping from roughly 40 to 127. Those new models include electric pickup trucks, filling a major vacancy in the EV market, according to AEE.

Corporate-level EV interest is soaring as well with major transport-heavy companies such as Amazon to buy more EVs. School bus electrification is also getting more attention, alongside broader trucking fleets.

A potential boon in the number of EVs on the road will raise critical questions about how to manage large additional loads of electricity, how to deploy charging stations quickly, and how to determine ownership of charging stations, experts say.

"Everybody's behind on charging infrastructure, and it has big implications for the market," said Matt Stanberry, managing director at AEE, "So there's a lot of interest in it."

Utilities, renewable energy firms will have to assess COVID-19 recovery

Though the power sector remained relatively stable during the COVID-19 pandemic and economic crisis, some renewables projects saw delays, solar saw a slight dip in installations, and utilities saw some declines and shifts in load.

For the renewables market, tax credit extensions that came in the latest economic stimulus package coupled with the Biden administration's pro-renewables bent could help buoy the sector against a potential slump later this year, said Lund. 

"We managed through 2020, essentially on built up inertia and fumes. But that could start running out," he said, in part based on "the sheer uncertainty" facing the markets. "The nice float that we had last year can only continue so long. And we just don't have a good sense for how much longer we can sustain ourselves on inertia," he added. The renewables industry is expected to continue lobbying Congress for direct pay options to replace the tax credits and give the sector more certainty.

On the utility side of things, a major question is how debt from $40 billion in unpaid utility bills will be paid off. 

"That's definitely going to be a big issue, from a general utility sector point of view," said O'Boyle.

Cyber remains a threat, and a bipartisan issue

Cyber attacks continue to present a growing threat to the power grid, and targets are more variable as the grid becomes more digital and decentralized. Federal regulators are taking a more vested interest in incentivizing utilities to harden their systems more aggressively, particularly as studies find power providers to be particularly at-risk of an attack.

An unprecedented cyber attack uncovered near the end of 2020 has only heightened scrutiny. Stakeholders hope cybersecurity, which continues to receive bipartisan support, will see more legislative and regulatory action in 2021.

"Cybersecurity is the one issue in Washington that hasn't been politicized — everyone knows the threats to the grid are real," said McNamee.

Acceleration of the growth of distributed energy resources (DER) has power system analysts anticipating big changes on utility distribution systems in 2021 and throughout the 2020s.

Continued falling prices of DER, ambitious new state and federal policies, and customer demand in 2021 will drive growth, power industry representatives said. And while utility-scale renewables growth will still boom, DER, including rooftop solar, batteries and electric vehicles (EVs), can be central to protecting reliability, according to a new Southern California Edison (SCE) paper describing the evolution of tomorrow's grid.

SCE’s Reimagining the Grid "is to help establish where and why we should turn right or turn left in building a distribution system to address evolving needs," said SCE Vice President of Asset Management, Strategy & Engineering Paul J. Grigaux. Those turns "will be determined by the growth of distributed resources and we want to have the system technologies to see and manage their impacts."

"We're reaching a threshold where distributed energy resources add up to enough megawatts to matter," Brattle Group Principal Ryan Hledik added. "And the idea of managing them in an aggregated coordinated way is being taken more seriously now."

There is likely to be much more attention in 2021 on proposals like SCE's for a future distribution system that can use DER to provide grid services, other power system analysts agreed. That attention is now needed because the DER are increasingly showing up and will accelerate in the coming year, the analysts said.

Growth and trends

Concrete predictions about growth are difficult only because economies of scale are driving costs down and growth up faster than forecasts can be made, according to DER advocates.

Prices continue to steadily fall, the December 2020 Lawrence Berkeley National Laboratory distributed solar data update confirmed. From approximately $12/watt in 2000, prices had fallen in 2019 to between $2.30/watt and $3.80/watt, depending on system size and market.

Residential solar 2020 installations were forecast by the 2020 Q4 SEIA-Wood Mackenzie U.S. Solar Market Insight Report, released Dec. 15, to have "13% growth in 2021." And that was before the recent extension of solar’s federal tax credit, which will help drive even greater growth into the early 2020s.

The COVID-19 relief bill’s functional extension of the tax credit through 2025 and anticipated further clean energy support from the Biden administration and a Democrat-controlled congress are likely to accelerate distributed solar growth and cost declines, analysts agree.

The newest policies to compensate solar include incentives that will also drive distributed battery storage growth, according to Autumn Proudlove, senior policy program director for the North Carolina Clean Energy Technology Center (NCCETC) policy quarterlies on solar, grid modernization and electric vehicles (EVs).

"Increasing growth is the biggest thing expected for storage in 2021," Energy Storage Association (ESA) Vice President for Policy Jason Burwen agreed.

The U.S. energy storage market is set to grow from 1.2 GW in 2020 to nearly 7.5 GW in 2025, representing sixfold growth, according to December’s Q4 2020 ESA-Wood Mackenzie Energy Storage Monitor. The total market value is forecast to cross the "$1 billion annual threshold in 2020" and "be a $7.3 billion annual market in 2025," the report added. 

"This year’s installations alone almost match cumulative U.S. battery storage, and 2021’s total capacity is forecast to reach over 3.5 GW," Burwen said. Residential storage represents about 20% of growth, he added.

The cost of battery storage has also declined "much faster than predicted, and will continue in 2021, though the curve may decline more gradually," he said.

FERC Order 2222, approved Sept. 17, requires wholesale market operators to develop rules and tariffs for DER, and is therefore expected to eventually bring aggregated distributed storage into wholesale markets, but the 2021 focus will be developing compliance filings, Burwen said. ESA will be working on that and "other ways to allow better utilization of behind-the-meter storage for grid services."

At the state level, key 2021 proposals will be Arizona’s value of DER tariff and Connecticut’s storage program design, Burwen said. "Progress will be state by state because some state regulators and lawmakers will lean forward on this and others will not, and progress is most often in response to regulatory pressure."

As the penetration of EVs grows, their load will eventually also be a major factor on the distribution system.

Though all car sales slowed sharply in 2020, Q3 2020 EV sales, led by California, were up nearly 60% from Q2 2020 and down only around 3% from Q3 2019, according to transportation electrification advocacy group Veloz.

But a "five-fold growth" will still take 2020’s 1.4 million EVs sold in the U.S. to 6.9 million units in 2025, according to a Nov. 19 report by global business research and consulting firm Frost and Sullivan.

Important transportation electrification policy priorities in 2021 will be returning to Obama-era tailpipe emissions standards and setting new financial and non-monetary incentives that drive growth, Boone added.

Federal action on EVs is likely to increase with Democrats controlling the White House and Congress. President-elect Biden, his Secretary of Transportation nominee Pete Buttigieg, and incoming Senate Majority Leader Chuck Schumer, D-N.Y., have described ambitions to expand transportation electrification.

But state mandates for EV procurement like those that drove renewables growth are the current emerging trend, NCCETC’s Proudlove said. At least 11 states are working on EV adoption policies that will add to growth, according to NCCETC’s Q3 2020 policy update, released in November.

This cumulative growth of solar, storage, EVs and other DER can lead to integration of new load in a way that supports the system and is a bigger part of system planning, Proudlove said. "It will be important to understand the effects on demand and load and on the need for distribution system modernization, and recent state utility commission proceedings about flexibility are likely to increase in 2021."

The new grid

Advancing a discussion about distribution system modernization will require alignment between utilities and DER advocates, Proudlove said.

The next phase of a debate that started with SCE’s 2018 rate case is leading to that kind of alignment, SCE’s Grigaux said. The California Public Utilities Commission "and other stakeholders see a new future evolving very quickly because of what's happening in the customer-driven marketplace in response to climate adaptation and technology costs and technology advances."

Greater reliance on variable wind and solar resources will require managing "challenges to safety, grid stability, asset condition, reliability and resilience," according to SCE’s recent white paper, the newest addition to its Pathway 2045 vision of how to meet California’s net zero emissions by 2045 mandate.

The direct impact of the growing "frequency and magnitude of climate-driven disruptions" will drive grid "evolution" by increasing customer demand for DER, the paper said.

Impacts of climate disruption and customer adoption of DER will vary by location and depend on things like urbanization, demographics and infrastructure, and "grid planning, design and operations will need to evolve," the paper continued.

The challenge of "inverter-based customer-owned technologies such as distributed solar and batteries is that their fluctuations can impact system voltage and frequency and threaten system stability," Grigaux said.

The utility needs visibility into "how the grid is operating at any node in the system to be able to respond to disturbances or outages," he said. "Today’s inverters and current technology limit that visibility," and the growth of system variability "will require a higher performing communications network."

There will be a new need for "more region-specific, ‘modular’ grid designs" and for strengthened "forward radar" to foresee customer adoption of technologies and the system issues they present, the paper said. Planning must take a "multiple scenario-driven, adaptive and more proactive approach using probabilistic analyses" to create "system flexibility" to address "future uncertainty."

A "reimagined" system must have the sensors, and communications and analytic technologies to provide "a targeted real-time response" to changing load, supply, and infrastructure conditions created by increasing amounts of DER, the paper added.

Building this "intelligent secure information and operations network" to manage DER and the poles and wires to support it "will require significant investment," Grigaux said. The paper is intended to make 2021 a year in which stakeholders’ "collective commitment to new technologies" grows and regulators and policymakers begin to understand the obstacles "to deploying the needed technologies."

SCE’s proposal is at the "cutting edge" of distribution system planning, Vote Solar Senior Director for Grid Integration Ed Smeloff said. "It builds on successes in New England and other states that allow customer resources to provide grid services, but I have not seen anything this advanced."

Preparing to "orchestrate DER flexibility is complex," Smart Electric Power Alliance Director of Research and Industry Strategy Brenda Chew added. "This is a design for a granular, forward-looking capability that can allow the situational awareness to anticipate changes in technology adoption and prepare to manage them."

Analysts say SCE’s vision can be put to use in two key ways.

Uses of the new grid

The distribution system envisioned by SCE can use today’s just emerging DER penetrations in 2021 for load flexibility, customer engagement, peak demand reductions and new infrastructure cost deferments, analysts said. And soon, SCE’s vision will enable DER as energy supply.  

"Regulators have already approved utility expenditures for incentives to customers for use of their DER for grid services, and that trend should not slow in 2021," Brattle Group Principal Ryan Hledik said. "Those programs are now reducing costs to ratepayers for distribution system upgrades and allowing utilities to increase system flexibility by offering customers new products and services," he said.

Regulators are also likely to consider performance rewards to utilities in 2021 for load flexibility offerings, Hledik said. "Where regulators see the system benefits of load flexibility but their utilities remain reluctant to support DER, regulators may pressure utilities to do more this year."

That may include trials of a new concept that couples a fixed bill with residential customers' DER technologies in return for participating in load flexibility programs, he added.

The SCE paper describes what different distribution systems will need as DER evolve at different times across the country, said Newport Consulting Managing Partner and former SCE Vice President for Advanced Technologies Paul De Martini. He co-originated the use of the "walk-jog-run" concept to describe the emergence of DER and other new power system technologies.

Places like California are "in the jog phase with DER and by the end of this decade will be into run mode," De Martini said. "The bottlenecks to the future everybody wants will be the areas of high DER penetrations on the existing distribution system."

DER can be a valuable source of flexibility now, but there is a "false narrative" that DER can make it unnecessary to do "significant physical upgrades," he said. "The real value from distributed resources is the energy and capacity value on the supply side," but that will require better wires and poles along with new control technologies and better planning to realize that value.

Customer demand will make energy supplied by DER "much more than a marginal contribution," but using it "will require thinking about the distribution system in a different way," De Martini said. Paired with utility-owned or customer-owned storage, it can be "a firm resource that can be scheduled and used as supply, it can be shaped and compensated and lead into a new realm of DER value in which it is much more than a load modifier."

SCE’s paper articulates the need for investments in advanced information, operations, communications and control technologies in the near, mid and long terms, he said. There will also be a need for investment in physical infrastructure, and for planning that recognizes "how much DER will grow and preparation to unlock its potential."

"The progress of DER is unlikely to slow in 2021 or after because customers will continue to want them," De Martini said. "There is likely to be exponential growth as innovation makes these technologies more cost competitive and capable, and that means power system planners must be ready to use thinking like the ideas in SCE’s paper to enable these technologies."

The U.S. electric sector’s transition to cleaner generation has been led by states for the past four years, but 2021 is poised to offer stronger actions from the federal level. Under President-elect Joe Biden and a Democrat-led Congress, which will likely lead to the proliferation of battery storage and lower-carbon natural gas generation, among other energy developments, experts say.

Groups that are heavily invested in natural gas, such as the Electric Power Supply Association, a merchant generation trade group, consider the resource to be a great investment in 2021. EPSA members are considering natural gas projects with lower emissions profiles in addition to other technologies such as lithium-ion battery storage.

By prioritizing pilots that prove out low emissions natural gas concepts, including  the natural gas sector is poised to secure continued investments and long-term contracts in the U.S., experts say.

Potential policy support for natural gas

Climate regulations have largely been dealt with on a state-by-state basis. The priorities of the Biden administration for a more unified decarbonization approach could result in a new design and operating standard for transitioning the energy system, according to Michael Rutkowski, senior vice president of research and technology development, at the not-for-profit energy research organization Gas Technology Institute (GTI).

For natural gas specifically, the Environmental Protection Agency could tighten restrictions on methane emissions, he said, which would lead to more research on lowering emissions for the fuel source.

Others in the natural gas sector are also hoping for stronger federal policy signals for restricting carbon dioxide emissions, specifically by setting a price on carbon. Without a transparent price on carbon, the utility sector has struggled to make larger investments in technology to reduce greenhouse gas emissions like carbon capture, according to utility experts.

Carbon capture advocates have made great strides in securing an investment tax credit for the capture, sequestration and utilization of carbon dioxide, but the process, which requires energy to run, can be prohibitively expensive for utilities to consider large-scale retrofits on coal or natural gas assets, according to GTI and others in the natural gas sector.

GTI has a wide portfolio of carbon capture technologies being scaled with demonstrations to reduce the cost of carbon capture, Rutkowski said.

As for a carbon price, EPSA sponsored a study published in October by Energy + Environmental Economics to quantify the regional emissions savings that would be gained through such a mechanism in the PJM Interconnection’s wholesale market. EPSA is supportive of a "price on carbon as an economically rational way for us to achieve a market-based mechanism that will allow emissions reductions to occur while allowing [merchant generators] to compete, and minimizing the cost to customers," Todd Snitchler, CEO and president, said.

A Biden administration and Democrat-controlled Congress could advance policies on carbon pricing and create other necessary incentives for decarbonizing the sector, according to EPSA.

Stronger climate regulations could push the energy sector to rethink the existing gas infrastructure, environmental advocates say.

"We have these rapid responding turbines that are on the system, is there a way to decarbonize those generators, but to keep the infrastructure online?" said Michael Colvin, director of the Environmental Defense Fund's (EDF) California Energy Program.

EDF, along with clean energy companies, have shared forecasts of a decarbonized grid where natural gas peakers continue to have a role, specifically in regions impacted by cold snaps and periods of cloudy days during the winter.

Those geographic parameters have prompted research for "a more cost effective option to help cover the times when solar-plus-short-duration-batteries are not the appropriate option," Colvin said. "That is going to be part of the long term conversation of how do we use that gas pipeline network and the existing generators that are out there. Is there a way to decarbonize the pipe or decarbonize the process?"

The natural gas system has "great potential" as existing infrastructure that can be adapted, according to Rutkowski.

In addition, more recent efforts to introduce hydrogen blending in natural gas infrastructure can benefit from the natural gas industry's experience with renewable natural gas or biomethane, and working with regulators, said Kristine Wiley, executive director of GTI’s Hydrogen Technology Center.

"We're trying to advance the technology to find ways to make it cleaner," Wiley said of blue hydrogen, the process of generating electricity by burning hydrogen that was converted from natural gas. Blue hydrogen programs being piloted by GTI with a number of utilities, such as Southern California Edison and Dominion Energy, remain in the early stages.

Burning a blend of natural gas and hydrogen will also require the development of new material and operations standards for low carbon fuels in existing infrastructure, as the standards are written largely for methane, Rutkowski said.

While the potential use of hydrogen in natural gas plants is in the initial stages, other alternative fuels are increasingly being piloted in the U.S. In January, developer Bakken Midstream Natural Gas advanced efforts to utilize ethane — that would otherwise be flared in liquid natural gas projects — as a fuel in North Dakota, building a new power plant expected in 2022.

Cheaper natural gas resources

Natural gas infrastructure investments remain viable considering the low prices. In the merchant generation space, natural gas is considered a strong investment, Snitchler said.

Electric utilities are also making investments in natural gas, including lower-emissions options. Southern Company's Alabama Power received regulatory approval in 2020 for a nearly 2 GW natural gas expansion, although enviornmental advocates are contesting the about $1.1 billion additions. The parent company has continued to invest in natural gas in the last five years, acquiring gas company AGL Resources for approximately $8 billion in 2016 and converting it to Southern Company Gas, according to a utility spokesperson.

Peaker gas capacity is expected to grow every year through 2050, outpacing globally the addition of combined cycle generation turbines in 2029, Bloomberg New Energy Finance (BNEF) concluded in December in its New Energy Outlook 2020. The growth of peaking capacity is impacted by the large amounts of intermittent energy being put on the system.

Changing prices for natural gas will also impact the extent of its use.

According to the Energy Information Administration (EIA), while natural gas prices were low last year, natural gas production also fell. Now, the federal analysis shows rising natural gas prices through 2022, which could prompt more fuel switching between natural gas and coal, and could give the resource "more competition from renewable generation sources from expected renewable capacity additions in 2021."

The low cost of natural gas makes the fuel attractive in the long term, prompting BNEF to model "at what point [would] cheap gas actually become a barrier to decarbonization" on a deeper level, Seb Henbest, BNEF's chief economist and lead author of the New Energy Outlook, said at a webinar in December.

While coal is being replaced with natural gas over the next decade, the subsequent 10 or 20 years show a "counterintuitive" addition of natural gas, based on the existing decarbonization goals in the U.S., but a higher gas price would hasten decarbonization efforts, according to BNEF's modeling. 

2 states leverage batteries and natural gas assets

States with aggressive decarbonization goals and reliability concerns are likely to consider more aggressive pathways for lower emissions natural gas, experts say. New York and California are viewed as key markets to watch regarding reliability trends.

New York issued a battery storage procurement goal for utilities and is working on securing a power supply during winter cold snaps while adding a large amount of offshore wind and other renewables to the energy mix. California is working on its own decarbonization goals and state regulators opened a proceeding to direct how much energy storage utilities and community choice aggregators would be responsible for contracting to ensure reliability.

California had a large gas buildout following its 2000-2001 energy crisis, but the state has shifted, based on its decarbonization goals, to make more investments in energy storage, and replace older plants with short duration batteries, as with the decommissioning of Moss Landing.

"I don’t think you’re ever going to see California approve a new, large natural gas-fired power plant. I think those days are behind us," said Colvin, who has over a decade of experience at the California Public Utilities Commission.

In 2021-2022, he believes more changes will be made to the energy sector to address summer reliability concerns in the state with clean energy resources.

"The old school way of thinking of ensuring reliability was to keep fossil [fuel] around," Colvin said. The solutions to achieve environmental and reliability goals can include lower emissions retrofits or a combination of longer duration energy storage technology.

Facing reliability issues in the winter, New York is also working to ensure the lights stay on as the state adds more intermittent renewable energy capacity. To meet the state's climate goals, utilities are required to transition from natural gas to low emissions technologies without risking system reliability.

Consolidated Edison and the New York Power Authority (NYPA) are two of the 18 companies across the country partnering with GTI and the Electric Power Research Institute on its Low Carbon Resources Initiative (LCRI) working on increasing a hydrogen blend in natural gas.

Additionally, NYPA is planning to install and demonstrate short duration storage in tandem with gas peaker plants at six sites, as a way to address capacity shortages in the New York City area, according to utility president and CEO Gil Quiniones.

"When long-duration storage becomes available, we also want to be the first one ... and pilot that," he said. "Who knows? A long-duration storage [system] may completely replace a peaker plant because our peaker plants run on the average of 10% of the year in terms of run-hours."

Electric vehicles are growing in popularity, and utilities are preparing for a future where their value goes far beyond transportation.

As more EVs hit the road, there are growing questions about how utilities will manage their charging needs. Rocky Mountain Institute (RMI) has estimated that electrifying all of the roughly 251 million light duty vehicles on U.S roads today would increase annual electricity demand by about 25% — and that doesn't include medium and heavy-duty applications like freight and public transit along with a host of other applications.

While the transition to a fully electric fleet could take decades to achieve, the near-term implications for grid management as more and more EVs hit the road are significant.

Along with adding demand, EVs are increasingly seen as potential grid assets: aligning their charging needs with times of higher renewables production and lower grid stress can help decarbonize transportation and operate electric systems more efficiently. Managed charging, through time-of-use rates and demand response programs, is known as vehicle-grid integration and is already the subject of utility programs around the country.

This approach to managing EV demand — largely reliant on unidirectional power flows that adjust how and when chargers are pulling energy from the grid — is sometimes referred to as level 1 integration (V1G). But there is also interest in using the energy in EV batteries to serve other loads, with what are known as vehicle-to-grid (V2G) capabilities.

While those capabilities are utilized in parts of Europe and Asia, experts say the United States is still years away from widespread use of V2G. There are a few utilities rolling out pilot programs to test the capabilities, including Duke Energy in North Carolina, but there are still safety and engineering concerns to be addressed, technical problems to solve and business cases to study.

"It can be pretty complicated to make it all work. I’ve read hundreds of technical papers on these topics and I just don’t think the value proposition of V2G is at all clear," said Chris Nelder, a manager with RMI's mobility practice. 

That said, there is a growing consensus that millions of vehicle batteries will one day serve as energy resources beyond V1G managed charging, to power buildings and microgrids and feed energy back into the bulk power system.

Bidirectional charging "can accelerate the adoption of EVs and accelerate renewables," said David Slutzky, Fermata Energy CEO and founder. "That's where we're headed, and we're moving quickly."  

Unlocking value streams and use cases

Fermata is a key player in this space. Last year, the company's bidirectional charging system was the first to become certified to a new Underwriters Laboratories (UL) North American safety standard, UL 9741, the Standard for Bidirectional Electric Vehicle Charging System Equipment. 

This makes the system the first commercially-available charger to meet the North American standard for bidirectional EV chargers. According to Slutzky, this is a tipping point for the technology in the United States and will allow utilities to begin experimenting with bidirectional programs and the values they can bring to the grid and to customers.

"An internal combustion vehicle has one value: It drives people around," said Slutzky. "EVs are different. There are many value streams which can benefit third parties and customers. What V2G does is liberate those value streams."

Those values could include resiliency, demand charge management, Volt/VAR optimization, frequency regulation and others. Fermata's chargers, just a couple dozen at first, began shipping to pilot partners last fall following pandemic-related production delays.

For bidirectional charging, Fermata's UL safety certification is a watershed moment, according to Holmes Hummel, founder of Clean Energy Works, a nonprofit focused on accelerating financing for the sector. "This is the beginning of its edge catching," said Hummel. 

"We have known of the technological potential [of V2G] for a decade," said Hummel. "But it wasn't until last month the partners we work with could place an order, install it and have it working that afternoon."

The business cases for bidirectional charging are likely to begin by connecting them with buildings (V2B) rather than the broader grid, said Nelder, due to the complexities involved.

"Before V2G really becomes a commercial reality, I expect various kinds of V2B solutions, where vehicles can be used as backup batteries for buildings," he said. "But that also entails a lot of technical issues."

According to Slutzky, after the technical issues are addressed, the potential value of bidirectional charging is significant. A Nissan LEAF connected to a 25 kW bidirectional charger could help some commercial customers significantly lower demand charges. If the vehicle was used two to three times a month to reduce demand charges of $30/kWh — a high figure, but not unheard of, he said — that could create savings of $9,000 annually, per vehicle.

"That's a free car and a free charger in a few years," said Slutzky. "It's that disruptive."

"Most people have narrowed their views of V2G to just peak demand management," said Hummel, but that likely understates their potential significantly.

A June 2020 report from a California joint-agency work group on vehicle-grid integration gives a look at the extent of the opportunity and quantifies the potential benefit.

The report, issued by the California Public Utilities Commission (CPUC), found 320 different integration use cases that "should be considered as able to provide value by 2022," and included dozens of V2G applications covering resiliency and peak load reduction applications with some delivering thousands of dollars in annual value per vehicle.

But according to Nelder, most of the value in vehicle-grid integration is in managed charging and not V2G applications.

"We have looked at the value stack of vehicle-grid integration and we think the vast majority of it is in managing charging to provide grid services, and not actually supplying energy from vehicles back to a building or to the grid," he said.

Pilots using Fermata's charger

Roanoke Electric Cooperative has acquired one of the Fermata charging systems, and partnered with Clean Energy Works to test multiple business cases for bidirectional charging with a single Nissan LEAF. 

"The value proposition today is still relatively narrow, compared to what we see in the future," said Hummel. While Roanoke will begin with one vehicle, Hummel said the utility expects the first 10,000 EVs in its service territory will log 100 million miles a year— while still being parked 90% of the time.

"We're looking at a number of use cases, and ways this could be expanded," said Roanoke CEO Curtis Wynn, who is also president of the board of the National Rural Electric Cooperative Association.

Roanoke's pilot is underway, and Wynn said the two immediate use cases the utility will consider are to reduce demand charges for commercial accounts and to allow residential customers to sell power back to the utility when the grid is stressed. There may also be "opportunities for resiliency, in the event we have an outage," said Wynn.

The pilot has no specific end-date, but Wynn said he expects it to run at least a year while the utility looks for new use cases to test.

"Fundamentally, what we'd like to see on a larger scale is how this might play out with the utilization of school buses and larger vehicles that could support the same thing, resiliency," said Wynn.

Fermata has also sent a bidirectional charger to the City of Denver, where it will be used in a small pilot at The Alliance Center, a nonprofit event and collaborative working space. Fermata has an agreement with Nissan to test these applications using the LEAF, but Slutzky said there is a non-disclosure agreement in place that prevents him from giving details.

And before its new charger was developed, the company was experimenting with providing services in wholesale markets.

In 2016, Fermata connected four Nissan LEAF EVs paired with 30 kW bidirectional chargers in three different locations, and used them to participate in the PJM Frequency Regulation market. Fermata is a curtailment services provider in the PJM through a special arrangement with the grid operator.

"The vehicles were used as fleet vehicles during the day, and in the evenings we'd bid into the frequency regulation markets," said Slutzky. "We aggregated those four vehicles and were about 97% responsive to PJM's signals."

School buses may be first at-scale use for V2G 

The idea of using an electric vehicle to power a residence is attractive, but experts say this is unlikely to be the first area where V2G capabilities take hold. More likely are school buses, which have much larger batteries and sit idle for long stretches.

"I don't think the residential applications will be the first" to be widely commercialized, said Hummel. Finding more value in electrified passenger vehicles is "obviously of value to extend the value proposition for residential communities ... But we may even sooner see that value proposition developed through the electric school bus market."

It only takes five electric school buses to provide about 1 MWh of onboard storage, according to Hummel. And the duty cycle for a bus is low — operating only a few hours a day, and often sitting idle for the summer months.

Duke Energy recently got approval for a small electrified school bus pilot in North Carolina that will include studying V2G potential. The program will start small, with 30 buses between the Duke Energy Progress and Duke Energy Carolinas territories. 

The pilot, is "designed as a proof of concept for these vehicles," said Lang Reynolds, Duke Energy's director of electrification strategy. "There's been a lot of hype and excitement around school buses and V2G. Even though we know the technology works, we need to learn more about how it works in practice."

Duke does not plan to do any bidirectional dispatch with the buses in the first year or two of the pilot, said Reynolds, and will instead study their charging needs. "We're going to be very deliberate about this process and come into it with a long period of time where we're not doing anything to impact normal operations. ... And when we do start testing bidirectional capabilities, we're just testing it, ensuring we can dispatch it at the power levels claimed by bus manufacturers and chargers."

But that will shift, eventually. "There are a lot of potential future use cases we're interested in," said Reynolds, including demand charge management for customers and backup power for resilience.

Reynolds said the school buses Duke has been looking at have about 50 kW to 100 kW of potential bidirectional power capacity, and can carry about 100 to 150 kWh of energy per bus.

"There are different configurations possible, and we're still reviewing offerings," he said. Duke's pilot would also allow the utility to keep the batteries after they have exceeded their useful life in buses, and to repurpose them as stationary storage.

There are tens of thousands of buses in Duke's service territory, said Reynolds. "If they were all electric, that's a significant resource. The real question is how that translates into a real world scenario ... we really have more questions than answers at this point, around V2G as a resource."

Funding the future, focusing on the present  

Funding for electric vehicle infrastructure has been a sticking point to date, but experts say there has been recent progress. President-elect Joe Biden included emissions-free transportation initiatives in his platform and has called for the government to support installing a half million chargers. And at the state level, there has been significant movement in the last year, said Katherine Stainken, senior policy director for Plug in America.

In December, the CPUC approved several measures to accelerate EV and infrastructure deployment, including more than $100 million to fund studies on and demonstrations of vehicle-grid integration. In addition, Congress authorized the U.S. Department of Energy to conduct a larger effort on vehicle-grid integration in the end-of-year stimulus law. Within both the California and federal initiatives are efforts aimed at bidirectional charging, said Stainken.

But while there is potential for V2G, Stainken said the group also worries that it is a "flashy term" with the potential to distract policymakers.

"We don't want policy makers to get so caught up with V2G that they don't move forward with other aggressive policies," she said. The near-term future for efficiently integrating EVs remains self-managed charging on one-way network charging, though the technology is evolving quickly. "We need to continue to focus on keeping costs for drivers low, whether that be V1G or V2G."

"This will be the breakthrough year, when data is compiled and released," Stainken said of utility pilots focused on integrating EVs into the electric grid.

The hydrogen industry has seen a significant acceleration of activity recently, with new projects, pilot studies and commercial partnerships. It has been the subject of significant attention before. This time, the hype may be warranted, analysts say, and 2021 is likely to see even more activity.

December, in particular, was "extremely busy for us," said Vinayaka Nakul Prasad, corporate strategy manager for Siemens Energy. In one month, the company launched four projects tied to Siemens Energy's electrolysis or hydrogen gas turbine businesses, dispersed across three continents. But Prasad expects even more to come in 2021.

In the coming hydrogen economy envisioned by Siemens Energy and, increasingly, other large energy industry players, Prasad doesn't see Siemens Energy's role as limited to being a manufacturer of turbines and other generation equipment. Rather, he says the company is working on solutions for use across the hydrogen value chain, from production to storage and production. And he sees a pressing need for these technologies around the globe.

Interest in hydrogen is mainly centered in two regions, according to Massimo Schiavo, a director for S&P Global Ratings — China and the European Union. China's interest, Schiavo said, stems from the country's desire to dominate global energy and technology markets. In the EU, government policy has taken center stage thanks to the EU Hydrogen Strategy, which was released last July and calls for the installation of 6 gigawatts of renewable hydrogen electrolyzers by the end of 2024, and at least 40 gigawatts by 2030.

The U.S., Schiavo believes, will be the next major player to enter the hydrogen race, and he anticipates the U.S. could release its own national hydrogen strategy sometime in 2021. Parts of the U.S., particularly in the West, have taken steps down this path, and companies from small energy startups to the world's legacy oil and gas leaders are gearing up for policy and societal changes they anticipate could generate unprecedented demand for hydrogen.

This is not the first time the world has seen industry hype for hydrogen. But this time, the need for hydrogen is no longer theoretical, according to Janet Howard, a partner at Canadian law firm Fasken. Achieving economy-wide decarbonization will require carbon-free solutions in sectors where electrification alone seems unlikely to fit the bill. The question, many now believe, is not whether the world will transition to a grid powered by a combination of renewable energy and hydrogen-based fuels. The question is how soon will the needed hydrogen become available — and how should we best use scarce supplies in the interim.

Hydrogen hype

During the last round of excitement for hydrogen, which peaked in the 2000s with President George W. Bush committing $1.2 billion to hydrogen fuel research, the enthusiasm largely centered on hydrogen-powered cars. But making transportation the focal point, Howard said, may have been part of the reason why interest eventually waned.

"The focus on transportation as a sector might have been something the market wasn't ready for, in the early days," Howard said. "There are other applications for hydrogen where there is a more natural fit."

Today, hydrogen has been reduced to a niche, according to Schiavo. "It represents just 2% of global energy consumption — it's nothing." But he, Howard and other experts expect that reality could change rapidly in the years to come.

The hype building today, Howard said, is less driven by ideology or policy — instead, she said, there is real-world demand building for hydrogen amid heavy industrial sectors that lack practical solutions for decarbonization amid growing environmental demands from customers, governments and financial players.

"There's much more focus from institutional investors, on the importance of making sure the companies that are funded are going to be sustainable long-term. There's a realization that if the companies they're invested in don't change, they will no longer be profitable," Howard said. "There wasn't that same pressure" in the 2000s.

Howard, who helped to found a hydrogen-focused advisory group at Fasken at the end of 2020, said her new hydrogen clients are a mix of entrepreneurs and institutions — legacy oil and gas companies, utilities, financiers and banks. But a large part of her clientele, she said, also comes from heavy industries such as mining, construction and agribusiness, which need hydrogen as a source of fuel to transition away from diesel.

This pressure is felt keenly in industries where efforts to reduce carbon emissions have to date remained "very modest" in the absence of viable solutions, according to Prasad, who said Siemens Energy is working with a steel plant in Austria to replace carbon with green hydrogen in its steelmaking process

Hydrogen also presents a solution for utilities faced with a need for seasonal energy storage. Pumped hydro may be the preferred means of long-term storage, Schiavo said, but it's simply not available in drier climates.

It's not just demand that may have the stars aligning for hydrogen, according to Nick Heymann, co-group head–global industrial infrastructure with financial services firm William Blair. The rapid decline in the cost of renewable energy over the last decade, and the likelihood that prices will continue to fall, means that one of the key inputs for so-called 'green' hydrogen production — renewable electricity — is finally coming within an affordable range. In some regions, he added, renewable power generation has begun to outstrip the world's ability to manufacture batteries to store it.

"We now have this surging supply of power, more ultra-low cost power than batteries can store," he said. "Suddenly, we don't have enough lithium, we don't have enough gigafactories, so instead of thinking of hydrogen as a downstream petrochemical feedstock, now it's suddenly a way to store energy."

There's also a growing sense, Howard said, that companies need to move quickly to get ahead of a coming wave of government policy that may penalize them for making insufficient progress toward decreasing carbon emissions. Members of the incoming Biden administration have indicated that tariffs or taxes on high-emission industries, such as steel or aluminum, could be on the table.

Entering the race

The need for carbon-free alternatives in sectors that are difficult to electrify, coupled with limitations on battery capacity, has begun the race for global dominance in international hydrogen markets, Heymann said. The main contenders? Currently the EU and China.

The European Union is already on track to exceed its hydrogen generation goals, established mere months ago, with plans for 20 gigawatts of hydrogen generation in place across five countries, Schiavo said. China's plans are somewhat less known to the international community, but the country is believed to be the world's current leader in hydrogen production.

"In the EU, they are totally committed to being the greenest place on the planet," Heymann said. "China is more interested in becoming the biggest economy.... I think in China's case, they see this as the technology that has legs for 30-50 years."

Schiavo believes the U.S., under the Biden administration, will move to close the gap by introducing its own strategy on hydrogen production in 2021. Or, if not during the current year, then at least within the next two to three years, he said, though recently most nations seem to be inclined toward fast-tracking hydrogen production.

"Personally, I was not expecting the EU to launch such an ambitious program in 2020," he said. "So I would not be surprised to see in 2021, that the U.S. has started to work on something, if not put something out, that is very ambitious."

Even if the U.S. doesn't create a hydrogen strategy at a national scale, efforts are underway at the state level, according to Laura Nelson, executive director of the Green Hydrogen Coalition. In December, California lawmakers introduced a bill mandating the study of hydrogen's role in the state's vision for a clean energy economy. Other state lawmakers have discussed pursuing similar legislation in 2021, Nelson said.

At the broader level, Nelson said, 11 U.S. states and two Canadian provinces recently formed the Western Green Hydrogen Initiative, which will begin meeting in March to discuss how to build momentum and infrastructure supporting the deployment of green hydrogen in the region.

The ongoing pandemic and current political push for infrastructure spending to spur economic recovery also seems poised to channel government funds to hydrogen, according to Mona Dajani, head of the hydrogen and renewable energy practices at the law firm Pillsbury Winthrop Shaw Pittman.

Based on her communications with individuals within the Biden administration, Dajani said she believes that "COVID recovery packages will be linked to energy transition packages, and those companies like oil and gas companies and utilities that are headed toward sustainability will reap significant rewards."

With industry and government now both on board for hydrogen, Dajani said, one question remains to be answered: when will the world's ability to produce hydrogen catch up to demand?

The scaling challenge

Dajani said she is aware of several large-scale hydrogen projects in the works, but not yet announced, causing her to believe the production of hydrogen could scale quickly in the coming years.

"I have a much shorter time horizon [for the growth of hydrogen production] than what I'm seeing reported," she said, "and maybe that's because you're not seeing what I'm seeing. I'm seeing major changes now... I definitely think more major stuff will start happening" in 2021.

But Heymann is slightly less optimistic, and alongside other industry analysts envisions a longer timeline to maturity for hydrogen. Even with strong government support, he said, hydrogen must still overcome two key challenges that are linked: affordability and scale.

The solution to the affordability problem, according to Schiavo, will likely come along once hydrogen electrolysis achieves the needed scale — which Schiavo and others believe will happen when individual electrolyzer units, called stacks, become sufficiently efficient to process one gigawatt of electrolysis per year.

Currently, the electrolyzers in service around the world sit at what Schiavo characterized as "pilot scale" or tens of megawatts per stack. He said he expects technology will enable stacks in the range of hundreds of megawatts each by 2025, and eventually move to even larger units.

"I'm not saying it's not possible," he said. "I'm just saying, it will probably take at least until the next decade."

Heymann agrees — the needed technologies for efficient and economical hydrogen production are on the horizon, but they aren't quite ready yet. "Remember, the electrolyzer technology is about 15-20 years behind the commercialization and reduction in cost in first solar and now wind," he said.

But electrolysis is also following a similar trend as other renewable technologies, with electrolyzer output increasing roughly ten times every four years, according to Heymann.

"In 2015, an electrolyzer produced one megawatt of power," he said. "In 2018, it was 10 megawatts, and by 2022, there is one under construction that is supposed to generate a hundred megawatts. Sometime later this decade, a gigawatt is expected."

As that level is achieved, economies of scale will bring hydrogen supplies in line with demand and allow prices to drop as the industry observed with wind and solar, Dajani said. That, in turn, could open up even more uses of hydrogen outside of niches that are currently limited to the resource out of necessity.

To achieve this vision, Schiavo said, will also require a rapid increase in the availability of renewable energy the likes of which just isn't possible on a short time scale. Even if the U.S. made a massive investment in renewable energy today, he said, it would still take 2-3 years to deploy sufficient renewables to fuel hydrogen production in a cost-efficient manner.

Transition strategy

The need for increased renewable energy generation, coupled with challenges with respect to storage and transportation of hydrogen, means making the leap directly to green hydrogen from fossil fuels is likely impossible, Heymann said.

This reality has many industry leaders considering intermediate steps that could enable economies to build out hydrogen infrastructure while waiting for the actual green hydrogen itself to achieve scale.

Unlike green hydrogen production, which uses electricity from renewable sources to split water into its chemical components — hydrogen and oxygen — gray hydrogen is derived directly from fossil fuels, typically by splitting natural gas into its own chemical components, carbon and hydrogen. Blue hydrogen is derived from fossil fuels in a similar fashion as gray, but paired with sequestration to capture the carbon emissions this form of hydrogen production generates.

Both gray and blue hydrogen are currently cheaper to produce than green hydrogen, so some countries, including China, are using gray hydrogen to prompt the development of hydrogen-compatible infrastructure, according to Schiavo. The line of thinking is that this approach will enable the development of pipelines and other infrastructure compatible with hydrogen, so that when green hydrogen does become more widely available, China will be ready for widespread distribution. But in environmentally-minded regions such as the EU, gray and blue hydrogen lack social acceptance.

Some see a third opportunity to build out hydrogen infrastructure and make scarce supplies go further — blending green hydrogen with natural gas. Hydrogen blending is thought to come with the advantage of decreasing transition costs by making use of existing infrastructure, because so long as the hydrogen inclusion remains low, the blend can be added to pipelines and burned in natural gas turbines. This transition strategy has gained steam particularly in the U.S. and Canada, where access to natural gas means hydrogen could struggle to compete on the basis of cost for years to come. And proponents of blending argue it keeps costs low and enables a gradual replacement of gas infrastructure as hydrogen inclusion rates increase.

"Natural gas is a quick way to start down the path," Howard said, "so hopefully people get comfortable with that."

Some environmental groups are, however, decidedly not comfortable with gas-hydrogen blending.

"One of the questions, with hydrogen combustion in gas plants, is whether this is a plan or a ploy. That is a pressing question," said Lewis Milford, president of the Clean Energy Group, a nonprofit advocacy organization. "Are these proposals to blend hydrogen in gas plants serious operations, or are they a way to preserve at-risk stranded assets?"

Milford points out that while green hydrogen may be carbon-free, it isn't necessarily emissions-free. The high temperature of hydrogen combustion can trigger nitrogen fixation and produce NOx. When hydrogen is blended with natural gas, the high flame temperature may actually increase NOx emissions, according to Milford. Additionally, he says, the blends don't result in a complete reduction of carbon emissions, and the gas plants where this blending would take place are often located near communities of color that already face disproportionate environmental burdens.

"This is of obvious concern," Milford said. "The last thing we should be doing is experimenting with new forms of pollution combustion in cities where" disadvantaged populations will be affected.

Milford said he believes gas-hydrogen blending proposals should not receive government permits until the potential environmental impacts are fully understood, and technology for mitigating the NOx emissions from hydrogen becomes available.

Prasad doesn't deny that burning hydrogen comes with additional NOx emissions. "Of course there's a NOx concern," he said, adding that SiemensEnergy is working on efficient combustor designs and other technologies to control these emissions. He also acknowledged that hydrogen blending with gas does not result in a 1-1 carbon reduction. Rather, a 60% hydrogen inclusion will reduce carbon emissions by about 30%, he said.

These questions about the best way to utilize, and transition to, hydrogen remain unanswered, and specifics aren't likely to emerge by the end of 2021, Heymann said. But at a higher level, he said, the future of hydrogen no longer seems speculative.

"We're no longer out in the desert, wondering which way to walk," Heymann said. "I don't think we're in that environment today. There's a very clearly delineated path.... The question is, are you positioned to benefit from this change, or are you going to get run over by it?"