Coal, solar and EVs: A pitfall for electric utilities?

By Kristi E. Swartz

E&E News, Jul 15, 2022


For many companies, the ongoing shift to clean energy presents a massive financial opportunity.


But for U.S. electric utilities, the transition may upend a longstanding business model.


That’s because utilities have traditionally made money by investing in new assets, from power plants to power lines. Consumers pay for those investments through monthly bills and expect reliable service in return. Utilities, with the approval of regulators, lock in rates of return and paths to hitting financial targets for Wall Street.


As the electricity mix has evolved, though, resources like rooftop solar and electric vehicles haven’t fit into that model — at least not in the traditional sense. Now, companies are facing a potential financial gap compared with past expectations. Some are trying to address that by proposing that utility customers pay for technologies like public EV chargers, a development that could be a financial opportunity for companies, but also one that is spurring resistance.


The clash is coming to a head after last month’s Supreme Court ruling, West Virginia v. EPA, which hamstrung the federal government in regulating greenhouse gases. Government leaders and climate advocates are leaning on utilities to lead the way in cutting greenhouse gas emissions and move toward a cleaner generation mix. President Joe Biden has proposed a decarbonized U.S. power sector by 2035, while a number of states have their own carbon-cutting goals for electricity and beyond.


But if utilities feel like they can’t make money off of many of the technologies to achieve decarbonization, will they make the effort to fully shift away from fossil fuels?


In many ways, the Southeast is ground zero for this emerging battle. It’s home to some of the biggest U.S. utility companies, which have enormous political and business clout. States and companies must decide how quickly to shut down coal plants and how much extra capacity should remain on the grid as extreme weather threatens reliability.


“Given the political leanings of [the Southeast region], I highly suspect that the utilities are going to win the day,” said Josh Basseches, a postdoctoral fellow at the University of Michigan’s Gerald R. Ford School of Public Policy.


Indeed, while Congress continues to negotiate some form of climate legislation absent of Biden’s signature “Build Back Better” proposal, having states and electric companies carry out their own net-zero policies becomes ever more important.


Electric companies and states like it that way: being in charge of their own energy destiny and letting the market — not Washington — drive those policies. But it’s also a chief reason why the Southeast continues to fall behind in the clean energy transition, experts say.


“In general, the Southeast is the area of the country that’s lagging when it comes to climate and energy policy,” Basseches said.


Disagreements among state lawmakers and utility regulators also have, in some cases, led to stalled clean energy legislation in the region.


The shifting energy mix is raising financial questions that utilities — and their regulators — will need to solve in the coming years.


EV chargers


The Southeast is fast becoming a hub for electric transportation, with a host of battery makers and auto manufacturers choosing the region to start up or expand. Utilities have been banking on the sector to contribute significantly to future revenue and profits.


The bulk of that money is in the chargers, and electric companies have been adding publicly available charging infrastructure to long-term energy plans and rate requests. That means all customers would pay for the chargers whether they drive an EV or not.


“The charging infrastructure is nothing more than a fancy plug; we ought to be able to include it with our [capital expenditure] plans,” said Tom Fanning, CEO of Southern Co., which operates electric companies in Alabama, Georgia and Mississippi, at the company’s annual meeting in May.


Not all lawmakers agree, arguing that letting electric companies embed those costs in monthly power bills gives them an economic leg up against private charging companies, gasoline stations and convenience stores, which don’t have the ready-made customer base of millions of people to pay for that infrastructure.


If there’s not a strong business case for EV chargers, gas stations and convenience stores won’t install them, their lobbyists have said. That would slow the transportation shift that so many electric companies have wanted.


“Southern has been talking about this for the better part of a decade as a business opportunity,” said Daniel Matisoff, director of the sustainable energy and environmental management master’s program at Georgia Tech. “The only way they can make more money is to sell more electricity.”


Georgia, Florida and Louisiana have discussed legislation to shape EV charging infrastructure this year. Lawmakers have called for a competitive marketplace, arguing that’s the best way to build out a charging network quickly.


That, and they don’t want the utilities to be in the charging business.


“We’re not going to allow the monopoly; we’re not going to allow the utilities to use their rate base to subsidize the EV business,” said Georgia state Rep. Alan Powell, a Republican from Hart County in northeast Georgia.


The Feb. 22 EV subcommittee meeting, part of the Georgia House Committee on Energy, Utilities and Telecommunications, was one of a series of debates over how to best set up a framework and rate structure that would help allow gasoline stations, electric companies and private EV charging companies install chargers.


In a battle that is playing out across the country, however, gas stations — and some lawmakers — don’t want the electric companies to be able to recoup the cost of those EV chargers from all of their customers, arguing that gives them a financially competitive advantage.


Those bills stalled in Georgia and in Florida. In Louisiana, S.B. 460, which sets up a framework to build out EV charging infrastructure statewide, was signed by Gov. John Bel Edwards (D) on June 18.


“We’re trying to … get us to a place where the gas stations that you see up and down the highway have a road map, so to speak, to move forward to make those investments,” state Sen. Rick Ward, a Republican and the bill’s sponsor, during an April 27 meeting of the Committee on Commerce, Consumer Protection and International Affairs, which he chaired. Ward resigned from the Legislature in June to take a job in the public relations sector, according to a media report.


Eva Rigamonti, associate general counsel for RaceTrac Inc., said a chief barrier to convenience stores installing EV chargers is the rates electric companies charge them for doing so.


“This unambiguously stifles investment,” she testified at that April meeting.


Entergy Louisiana LLC executives, including its CEO, met with Rigamonti and others the previous day to say they would not stand in the way of anyone that wants to build fast chargers, said Jody Montelaro, the electric company’s public affairs vice president.


“What we are charged with is to make sure that the infrastructure is in place, for anyone. That’s going to be a big deal,” Montelaro said at the meeting. “EV is a totally different type of system because you are using our grid.”


Solar credits


As more customers want cleaner energy options or to generate their own electricity, a battle over how much they should get paid for selling excess electricity to the grid is reemerging. Known as net metering, the system credits customers with rooftop solar who generate more power than they can use and sell it back to the electric company.


Some electric companies oppose paying customers what’s known as a retail rate, saying that amount is too high. This is because utilities argue that customers without solar panels are subsidizing those who have them. The state’s electric companies still must be able to provide traditional electricity for solar panel owners when they need it.


That has turned rooftop solar policy, at times, into an issue of class. The panels are expensive, often preventing low-income residents from being able to buy them. What’s more, renters and people who live in multi-unit dwellings typically can’t use them because they don’t own their roofs.


That means the people who may need to reduce their monthly power bills may not be able to take the steps to do so.


“There’s a lot of emotion,” said William Boyd, a professor at UCLA’s School of Law and at the Institute of the Environment and Sustainability. “There’s a concern there to try and deal with those issues if they can.”


The issue was in the spotlight this year in Florida, where the state’s largest electric company has long threatened to slash the incentives that rooftop customers receive for selling excess electricity to the grid.


Many clean energy advocates weren’t surprised when a bill, largely penned by NextEra Energy Inc.’s Florida Power & Light Co., was filed in November 2021 for the 2022 legislative session. The measure moved quickly through both chambers despite dozens of people lining up in each committee to oppose it. The bill would have cut the amount of money rooftop solar users would receive for selling excess electricity back to the power grid. Then came Republican Gov. Ron DeSantis and his veto pen.


DeSantis said Floridians didn’t need more economic woes on top of inflation and the price hikes in fuel, groceries and other bills (Energywire, April 28). The governor indicated that he did not want to cut back on a financial incentive for consumers at a time when monthly bills, among other things, were rising.


Abigail Ross Hopper, CEO of the Solar Energy Industries Association, said in a statement following the governor’s April 27 veto that by vetoing the bill, DeSantis protected jobs, businesses and consumer choice.


“This veto signals that Florida’s energy economy is open for business, and that the rights of state residents should be placed ahead of monopoly utility interests,” Hopper said.


FPL is a top political donor to DeSantis and much of the GOP-controlled Legislature. His veto sent shockwaves through Florida’s energy and political landscape.


Alabama, Georgia and Mississippi are grappling with rooftop solar policies in front of regulators and, in one case, the courtroom. The issue is about control of the power grid, experts say.


“Every time someone puts a solar panel array on their rooftop, they now own a small piece of that grid,” said Basseches, the University of Michigan fellow.


Coal retirements


As power companies propose ways to make money off new investments, they also seek to profit off their old ones. That can put a strain on both consumers and utilities, which want to be made whole as they transition away from coal while having certainty on when to make the shift.


That is playing out as many of the region’s electric companies have set net-zero carbon goals and proposed closing the last of their aging coal plants by 2035, making natural gas their replacement fuel of choice for plants that can run on demand. Some state regulators want utilities to rethink those plans, however, arguing that extreme weather events in places like Louisiana and Texas have led to widespread blackouts and that those old coal plants may be needed to keep the lights on.


What’s more, the longer the coal plants run, the more that delays building a new natural gas plant, a move that fits in with the industry’s age-old capital-intensive business model.


“It’s a big, looming issue for sure,” said UCLA’s Boyd.


Roughly 38 percent of the nation’s electricity last year came from natural gas, according to the U.S. Energy Information Administration. The eventual question is whether electric companies can recover the cost of stranded natural gas assets, especially after doing so with coal plants, Boyd said.


“I think the gas build-out question is hard,” he said in an interview. “Are there going to be stranded assets in 10 to 15 years if we do make a big push on carbon?”


South Carolina utility regulators took the unusual step last year of rejecting Duke Energy Corp.’s long-term electricity plans, saying the utility company wasn’t moving away from fossil fuels quickly enough in favor of solar and battery storage (Energywire, June 22, 2021).


But the Public Service Commission this year directed Duke to keep the last of its coal plants running longer, into the 2030s. For this and other reasons, Duke asked for a rehearing, which the PSC denied.


In its request, Duke argued that keeping older, emissions-intensive power plants running is an economic risk. Aside from the power plant’s reliability, coal markets have become increasingly volatile, and the number of coal suppliers is dwindling, the company said.


Electric companies also must start choosing future forms of generation now as the nation shifts to cleaner sources of electricity.


“The companies, along with other peer utilities in the Southeast and across the country, are engaging in a significant and transformative period of energy transition,” attorneys for Charlotte, N.C.-based Duke Energy Corp., wrote in its filing on May 13.


In an email, Duke spokesperson Erin Culbert said the company is “disappointed with the commission mandating the least proactive path for moving away from coal generation, because it carries unnecessary risks for customers and our system.”


South Carolina utility regulators declined to comment, saying they would explain their decision in an upcoming order.


The PSC’s decision also puts Duke at a crossroads in the two main states where it operates: North Carolina and South Carolina.


North Carolina now has a mandate to become net zero by 2050, and Duke is required to cut its carbon emissions 70 percent by 2030 from 2005 levels. That includes closing roughly 9,000 megawatts of coal plants in the Carolinas.


In Georgia, the state’s largest electric company wanted to close its remaining coal plants by 2028, according to its long-term energy plan that regulators are scheduled to vote on July 21.


But members of the Georgia Public Service Commission staff argued recently that Georgia Power can put off making that decision until 2025 for three of those individual units.


The absence of federal carbon legislation is a chief reason, according to economic analysts with the PSC staff. They also want Georgia Power to use a competitive bidding process for replacement generation instead of simply turning to natural gas.


Southern signaled a year ago the end of its coal plants was near, citing a Trump administration-era rule for water and wastewater. At a recent hearing, clean energy advocates asked the Georgia PSC staff whether they weighed the cost of environmental upgrades.


Utility Finance Director Tom Newsome with the Georgia PSC answered affirmatively and cautioned against racking up a bunch of hypothetical costs based on other regulations that didn’t exist.


“Then we retire these units prematurely, and you open the door for Georgia Power to come in an do a new build,” he said, adding that building a new power plant costs more than a long-term agreement to buy electricity or keeping those coal units operating.


Members of the PSC staff and Georgia Power reached an agreement on major issues of the company’s long-term energy plan on June 13. The utility and others discussed the agreement at a routine committee meeting yesterday, and the PSC is scheduled to vote on the plan on July 21. The agreement includes closing some of Georgia Power’s remaining coal units this year and others by 2028.


The commission has yet to decide the fate of two additional units. By 2035, the utility expects to shutter all of the coal units in which it has a majority stake.


Brandon Marzo, an attorney who represents Georgia Power, reiterated the reasons why the utility wants to shutter its aging coal plants in speaking in support of the agreement.


Marzo cited environmental “pressures,” that are likely to increase as well as a diminishing coal supply in the United States. The recent Supreme Court decision on environmental regulation also has no impact on the utility’s plans, he said.


“It does not alter the company’s analysis in this case or the economic conclusions that several of GPC’s coal plants are uneconomic to operate,” Marzo said at a meeting that was streamed online yesterday.


Originally posted on E&E News.

The Hydrogen Economy

“Texas’s natural resources make it a natural fit for  hydrogen energy and vehicles.” – Texas Monthly

Key Questions: 

  •  Why should there be an increased reliance on hydrogen?   
  •  How has hydrogen as a fuel source been advanced?   
  •  What will help further promote hydrogen use?   

The energy industry continues to face growing energy demands from an increasing  population, while also being called to reduce carbon emissions on a significant scale.  Innovations in technology and process, including Carbon Capture, Utilization, and Storage,  provide one pathway for an array of industries both to meet demand and to attempt to  achieve carbon neutrality. Toward that end, industry and government are increasingly  focused on the use of hydrogen, an energy source touted as an affordable, reliable, clean, and  secure energy by the U.S. Department of Energy (DOE) and industry groups alike. The DOE  has billed hydrogen as the fuel product that can “enable U.S. energy security, resiliency, and  economic prosperity.”i As a key player in the oil and gas industry, Texas has the opportunity  to lead the way in providing that energy stability and reliability, while also seeing the  economic benefits of advancing the potential future of fuel.   

Why Hydrogen?   

Hydrogen is a one-hundred percent renewable, zero emission fuel that can be produced from  various resources, including natural gas, nuclear power, biomass, and renewables, such as  solar and wind power. In 2020, one percent of hydrogen production in the U.S. was from  electrolysis, while 99 percent was from fossil fuels. “Fossil fuels are expected to continue as  the main source of hydrogen through 2050 based on International Energy Agency  projections driven by abundant supply, low cost, and expected development of large-scale  carbon capture and storage.” ii   

However, because it can be produced through diverse resources, it can be produced on a  large scale. Hydrogen is an invisible gas, but it is classified in name by colors, from green to  grey to blue, yellow, turquoise, and pink. While broadly all hydrogen is seen as a “clean” fuel, the three main variations of produced hydrogen, grey, blue, and green, each produced  through different processes and with different carbon intensities:

  • Grey hydrogen, which is currently the most common, is derived from  natural gas, and is most commonly used in the chemical industry to make fertilizer and for refining oil.iii  

  • Blue hydrogen utilizes the Carbon Capture, Utilization, and Storage  process, repurposing generated carbon for reuse in the hydrogen  manufacturing process or storing it for future use. Blue hydrogen can be  used as a low-carbon fuel for generating electricity and storing energy,  powering cars , trucks and trains. iv 
  • Green hydrogen is produced using electrolysis powered by renewable  energy, such as offshore wind, and carries the benefit of producing zero  carbon emissions. It can be used for manufacturing ammonia and  fertilizers, and also in the petrochemical industry to produce petroleum products.v
    Although green hydrogen is seen as the ultimate goal for zero emissions, it requires twice as  much water as steam methane reformation to produce grey or blue hydrogen and can be two  or three times as expensive to produce as grey or blue hydrogen, depending on the price of  natural gas.vii The European Union has called for the increased use and focus solely on green  hydrogen in order to meet the EU’s goal of net-zero emissions by 2050. In the U.S., however,  the landscape holds a mix of gray, blue, and green hydrogen, as the industry weighs  investment, demand, and regulation. Case in point: the Port of Corpus Christi (PCC), the US’s leading energy export gateway, is actively cultivating production of low-carbon hydrogen  from diverse feedstocks to supply world-scale international demand. In public  presentations, PCC leadership has stated that while the port has numerous commercial scale  electrolytic (green) hydrogen projects in development, they are also recognizing that  bringing hydrogen production to world scale will require using natural gas feedstock, at least  for the next 8-10 years. To this end, PCC is partnering to develop scalable, centralized  geologic storage for captured carbon, which will enable low-carbon hydrogen production  from the regions abundant, affordable natural gas. The Center for Houston’s Future recently  released a report outlining the ways in which Houston could become the epicenter of a global  clean hydrogen hub, including the utilization of existing hydrogen production facilities and  pipelines on the Gulf Coast, reliance on Houston’s industrial energy consumer base, and the  renewable energy assets already in place. The report projects that a Houston-led clean  hydrogen hub could reduce carbon emissions by 220 million tons by 2050. viii   

    In that report, the Houston Energy Transition Initiative (HETI), through their collaborative  of the Greater Houston Partnership and Center for Houston’s Future, also forecasted that  Texas could build a $100 billion hydrogen economy, with 180,000 jobs by 2050, through  initiatives focused on policy, infrastructure, innovation, and talent. The report projects that  clean hydrogen demand could grow from current 3.6 million tons (MT) to 21 MT by 2050,  with 11 MT of local demand and 10 MT available for export. ix

    On a global level, PricewaterhouseCoopers analyzed the green hydrogen market on a  worldwide scale and released findings on potential demand growth. The report projected  that through 2030, demand growth will maintain a moderate, steady growth through smaller  application across industrial, transport, energy and building sectors. The growth is then  expected to accelerate from 2035 forward, due to a decrease in production costs over time,  technological advances, and economies of scale.x In 2020, GoldmanSachs projected that  green hydrogen could supply up to 25% of the world’s energy needs by 2050 and become a  $10 trillion market by 2050.xi

    Other companies such as Sempra are seeking ways to support green hydrogen initiatives,  with goals to support the expansion of electric grids, with increased flexibility, with low or  zero carbon energy such as hydrogen. The Southern California Gas Company recently  announced a green hydrogen energy infrastructure system, called The Angeles Link, to serve  the Loas Angeles County with a hydrogen-ready, interstate pipeline system in an effort to  decarbonize dispatchable electric generation.xii More innovative initiatives to use hydrogen  in order to deliver reliable, affordable energy that is low or zero-carbon are sure to follow.  

    Hydrogen Economy Advancement   


    According to the International Energy Agency (IEA), the current largest consumer of  hydrogen is in oil refining, followed by use in chemical production, ammonia production, and  methanol production. Steelmaking consumed a minor amount of hydrogen in 2020, but  demand in the iron and steel industry is expected to rise. In the transportation sector,  hydrogen has been used in limited amounts, but as fuel cell electric vehicle development  expands in the U.S. and Japan, increased use is expected as a motor fuel for both light and  heavy duty vehicles.xiii The Texas-based company Hydron has begun the effort to bring  hydrogen-powered, autonomous ready long-haul Class 8 trucks to the Texas roadway.xiv Hydrogen fuel cells offer several distinct advantages over battery electric vehicles in the  heavy freight sector, with substantially longer range and lower refueling times.   

    A federal effort to further increase reliance on all hydrogen is already underway. DOE has  put in place a major initiative to advance the production, transport, storage, and utilization  of hydrogen in an affordable way, across multiple sectors.xv [email protected],” the DOE initiative,  is built on the idea that hydrogen as a fuel source carries many benefits. First, hydrogen  contains the highest energy content by weight of all fuels and is seen as a critical feedstock  for all chemical industry. Second, it can be a zero-emissions fuel, making it a critical part of  many industry and government goals for reducing or eliminating emissions. Hydrogen can  also be used as a ‘responsive load’ on the grid, enabling stability and energy storage and  increasing utilization of power generators.   


    The DOE identifies the next steps in expanding the value proposition of hydrogen  technologies as increasing infrastructure and seeking further opportunities for the use of  hydrogen. Those other uses include “steel manufacturing, ammonia production, synthetic or  electrofuel production (using CO2 plus hydrogen), and the use of hydrogen for marine, rail,  datacenter, and heavy-duty vehicle applications.”xvi The [email protected] program offers some  incentive, focusing on early-stage research and development projects and facilitated through  cooperative agreements with matching DOE funds. There remains a push, however, for a  prominent role for the private sector in advancing hydrogen use: “[w]hile DOE’s role focuses  on early-stage R&D, such as new concepts for dispatchable hydrogen production, delivery,  and storage, reliance on the private sector for demonstration is critical.”

    In October of 2021, Senator John Cornyn and others introduced a bi-partisan bill package to  incentivize hydrogen infrastructure and adoption of hydrogen in certain sectors. The three bill initiative creates research and grant programs for advancements in hydrogen  infrastructure, with the following three focus areas:  

  1. Maritime: Creates a grant program for hydrogen-fueled equipment at ports and in  shipping;  
  2. Heavy Industry: Creates a grant program for commercial-scale demonstration  projects for end-use industrial application of hydrogen, which includes the  production of steel, cement, glass, and chemicals;
  3. Infrastructure: Creates a pilot financing program to provide grants and low interest loans for new or retrofitted transport infrastructure, storage, or refueling  stations. 

In this initiative, priority will be given to projects that will maximize emissions reductions.  In February of 2022, the Port of Corpus Christi and Apex Clean Energy, Ares, and EPIC  Midstream entered an agreement to explore development of gigawatt-scale green hydrogen  production, storage, transportation, and export as part of PCC’s burgeoning hydrogen hub.  This agreement builds upon an agreement from May of 2021 to work towards developing  infrastructure to support green hydrogen production.   


Major oil companies such as BP and Shell are pursuing hydrogen projects that may begin as  blue hydrogen but will likely yield increasingly more green hydrogen as the electrolier  marketplace matures. With this increased focus, BP projects that hydrogen could make up  16% of global energy consumption by 2050 if net zero carbon-emissions goals are to be met,  where it is currently at less than 1%.xvii Currently, the United States produces more than 10  1million metric tons of hydrogen each year, which amounts to one-seventh of the world’s  supply.xviii A move toward increased hydrogen production has been percolating in the Texas  industry for years. In a 2017 Texas Monthly article, Michael Lewis, program manager for fuel   cell vehicle research in the Center for Electromechanics, University of Texas at Austin,  identified Texas’ unique ability to be a leader in hydrogen production. “Texas’s natural  resources make it a natural fit for hydrogen energy and vehicles. Our natural gas resources  are an economical feedstock for hydrogen production. Curtailed wind power in West Texas  could power the production of hydrogen for use in vehicles and other applications. And miles  of hydrogen pipeline already exist along the Texas coast, which would ease distribution.”xix With Texas holding the majority of 1600 miles of hydrogen pipeline infrastructurexx, Texas  has an advantage in pursuing the advancement of hydrogen production.   

Geological storage of hydrogen is another topic that must be considered in the advancement  of hydrogen use. Salt caverns have met current storage needs, which allow for fast  withdrawal and injection rates but can be costly and have limited capacity. The Bureau of  Economic Geology at the University of Texas (BEG) has identified two categories of storage reservoirs that could provide more available and advantageous storage: (1) depleted oil and  gas reservoirs; and (2) saline aquifers, which have proven storage capabilities and are  already supported by infrastructure. xxi The BEG has identified the need for an inventory of  sites for use in order to make progress on hydrogen storage; the identification of such sites  could also help further other low carbon initiatives such as CCUS, by locating storage that  could be utilized for both long term sequestration and immediate term hydrogen storage.  


Hydrogen Incentives  

Industrial adoption of hydrogen as a primary fuel could be accelerated by additional  incentives. One proposal is to create “Hydrogen Development Zones” taking advantage of the  Opportunity Zone Program, a federally approved program meant to spur economic  development and job creation in distressed communities. The program offers incentives  such as capital gains abatement when private businesses invest eligible capital into pre  

qualified opportunity zone assets. A sustainable energy enterprise, earlier discussed as a  company engaged in CCUS, and further here in hydrogen production, could potentially apply  for the tax incentives when pursuing increased hydrogen production in a “Hydrogen  Development Zone.” Tax relief could further be encouraged through the Governor’s Office of  Economic Development and Tourism, with a directive for tax incentives to foster job creation  and development of sustainable energy in Hydrogen Development Zones.

A statutory definition of hydrogen could be included, to include products derived from  hydrogen or any other conversion technology that produces hydrogen from a fossil fuel  feedstock. Another necessary action would be requiring Texas and its partners, including  local governments, industry, and institutions of higher learning, to consider a number of  factors in their duties to support the state’s Hydrogen Initiative. Relating to procurement, a  state agency that seeks to purchase any item requiring the use of a power source, including  but not limited to motor vehicles, material and cargo-handling equipment such as forklifts,  harbor craft, generators, power systems, portable floodlights, microgrids, and  telecommunications equipment, should include in the request for proposals provisions that  allow for the consideration of items that are powered by Texas hydrogen.   

The Legislature could also authorize state government, specifically the Office of the Governor  and TCEQ, to consider investments in hydrogen fueling infrastructure and the production of  sustainable hydrogen as a transportation fuel, and also define transportation electrification  to include sustainable hydrogen used as a transportation fuel. Relatively small changes to  Texas Emissions Reduction Program alternative fuel requirements could open underutilized  funds currently allocated exclusively to compressed natural gas vehicles.xxii Finally,  industrial revenue bonds for the purpose of achieving a Texas Hydrogen Development Zone  goal could be authorized through the governor and the Legislature, along with permitting  counties, municipalities and other political districts to bond for sustainable projects. 

Although hydrogen prices have increased in line with other energy sources, due to increases  in the natural gas markets, long-term growth projections still anticipate a reduction in  hydrogen price as technology continues to advance and scale increases. xxiii Thanks to robust  existing hydrogen infrastructure and frenetic commercial activity in the hydrogen value  chain at Port Corpus Christi and other cornerstones of the global energy marketplace, Texas  could easily become the leading producer of low-cost hydrogen in the nation. With an  increased focus from the industry, along with support from state and local government  leaders, Texas is in the best possible position to benefit from an increased reliance on this  low to zero-emissions fuel.   

i  ii   

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vii Blue Vs. Green Hydrogen: Which Will The Market Choose? (  

viii  ix as%20the%20epicenter%20of%20a%20global%20clean%20hydrogen%20hub/houston-as-the-epicenter-of-a global-clean-hydrogen-hub-vf.pdf?shouldIndex=false   

x cost.html#:~:text=Through%202030%2C%20hydrogen%20demand%20will,form%20to%20develop%20hydrogen% 20projects.   

xi  xii  xiii   

xiv; producing-hydrogen-powered-autonomous-ready-freight-trucks/   



xvii Big Oil Companies Push Hydrogen as Green Alternative, but Obstacles Remain – WSJ  

xviii  xix  xx  









Carbon Capture, Utilization, and Storage: Incentives

The Texas energy industry faces a significant challenge today. The oil and gas industry is being asked to continue to provide reliable energy for an increasing population as well as for developing and emerging economies who strive to lift themselves out of ‘energy poverty’, while simultaneously meeting growing calls to reduce carbon emissions and address climate change. The pressure from financial institutions, in concert with federal regulatory agencies, means that the state must incentivize large-scale deployment of carbon capture technology.

It is a recognized fact that energy demand has and will continue to grow. Specifically, the U.S. Energy Information Administration (EIA) projects a close to 50% increase in world energy use by 2050.i The EIA projects that total volumes of fossil fuels consumed in the United States will increase by 10% between now and 2050 and that 74% of America’s energy will still come from fossil fuels in 2050. Further, the EIA projects that by 2050 fossil fuels will still supply 69% of the world’s energy. As demand for fossil fuel energy continues to rise around the world, well-funded groups, financial institutions and regulatory agencies are making significant efforts to drastically reduce or even eliminate fossil fuels in an attempt to solve the carbon emissions issue. The result of such a course of action would undermine efforts to expand energy supply, increase energy poverty and make the current energy shortages around the world look miniscule in comparison.


The fossil fuels industry is faced with the dual problems of meeting increasing fossil fuels energy demand while also dealing with increased market – and – regulatory pressure to reduce greenhouse gas emissions. To address these problems, new technology and innovation is being advanced in the industry. One of these processes, Carbon Capture, Utilization, and Storage (CCUS) has been billed as part of a viable solution to achieve carbon neutrality without undermining the advancements of mankind’s quality of life to which the abundance and use of fossil fuels have dramatically contributed over the last 150 years.
However, CCUS is a costly and complex process. For Texas to take advantage of the opportunity CCUS provides, Texas has a unique opportunity to achieve – continued robust production of energy, but with lowered carbon emissions – with the addition of critical incentives.


What is “CCUS”?


Carbon Capture, Utilization, and Storage (“CCUS”) is the process of capturing carbon dioxide emissions produced from industrial sources to be used to increase hydrocarbon recovery, utilized for various industrial applications, or to be stored underground. Dedicated carbon storage is possible through the process of deep injection into secure geological formations, some of which may be depleted crude oil and/or natural gas reservoirs, brine-filled aquifers or mineralized basalt formations.ii Many projects in the United States and around the world have been developed, as industry has seen CCUS as a way to reduce
emissions while increasing production to meet demand.


The Opportunity for Texas


For CCUS, the existence of reservoirs and available pore space in Texas play a key role in their feasibility. Columbia University’s Center on Global Energy Policy released a case study1 on possible industry efforts to achieve significant CO2 reduction and removal. The study focuses on the idea of “net-zero industrial hubs” as a pathway to reducing emissions, focusing on Texas’ potential, particularly regarding storing carbon when it comes to CCUS:


Texas is also home to an important natural resource required for a net-zero industrial hub: subsurface pore volume for CO2 storage. The combined onshore and offshore saline formation capacity along the Gulf Coast alone is estimated above 1 trillion tons capacity—more than 10,000 times the annual emissions of Houston—and the Gulf of Mexico pore-volume storage resources
is the largest in the United States.iii


Due to its storage resources available, and current infrastructure already in place, Texas stands to play a significant role in the development and advancement of CCUS.


Possible Incentives


Because CCUS is complex and still emerging as an industry, it requires significant integration across technical and legal disciplines as well as large capital investment for companies during the development, construction and operation phases. Costs for CCUS projects are estimated to cost approximately $400 million per 1 million tons per annum., captured and stored, divided among the cost of capture, transportation, and storage. This significant cost requires some type of financial incentive for companies looking to enter the CCUS industry, particularly as the regulatory, legal, and economic frameworks are still being
developed or need clarification both on a federal and state level. A GAO report on CCUS from December 2021 cites several barriers to CCUS development on the economic level, including viability risks of the host industrial emission point source, volatility in the fossil fuel commodities market, high expected project costs, and uncertainty within carbon markets
and tax incentives, making it difficult to estimate economic viability.iv


In the International Energy Agency (IEA)’s report2 on CCUS in Clean Energy Transitions, the agency notes that several policy developments will be necessary to support this new industry:


A range of policy instruments are at policy makers’ disposal to support the establishment of a market for CCUS and address the investment challenges. In practice, a mix of measures is likely to be needed. These measures include direct capital grants, tax credits, carbon pricing mechanisms, operational subsidies, regulatory requirements and public procurement of low-carbon
products from CCUS-equipped plants. Continuous support for innovation is also needed to drive down costs, and develop and commercialize new technologies.v


Establishing sufficient incentives, on a federal and state level, could provide not only financial support but also certainty in pursuing new CCUS projects. CCUS is equivalent to making existing industrial activities carbon-free, whether for electric power, transportation fuels, petrochemicals, fertilizers, ammonia, methanol, and hydrogen. These existing sectors are large employers, particularly with well-educated, technical workforces in both the
corporate and field levels.


Federal Incentives

At the federal level, the tax credit for carbon dioxide sequestration (referred to by its Internal Revenue Code section, “45Q”) is a credit based on metric tons of carbon captured and sequestered when that carbon would have otherwise been released into the atmosphere. The captured carbon must be disposed of in “secure geological storage” to be The credit has been expanded several times since its passage and remains a major incentive on the federal level for carbon capture projects.


Recent federal legislation increasing incentives will make an impact on CCUS funding but will not completely close the gap for companies seeking to enter the new industry. New federal regulation increases the 45Q credit to $85 per ton from $50 per ton for captured and stored carbon, $60 per ton for beneficial use of captured carbon emissions, and $60 per ton for carbon stored in oil and gas fields.vii The bill also increases credits for direct air capture projects, from $50 per ton of carbon captured to $180 per ton for carbon stored in geological formations, $130 per ton for utilization projects, and $130 per ton for storage in oil and gas fields. However, the cost of the technology, compounded with current inflation rates that will significantly impact the installed costs of CCUS infrastructure, make the current 45Q levels inadequate to encourage many companies to engage in new CCUS projects.viii Accordingly, industry seeking to adapt and deploy CCUS technologies should be able to turn to state-level programs to supplement and induce CCUS projects.

State Incentives

1. Tax Credit for Clean Energy

The Legislature created a tax credit for clean energy projects in 2013, aimed at coal projects. Though now expired, the statute provides a good framework to build upon for the clean energy project that is CCUS. The statute provided a tax credit equal to the lesser of 10% of capital costs of the projects or $100 million, and was limited to three projects, to be carried forward for no more than 20 consecutive years. The statute had a requirement that the project must sequester at least 70% of the carbon dioxide resulting from the project. In recent CCUS projects, the capture rate can vary depending on the type of CO2 facility, from 60% up to 85%. With input from industry, designating a required capture rate could work to limit the amount of eligible projects or applying categories of required capture rates with different levels of incentives, would help in capping the financial expense to the state while still supporting major CCUS projects.

2. “Prop 2” Pollution Control

Another potential for tax relief falls under the Tax Relief for Pollution Control Property Program, called “Prop 2”, which provides tax relief for facilities using certain property or equipment for pollution control. The TCEQ program offers tax relief for pollution control property or facilities that are used to “meet or exceed laws, rules, or regulations adopted by any environmental protection agency of the United States, Texas, or a political subdivision of Texas, for the prevention, monitoring, control, or reduction of air, water, or land pollution.”xiii

To receive the tax exemption, applicants must request a use determination by TCEQ. Upon receiving a positive use determination, applicants then apply to their local property tax appraisal district for the property tax exemption.ix Currently, statute provides that property used to capture carbon dioxide is eligible for the tax credit but includes a limiting factor that the property is eligible if the Environmental Protection Agency (EPA), permitting authority, or other entity adopts rule or regulation regulating carbon dioxide as a pollutant.x

Rather than rely on various regulations subject to change, the state should remove the limiting factor to ensure that CCUS projects are eligible for the credit. Statute should also provide for a minimum amount of property tax relief rather than relying entirely on a determination by local appraisers with the floor increasing depending on the scale of the project. In addition, because the tax exemption is a constitutional provision, a constitutional amendment will also be required in order to amend the tax relief provision. If CCUS is considered a pollution control project or equipment, Prop 2 could provide another opportunity for tax relief when it comes to the cost of CCUS.


The Texas Emissions Reduction Program (TERP) offers financial incentives to eligible businesses and others for the reduction of emissions from vehicles and equipment. Texas Council on Environmental Quality (TCEQ) administers the program, funded by revenues from fees and surcharges relating to certain off-road equipment and on-road vehicles. TERP is intended to help Texas meet the goals of reduced pollution and improved air quality.

With amendment, CCUS could be considered eligible for several current grant programs in TERP, such as the New Technology Implementation Grant Program (NTIG) or the Emissions Reduction Incentive Grants (ERIG). Under the NTIG Program, there are several categories where CCUS could be applied, and should be included. “Advanced Clean Energy Projects” include projects that involve electricity generation through fuels such as coal or biomass, natural gas and use new technologies to reduce certain emissions from stationary sources. With the inclusion of natural gas in the category and a required reduction of carbon dioxide, a CCUS project should be considered eligible. Eligible projects under the “New Technology – Stationary Sources” category are projects that reduce emissions of regulated pollutants from stationary sources, including pollutants subject to TCEQ permitting. Carbon dioxide, as one of the major greenhouse gases, is currently permitted through TCEQ. Through either a new facility or the retrofit of an already existing facility, CCUS is a new technology that could be applied here and should be specifically included. “New Technology – Oil and Gas Projects” is another area CCUS may be applicable, as it is aimed at reduction of emissions from upstream and midstream oil and gas activities. The Emissions Reduction Incentive Grant Program (ERIG), providing grants for the upgrading or replacing of certain equipment to reduce emissions, may be another avenue for CCUS incentives. Establishing the avenue for TERP funding to apply to CCUS can help TCEQ and the state achieve the goal of reduced emissions while also allowing the state to continue its robust energy production.

4. Purchasing Preferences

There are several provisions dealing with procurement that might aid in incentivizing the purchase of products developed from captured carbon, or other low carbon processes, like hydrogen. For example, for contracts performed in nonattainment areas, the comptroller and state agencies may give preference to goods or services of a vendor that meets or exceeds environmental standards relating to air quality, when the cost would not exceed 105 percent of the cost of another vendor.xi Another provision gives a preference for some recycled, remanufactured, or environmentally sensitive products when certain factors allow,
such as price, quantity and quality.xii Amending either of these provisions, or creating a new provision, pertaining to products produced through low carbon efforts, could help incentive the market for low carbon products.

Limits on Incentives

To make CCUS incentives feasible on a state level, limiting factors are necessary, especially as the industry is developing in the state. Various metrics could apply to limit the total funds expended by the state, such as limits based on percentage of carbon captured or the size of the project. Pictured below are estimated target percentages of carbon captured per type of processing plant. As an example, the state could target plants capturing 90%- 95% of carbon emitted.

In addition to applying limits based on the size of the project or the amount of carbon captured, projects in non-attainment areas could be a priority. Non-attainment areas are those that do not currently meet National Ambient Air Quality Standards (NAAQS).

Incentives Around the Country

Several other states have created incentives meant to encourage a reduction in carbon emissions, some related directly to CCUS projects, and others related to and encompassing CCUS through enhanced oil recovery projects (EOR). Below is a summary of the tax incentives, bond authority, and eminent domain powers that have been enacted in other states to help support and develop CCUS. While bond amounts in each state are unknown, similar ideas could serve as a framework to be tailored to Texas. Importantly, this white paper does not cover other states’ initiatives concerning other elements of CCUS, namely pore space ownership and long-term liability ownership. These topics are summarized by CNC white papers elsewhere, whose conclusions with those offered herein are intended to advocate for comprehensive policy.

1. Illinois

In 2007, Illinois authorized the Illinois Finance Authority to issue bonds to finance the development and construction of coal-fired plants with carbon capture projects. Utilities in the state were also authorized to charge a fee to customers for deposit to the Renewable Energy Resources Trust Fund and Coal Technology Development Assistance Fund. Per the statute, the funds are to support the capture of emissions from coal-fired plants and the development of further capture and sequestration of carbon emissions.

2. California

California has a broad system regulating emissions, which incentivize CCUS projects as means in which to meet benchmark emissions standards in the state. California also provides an enhanced oil recovery tax credit that is similar to the federal enhanced oil recovery credit. In California, the credit is equal to 5 percent of the qualified enhanced oil recovery costs for qualified oil recovery projects within the state. However, this credit does not apply to taxpayers that are retailers of oil or natural gas or refiners of crude oil if daily refinery output exceeds 50,000 barrels.

3. Kansas

Kansas allows a five-year exemption from property taxes for property used for carbon dioxide capture, sequestration or utilization, and any electric generation unit used to capture and sequester carbon dioxide emissions. Kansas also allows for accelerated depreciation on CCUS machinery and equipment. There are also deductions from adjusted gross income available, starting with 55 percent of the amortizable cost down to 5 percent in following years for a 10-year period.

4. Louisiana

Louisiana provides a Sales and Use tax exemption for anthropogenic carbon dioxide used in a tertiary recovery project, once approved by their Office of Conservation in the Department of Natural Resources. The exemption does not specifically require geologic sequestration to qualify. The state also allows a 50 percent reduction on severance tax for the production of crude oil from a tertiary recovery project using anthropogenic carbon dioxide.

5. North Dakota

North Dakota classifies CO2 pipelines as common carrier, thereby granting them the right of eminent domain. The state also provides an exemption from their Sales and Use tax, a rate of 5 percent, for all gross receipts from the sale of carbon dioxide used for enhanced recovery of oil or natural gas. Another exemption from the Sales and Use tax is allowed for gross receipts from sales of tangible personal property used to build or expand a system used for carbon dioxide storage, transportation, or for use in enhanced recovery of oil or natural gas. The property must be incorporated into a new system rather than be used to replace an existing system, although there are exceptions for expansion purposes.

North Dakota also provides a property tax exemption for pipelines and related equipment for the transportation or storage of carbon dioxide for use in enhanced recovery or geologic storage, during construction and the following ten years.

An ad valorem tax exemption applies to coal conversion facilities and any carbon dioxide capture system located there, plus any equipment directly used for geologic storage of carbon dioxide or enhanced recovery of oil or natural gas classified as personal property. The exemption does not apply to tangible personal property incorporated as a component part of a carbon dioxide pipeline, but this restriction does not affect eligibility of such a pipeline for the carbon dioxide pipeline exemption.

Finally, carbon dioxide capture credits are available for coal conversion facilities that capture 20 percent of carbon dioxide emissions during a certain period. The owner of such a facility may take from a 20 percent reduction of the North Dakota privilege tax, a tax levied on operators of coal conversion facilities, up to a maximum of a 50 percent reduction when 80 percent or more of carbon dioxide emissions are captured. The tax reduction is available for ten years from the date of the first capture or ten years from the date the facility is eligible for the tax credit. xiii


Texas has the opportunity to lead the way in showing that the fossil fuel industry is ready to continue to provide affordable energy, electricity, and a vast array of products for the benefit of consumers while still improving our environment through lower carbon emissions. Consumers will continue to need fossil fuels for electricity, fuels, and products, but their production and use can become carbon neutral through CCUS. CCUS can be the answer to meeting government-mandated reductions in emissions, without harming the vital fossil fuel industry.

On both the federal and state level, renewable energy has benefitted from substantial subsidies.xiv As Texas has focused on incentivizing wind and solar energy in part to help reduce emissions, a new focus on enabling the oil and gas industry to utilize CCUS to reduce emissions will achieve similar goals, while still affording the state the ability to produce reliable, affordable energy. In addition, Texas’ existing workforce will be protected while also new technical jobs will be created. With a dedicated focus, the Texas energy industry stands to be the model toward reliable and secure energy production, and carbon neutrality,
through CCUS.



iii Columbia | SIPA Center on Global Energy Policy | Evaluating Net-Zero Industrial Hubs in the United States:A Case Study of Houston


viii,for%20inflation%20beginning%20in%202 027.

x Tex. Tax Code § 11.31
xi Tex. Govt. Code Tit.10, Ch. 2155.451
xii Tex. Govt. Code Tit. 10, Ch. 2155.455

xiii FTI Orrick USEA CCUS Report.pdf