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America’s New Energy Crisis

By Christopher Matthews & Katherine Blunt

The Wall Street Journal,  Aug. 1, 2022

Fossil fuel plants are closing faster than green alternatives can replace them. Producers of oil and gas can’t keep up with a surge in demand. How did this happen, and what will it take to fix it?

America is wrestling with the worst energy crisis in nearly five decades, a period of high prices and limited supply. What makes this crisis different than the troubles that roiled the country in the 1970s is how it started and the fixes required to make it end.

This current challenge began with a decade of affordable power that upended the U.S. energy world. The rise of fracking, which extracts oil and gas from shale rock, unlocked cheap domestic supplies while cleaner energy provided by wind and solar farms became far less expensive. Gasoline and oil prices fell while gas-fired power and renewable power pushed aside costlier—and politically less popular—coal and nuclear plants.

It was an era of cheap, plentiful energy. It came undone thanks to a haphazard transition to renewable energy, reduced investment in oil and gas production, political inaction and unexpected economic forces triggered by the pandemic and lockdowns. Russia’s Feb. 24 attack on Ukraine applied even more pressure to global supplies.

The result was evident across the country this summer as demand surged well ahead of new supply. Drivers paid more than $5 a gallon to fuel their cars and trucks for the first time ever. The price of natural gas used to heat homes and offices hit its highest mark in 14 years. Energy shortages now loom as U.S. stockpiles of everything from crude oil to petroleum products fall. Electricity grid operators have warned of controlled outages to balance supply and demand on the hottest days.

The proposed new legislation that gained key support this past week from Sen. Joe Manchin of West Virginia is in part pitched as addressing some of the causes of the current energy crisis. Its passage is uncertain—and in any case the investments in new energy sources it aims to spur would take years to come to fruition.

The deal would spend roughly $369 billion on climate and energy programs, including tax credits for buying electric and hydrogen vehicles. It provides numerous incentives to accelerate the build-out of wind and solar farms, as well as large-scale batteries to store their output for use when production declines. It also has provisions that benefit fossil fuel companies—requiring the Interior Department to offer oil companies millions of federal acres onshore and offshore over the next decade—as well as support for nuclear power production.

Part of the handshake agreement with Mr. Manchin this past week tackles another issue: construction delays on new energy projects. A separate bill could speed up these projects by making the environmental-permitting process faster. The delays are making it challenging to fill a gap left by the closure of older power plants.

Whether any new legislation brings upward or downward pressure on energy prices depends largely on how fast new regulations and incentives are rolled out and which come first, said Bart Melek, global head of commodity markets strategy at investment bank TD Securities. Energy companies face steeper costs of production when dealing with new regulatory hurdles but are slower to factor in incentives in their investment decisions.

“Once you make changes, you have to convince your board of directors that this is a good idea [and] your investors,” Mr. Melek said.

Politicians of both parties didn’t plan for the possibility of this current crisis, making it more difficult to solve. It is a major political problem for President Biden heading into a pivotal midterm election in which the highest inflation in four decades—driven in good part by soaring energy costs—is a kitchen-table issue for voters.

Energy was a political issue for the president from his first week in office, when he blocked completion of the Keystone XL oil pipeline and froze new oil and gas leases on federal land. He backtracked some as gasoline prices rose, resuming the sale of leases to drill on federal lands, albeit at higher royalty prices and with fewer acres offered, and asking oil-and-gas companies to produce more.

While Mr. Biden has asked for more short-term production, he still opposes long-term fossil fuel investments that will make it difficult for the U.S. to meet carbon-reduction targets. His support for policies designed to reallocate investment from oil and gas to green power amounts to a market signal that fossil fuels are a sunset industry, say executives, making it difficult for them to invest.

Energy prices have tempered in recent weeks, as traders bracing for a global recession bet that lower economic activity will cut energy usage. Gasoline prices have fallen to less than $4.30 a gallon recently, in part because prices got so expensive that drivers have stopped filling up as much. The U.S. also has abundant untapped fossil fuel reserves and remains far better positioned than Europe, where energy shortages this winter appear increasingly likely as imports from Russia dwindle.

Fracking’s fall

 

This crisis was unimaginable for many before 2020, when investors were plunking hundreds of billions of dollars into new petrochemical facilities and natural-gas power plants to take advantage of cheap American energy. The rise of fracking—which involves blasting underground shale rocks with a mix of water, sand and chemicals—had unlocked vast new domestic supplies of oil and gas.

From 2010 to 2019, while overall consumer prices rose 19%, energy prices paid by consumers—including gasoline, electricity and natural gas from utilities—rose just 11%, according to Labor Department data. In other words, the real price of energy fell by about 7%. During the prior decade, real energy prices rose 41%.

Coal power, which had been the leading source of power generation in the U.S. for much of the 20th century, was toppled by natural gas in 2016, according to the U.S. Energy Information Administration.

The shale boom transformed the U.S. from a net importer to a net exporter of petroleum and gas. Investors motivated by low interest rates plowed into fracking, and they triggered a gusher: The U.S. became the world’s top oil producer, surpassing Saudi Arabia. U.S. oil prices fell from about $78 a barrel to $58 from 2010 to 2020, lowering gasoline prices.

One shale producer that initially benefited was Bonanza Creek Energy, which attracted hundreds of millions of dollars from Wall Street investors. Between 2012 and 2019, the company roughly doubled its oil and gas production from about 12,000 barrels a day to nearly 24,000 barrels a day. But the Colorado driller burned through so much cash that it was forced to declare bankruptcy.

The same problems rolled across the industry, as many companies drew on gushers of cash to drill as much as possible with little regard to profitability. Many shale wells turned out to be less productive and more expensive than predicted, and the industry lost $300 billion more in cash than it made between 2010 and 2020, according to accounting firm Deloitte. Those losses soured investors, who began fleeing the sector. That raised oil companies’ borrowing costs and shrunk their budgets.

The result is that shale companies and investors are being cautious now. They aren’t producing enough energy to keep pace with rising demand, even as they now reap large profits from high commodity prices. Most shale-company budgets are still below prepandemic levels, and their spending will only equate to a 3% increase in production next year, according to JPMorgan Chase & Co.

Consider Bonanza Creek, which emerged from bankruptcy in 2017. It expanded production in 2019 and predicted more expansion in 2020 but pulled back when the pandemic took hold. It cut planned capital expenditures to around $65 million from roughly $225 million and laid off dozens of employees.

In November 2021, it merged with a rival to create Civitas Resources, which plans to expand production only moderately or not at all and return all excess cash to shareholders instead of plowing it into new projects. Many of Civitas’ peers are pursuing similar strategies, including Exxon Mobil Corp., Chevron Corp. and Occidental Petroleum.

“Financial investors subsidized oil-and-gas companies to grow volume with no regards to profit and essentially subsidized the consumer,” said Ben Dell, chairman of Civitas and co-founder of private-equity firm Kimmeridge Energy Management Co., which owns a nearly 14% stake, according to S&P Capital IQ. “Now, the investors are asking for a return on their capital and, by default, the prices will be higher.”

The limitations of green energy

 

There was a time when it also seemed like it would be relatively easy to replace many fossil-fuel plants with renewable energy and large-scale batteries that store wind and solar power for use as fossil-fuel production declines.

These energy sources became much less expensive over the last decade due to more efficient production as well as government subsidies that made renewables more attractive for investors. Renewable energy, including hydroelectric power, in 2020 became second to natural gas as a source of electricity generation in the U.S., according to the U.S. Energy Information Administration.

But as U.S. power supplies tighten, developers are struggling to build these projects quickly enough to offset closures of older plants, in part because of supply-chain snarls. Another reason: It takes longer to approve their connections to the existing electricity grid. Such new requests neared 3,500 last year compared with roughly 1,000 in 2015, according to research from the Lawrence Berkeley National Laboratory. Typical time needed to complete technical studies needed for that grid approval is now more than three years, up from less than two in 2015.

One renewable-energy developer, Recurrent Energy, filed more than 20 of these grid-connection requests last year in California, a state that needs more clean power to replace several gas-fired power plants as well as a nuclear plant slated for retirement in the coming years. It took the company seven years to get approval and construct a separate battery storage project in that state.

“It’s only getting harder and harder to get things done in California, specifically, but in every market,” said President and General Manager Michael Arndt.

Wait times can be years for other projects that could also help alleviate energy shortages, such as high-voltage power lines to carry electricity between regions, natural gas pipelines and offshore wind farms capable of generating large amounts of clean power. These require land and ecological studies that many stakeholders say are critical to protecting wildlife, nearby industries and other interests.

The strain is already evident in the Midwest, where Midcontinent Independent System Operator Inc. operates a regional grid across multiple states. One of its biggest challenges, said Chief Executive John Bear, is how to replace coal- and gas-fired power plants that can produce power on demand with wind and solar farms where output fluctuates with weather and time of day.

When electricity supplies get tight, MISO calls on every available generator to produce power in what’s known as a “MaxGen” event, something that rarely occurred before 2016. Since then, MISO has had more than 40 MaxGen events, a number of which occurred outside the summer months, when demand is typically highest.

MISO this past week approved a sweeping plan to build high-voltage power lines to help balance supplies, though the projects aren’t expected to be complete until 2030. It is also considering how to better compensate power plants for operating on standby to slow the pace of closures. “The transition may require some scaffolding, and that scaffolding may be some gas plants,” Mr. Bear said.

Project delays—coupled with higher gas prices—present new challenges for utilities, too. They are paying more to produce or purchase electricity while planning big spending increases to upgrade aging infrastructure and prepare for new energy demands.

Xcel Energy Inc., a Minneapolis-based utility company serving parts of eight Western and Midwestern states, is wrestling with slowdowns on solar projects. Those include contracts with solar farms in Colorado that were scheduled to be online in late 2022 and early 2023.

Xcel, through one of its subsidiaries, is now working on contingency plans to ensure adequate supplies for next summer. It plans to invest $26 billion between 2022 and 2026 partly so it can build more high-voltage power lines to carry more power from new wind and solar farms.

Xcel CEO Bob Frenzel said higher energy prices pose near-term challenges for the company and its customers, but he expects they will fall with time. The war in Ukraine, the pandemic and supply chain snarls, he added, would have been easier to manage if they didn’t converge.

“You put those three factors in a mixing bowl, and you come up with a bigger challenge,” Mr. Frenzel said.

‘No one knows what to do’

 

The actions of the U.S. government also contributed to this current crisis. Federal decisions made over the last three decades to encourage competition, lower costs for consumers, sell oil and gas to foreign buyers and encourage the development of more renewable sources are having unintended consequences now that the energy market is in turmoil.

It began with the decision to deregulate the electricity industry, a movement that first gained support following the energy shortages of the 1970s and gathered more momentum with the 1992 passage of the Energy Policy Act, which encouraged competition among wholesale electricity suppliers. The federal government also lifted price caps on natural gas and created incentives for more renewable energy sources to take root in markets around the country, hoping to prop up technologies that didn’t rely on oil and gas.

What this new system created in the subsequent decades was a patchwork of markets across much of the country with different regional operators, leaving state regulators and power grid managers to do much of the planning. Coordination across regions became more challenging as states set different goals to reduce carbon emissions.

Consider what happened in California when the state experienced rolling blackouts in 2020 after temperatures rose across the West. The state had substantially reduced its reliance on gas-fired power plants in recent years in favor of renewable energy, giving way to evening supply crunches on hot days when solar production tapers off. California has historically imported a lot of power from neighboring states in times of need, but it was constrained in its ability to do so during the 2020 heat wave because neighboring states also had numerous plants close and thus had less power to spare.

“You had too much capacity come off the market too quickly and now all the markets are scrambling for reliability,” said John Arnold, a former natural gas trader who now is a billionaire philanthropist.

Presidents Obama, Trump and Biden all encouraged U.S. exports of liquefied natural gas. The U.S. became the world’s top LNG exporter this year as it sent huge volumes to Europe to help replace Russian supplies. But those same exports are now driving up domestic gas prices because U.S. consumers are effectively competing for supplies with foreign buyers, say analysts, and will keep prices elevated for years to come due to long-term supply contracts signed by exporters.

The U.S. government has more recently taken steps to help with the nation’s transition to renewable energy sources. For example, it expanded its authority to intervene in state-level permitting processes for high-voltage power lines as a way of helping balance electricity supply and demand across regions. Mr. Biden is also trying to lower high energy prices by asking Saudi Arabia, which he had vowed to treat as a “pariah” after the killing of journalist Jamal Khashoggi, to pump more crude. He traveled there earlier this month.

One former regulator said the current situation reminds him of a period five decades ago when an Arab oil embargo and revolution in Iran led to a rethinking of energy policy in the U.S. and Europe. But it is also different, he said.

“The crisis now is much worse than it was in the 70s,” said Bernard McNamee, a Republican former member of the Federal Energy Regulatory Commission. “Everyone is looking around, and no one seems to know what to do.”

Originally posted on The Wall Street Journal

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 https://www.energy.gov/eere/articles/five-things-you-might-not-know-about-h2scale  ii https://www.beg.utexas.edu/research/areas/hydrogen   

iii https://www.jdpower.com/cars/shopping-guides/whats-the-difference-between-gray-blue-and-green-hydrogen  iv https://theconversation.com/blue-hydrogen-what-is-it-and-should-it-replace-natural-gas-166053I  v https://www.activesustainability.com/sustainable-development/what-is-green-hydrogen-used for/?_adin=02021864894   

vi https://energyeducation.ca/encyclopedia/Types_of_hydrogen_fuel   

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

viii https://www.houston.org/news/report-houston-region-poised-become-global-clean-hydrogen-hub  ix  

https://www.mckinsey.com/~/media/mckinsey/business%20functions/sustainability/our%20insights/houston%20 as%20the%20epicenter%20of%20a%20global%20clean%20hydrogen%20hub/houston-as-the-epicenter-of-a global-clean-hydrogen-hub-vf.pdf?shouldIndex=false   

x https://www.pwc.com/gx/en/industries/energy-utilities-resources/future-energy/green-hydrogen cost.html#:~:text=Through%202030%2C%20hydrogen%20demand%20will,form%20to%20develop%20hydrogen% 20projects.   

xi https://www.goldmansachs.com/insights/pages/gs-research/green-hydrogen/report.pdf  xii https://www.sempra.com/newsroom/spotlight-articles/green-hydrogen-leadership-opportunity  xiii https://www.iea.org/reports/hydrogen   

xiv http://www.hydron.com/; https://hydrogen-central.com/tusimple-co-founder-mo-chen-launches-hydron producing-hydrogen-powered-autonomous-ready-freight-trucks/   

xv https://www.energy.gov/eere/fuelcells/downloads/h2scale-handout   

xvi https://www.energy.gov/eere/fuelcells/downloads/h2scale-handout   

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

xviii https://www.energy.gov/eere/articles/five-things-you-might-not-know-about-h2scale  xix https://www.texasmonthly.com/news-politics/electric-vehicles-energy-problem-hydrogen-may-answer/  xx https://www.energy.gov/eere/fuelcells/hydrogen-pipelines  

xxi https://www.beg.utexas.edu/research/areas/hydrogen   

xxii https://www.tceq.texas.gov/airquality/terp/tngvgp.html   

xxiii https://www.utilitydive.com/news/green-hydrogen-prices-global-report/627776/  

 

 


 

 

 

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 credited.vi 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.

3. TERP

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

Summary

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.

i https://www.eia.gov/todayinenergy/detail.php?id=41433

ii https://www.energy.gov/carbon-capture-utilization-storage

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

iv https://www.gao.gov/products/gao-22-105111
v https://www.iea.org/reports/ccus-in-clean-energy-transitions
vi https://fas.org/sgp/crs/misc/IF11455.pdf
vii https://www.jdsupra.com/legalnews/key-climate-and-energy-provisions-in-5560526/

viii https://www.catf.us/2022/06/inflation-creates-new-urgency-for-passage-of-45q-enhancements/#:~:text=In%20the%20most%20recent%20draft,for%20inflation%20beginning%20in%202 027.

ix https://www.tceq.texas.gov/airquality/taxrelief
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

xiv https://www.dsireusa.org/