U.S. Gearing Up for Offshore Storage by Establishing Rules of the Game

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We are still in the early days, but using offshore storage wells and basins to store the carbon captured from emissions and the atmosphere is building momentum.

The technologies for removing carbon emissions are becoming more economically feasible, and the government has stepped up with legislation to speed it up. The most recent provisions in the Inflation Reduction Act are a good example. Carbon capture projects are getting a huge push forward by the Biden administration. They are, for example, the big winners in the $369 billion climate bill recently passed by Congress.

The next question:  Where will all of this captured carbon will be stored?

Onshore geological (underground) storage is the obvious first stop. It has been in use in the oil industry for years and is an integral part of business for companies like Occidental Petroleum, which uses carbon dioxide injection as a method to increase crude oil recovery.  This practice is often termed as CO2 enhanced oil recovery, or CO2 EOR. 

The geological formations and depleted reservoirs in offshore waters like the Gulf of Mexico also hold tremendous promise as future storage sites. The same porous geology of the U.S. Outer Continental Shelf that has made it a great place to drill for oil and gas also makes it highly favorable for storing carbon.

Offshore storage also provides the ability to reuse the extensive offshore infrastructure. More importantly, it also allows companies to be able to set up storage next to major emission centers, such as refineries and industry, without having to worry about transporting the carbon back to onshore facilities.

The government and the industry are beginning to take the necessary steps to take advantage of offshore storage sites.

Successfully storing carbon offshore means doing so safely. And that means a set of regulations with rules of the game for all players. It ensures that all operators consistently apply the same safety practices that can be effectively monitored.

Drafting the initial set of safety regulations is the task of the U.S. Department of Interior’s Bureau of Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE). They have a mid-November deadline to do so, according to the Biden administration’s 2021 Infrastructure Investment and Jobs Act. It gave the Secretary of the Interior the authority to grant leases for offshore carbon storage in U.S. federal waters.

The end game for the new rules is clear.

These offshore regulations need to make carbon storage safe for the public, which will provide confidence in developing the sector further. To do so, there need to be parameters to ensure that storage sites are carefully chosen and sufficient monitoring is conducted to make sure the carbon remains safely sequestered.

Existing rules for onshore carbon storage, overseen by U.S. Environmental Protection Agency, or EPA, have worked well and can provide some guidance. The focus of its rules are to ensure the protection of underground sources of drinking water. Even so, many elements of these regulations have a useful overlap.

Like those for offshore exploration and production, the new regulations are expected to be designed around best practices. The offshore regulatory agencies, BOEM and BSEE, have already proposed a list of these management practices for offshore carbon sequestration.  

Both the list – and the practices – are similar to what energy companies already do for offshore oil and gas operations. When drilling for hydrocarbons, companies spend millions to ensure that they understand the geology and the characteristics of the site.  They do so by collecting and analyzing extensive geologic data to determine with great precision the potential of a geological formation thousands of feet below the surface.  

These same techniques are well-suited for offshore carbon storage.

“It is applied to slightly different circumstances, but you still need to understand the areal and vertical structure of these reservoirs and how the sealing mechanisms – shale layers above and below, fault seals, etc. – can effectively sequester the fluids in them for centuries,” said Ram Seetharam, a former Exxon executive now working on affordable carbon capture and storage solutions. “You need to be able to predict where the carbon dioxide is going and be confident there are not pathways that will let it be released at the surface.”

It also means that the activities the regulations are expected to make mandatory – identifying risks through a risk management plan, monitoring these risks and reporting their progress – are already practiced by the industry in their drilling and production operations.

There are, of course, additional financial issues to address, such as how to handle any liability issues that arise in case of a storage malfunction, and how to decommission the sites if and when necessary. 

Those who recall the BP Deepwater Horizon accident fear a big uncertainty:  the safety risks of offshore storage. There are several reasons why offshore carbon storage is significantly less risky than an offshore oil platform or subsea drilling operation. The most important reason is that even in a worst-case scenario, a carbon dioxide leak is not nearly as toxic or dangerous for the environment as a major oil spill.

“There are not any combustible materials to deal with,” Seetharam said. “The explosion risks are significantly lower than when dealing with hydrocarbons.”

But it still leaves the human health question: While CO2 is naturally present in the air and is not harmful to health at low concentrations, a CO2 plume could be enough to kill a person in direct contact. For this reason, the British government has raised concerns that carbon storage has the potential to create a major accident hazard, given a devastating leak. 

For this very reason, many experts view offshore storage as preferable to storage near population centers. At the same time, these safety concerns are why it is such good news most of the companies looking at offshore carbon storage bring decades of experience.

Several of the largest energy companies that operate in the Gulf of Mexico have already partnered to develop the Northern Lights project, an offshore carbon storage project in the North Sea and off the coast of Norway. This project is currently scheduled to go into operation in 2026. The companies involved – BP, Eni, Equinor, Shell and Total – are players in the Gulf of Mexico as well and said to be looking for offshore storage opportunities.

Coming up with rules that are sufficient to protect us while still encouraging a much-needed service in the name of protecting the climate is a heavy lift for the regulators. But these new regulations can’t come soon enough.

Texas is Primed to Be Our Nation’s Direct Air Capture Capital

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Emily Pickrell, UH Energy Scholar

Right now, much of the climate change conversation is focused on reducing future emissions.

While that is critical, it represents only part of the solution. Some industrial processes – steel, cement and aviation – will prove challenging to decarbonize. Having a way to remove this carbon will be part of the solution.

Emerging direct air capture technology is ready to address that challenge. It’s a technology that climate activists, the U.S. government and the energy industry all agree is essential to tackle hard to abate distributed emissions.

The technology’s future has just had a huge boost – the Inflation Reduction Act. The legislation includes generous support for direct air capture facilities. And the learning by doing that these facilities will enable will improve the economics of projects into the future.

These incentives complement the 2020 infrastructure legislation, which included $3.5 billion for four regional direct air capture hubs.  The purpose of such a hub is to encourage the colocation of complementary infrastructure. To be eligible for government funding, any proposed hub site must demonstrate that it will eventually be capable of capturing at least 1 million metric tons of carbon dioxide annually.

Because of attached funding, many states are making proposals for why their location makes sense, talking up regional economic development needs and other factors to argue their case.

Yet Texas has a much more compelling and unique story: it can make direct air capture economically feasible, with customers willing to pay for the capture carbon, and in doing so, financing the expensive technology.

This is important, because the high cost of direct air capture has been one of the biggest barriers to adoption. Right now, using direct air capture is estimated to cost roughly $500 per ton, according to data provided by the University of Houston. These costs could go down to $300 per ton in the coming years, when the technology becomes more efficient.

Creating hubs where these costs can be controlled and lowered will be essential for broad commercial deployment when the funding for government programs ends.

It will encourage companies to make the huge investments that these kinds of emerging technologies need for further development – which leads to further price decreases.

The good news is that several Texas-based major energy companies are already committing to these kinds of investment in direct air capture.

And they have been doing so for years.

Houston-based Occidental Petroleum recently announced it would begin construction of a direct air capture plant in West Texas to remove 1 million tonnes per year of CO2 from the atmosphere, using the captured carbon dioxide for its enhanced oil recovery, or EOR, strategy. For EOR operations, carbon dioxide is a critical input. The carbon dioxide is injected into the ground to help squeeze out oil that would otherwise be difficult to reach.

The resulting oil produced changes the overall economics for these projects, converting the carbon into a valuable commodity, rather than just a waste product to be stored.  

Much of this carbon dioxide based EOR is taking place in the Permian Basin, where there are many depleted reservoirs available to displace oil and store carbon. The industry in the Permian Basin has also demonstrated over the last 50 years that they know how to safely sequester carbon and manage it, without any significant threat to surrounding communities. Given the importance of public confidence about the overall idea of carbon storage, Texas’ track record would be a real asset.

Texas also has favorable storage geology, with onshore storage capacity for between 661 million and 2.4 billion tons of carbon dioxide in its gigantic underground reservoirs. For direct air capture projects in Texas’s Permian Basin, there will be no need for extensive pipeline infrastructure to move the carbon dioxide to storage facilities. 

Again, a big cost saver.

Direct air capture facilities are expensive to run – about half the overall cost of the projects come from the energy required to operate them. And given that the aim is the removal of carbon from the atmosphere, carbon-free fuels should be used.

Once more, it’s Texas – this time by a long shot.

The Lone Star state is the largest wind energy producers in the U.S. Wind energy accounted for 25% of its total generation in 2021, making the kinds of power demands of direct air capture seem modest in comparison. And better yet, it could do so without the need for a big infrastructure upgrade to its powerlines – most of the wind generation is already in West Texas.

Under the requirements of the legislation, the projects need to be able to capture and sequester or use at least one million metric tons of carbon dioxide each year. They also need to demonstrate that they could be developed into a regional carbon network for carbon storage.

Several companies in Texas are actively working on direct air capture solutions. Chevron and Occidental have both invested in a joint venture to take carbon directly from the air and subsequently synthesize it into clean transportation fuels. ExxonMobil has spent the last three years working together with Global Thermostat on direct air capture to advance “breakthrough technology and ways to bring it to scale”.

The work these companies are doing also ensures that they will have plenty of human talent and direct experience in place – in addition to the wealth of energy know-how already available in Texas.

When the announcements come, Texas should feature prominently on the list.

The success of emerging technologies like direct air capture actually do hang on whether they can develop further by attracting more investment and becoming economic. Companies should be excited about their ability to make them work and flourish while doing so.  No other state can make a case like Texas about how it is ready to make this happen. 

Where Have All the Refineries Gone? How Energy Politics Are Discouraging Critical Investments

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Emily Pickrell, UH Energy Scholar

A summer of $5 per gallon gas has made the refinery business a very lucrative proposition, at least in the short term.

Yet while demand has been tight, concerns about climate change and societal push back against fossil fuels have made it difficult to build new refineries, even as U.S. and international demand for refined products continues to grow.

The uncertain future of gasoline in today’s policy discussions is one reason for a lack of investment, even in the recent $5-or-more gasoline price climate.

Initiatives like the Biden’s administration’s goal of electric vehicles making up 50% of auto sales by 2030 have done little to dispel this uncertainty. 

So far, gasoline production has remained stable. In the first six months of 2022, the U.S. produced 19 million barrels of refined products per day, according to data from the U.S. Energy Information Administration. That’s up slightly from the 18.6 million barrels per day average in 2021.

Yet prices still went haywire earlier this summer. Recovering post-pandemic travel growth has spiked international demand. Coming in the face of a boycott of Russian crude oil, the supply/demand imbalance has pressured prices higher.

The U.S. capacity to meet this growing demand is limited. Refineries cost billions to build or retrofit for expansion. In the current high gas price environment, they are cash cows. Yet when gasoline prices are low, as was the case just two years ago, they run on razor-thin profit margins.

“The real question for refineries right now is whether to invest billions of dollars on retrofitting them,” said Paul Doucette, the hydrogen program leader at the University of Houston and former energy transition executive and general manager at Baker Hughes. “You ask yourself, can I make money over the next 40 years? The market is telling you that EVs are becoming more popular, that pressure to reduce emissions are more severe, that carbon prices or taxes may be coming in the near future, and that environmental justice community may not want you there.”

Philadelphia Energy Solutions, for example, made the decision in 2019 to close its 335,000 barrels per day operation after a fire. Repairing the refinery would have been a huge investment. But at the same time, the refinery had long been a source of contention with local residents. The pushback invariably factored in to the decision to permanently close the facility.

The loss of these refineries has had a cumulative impact. In 1982, there were 27 operating East Coast refineries with 1.8 million barrels per day capacity. By 2022, this number has dwindled to seven facilities with 800,000 barrels per day capacity.

The same pattern is taking place across the country.

The Shell refinery in Convent, Louisiana shut down in 2020, removed another 211,146 b/d capacity. So did Marathon’s 161,000 barrels per day refinery in Martinez, California. And the 48,000 b/d HollyFrontier refinery in Cheyenne, Wyoming, the 27,000 b/d Western Refining refinery in Gallup, New Mexico and the Dakota Prairie 19,000 b/d refinery in Dickinson, North Dakota.

And if older refineries are shutting down because the economics don’t make the investment seem worth it, new refineries are not being built and haven’t been built for several decades. The tremendous hurdle to get regulatory and environmental approval jacks up the price tag.

One big challenge is getting past the lawsuits that accompany the approval process.

“If I was trying to toss a grenade to slow down a new refinery or a major expansion, I would look for federal approvals that trigger a requirement to prepare an environmental impact statement,” said Tracy Hester, an environmental law professor at the University of Houston’s Law Center. “Even if you can’t stop a refinery project outright, you can slow it down and effectively kill it with a thousand paper cuts.”

The planned $3.8 billion expansion of a BP Whiting refinery in Indiana, for example, met with considerable opposition from the National Resources Defense Council and the Sierra Club, which jointly sued the U.S. Environmental Protection Agency over how particulate matter emissions would be regulated.

Environmental pressure, such as emissions targets, is also working to pressure companies to reduce their fleets.

LyondellBasell Industries, for example, has already announced it will shut its Houston Refinery in 2023, citing ‘decarbonization goals’ as part of the reason.  

This is not to say that all the environmental concerns are without merit.

Local pressure has also come from communities of color. They have historically shouldered a disproportionate share of the environmental damage from refineries and other heavy industry.

Many of the community objections to existing refineries are rooted in historical environmental discrimination whose impact persists to date. 

Black Americans are 75% more likely than other Americans to live in neighborhoods adjacent to refineries, according to a study by the Clean Air Task Force and the National Association for the Advancement of Colored People.

And living near the kinds of environmentally damaged sites that refineries can create can take a year or more off of life expectancy, according to a 2021 study by University of Houston researchers that looked at the impact of Superfund sites on life expectancy. 

Yet lax oversight of regulations for refineries has contributes to the problem. In Philadelphia, The EPA found that the refinery had been out of compliance with the Clean Air Act nine of the past 12 quarters through 2019 prior to its closure, with relatively small penalties.

The Biden administration has acknowledged the need for these communities to share in the economic benefits of heavy industrial projects with its Justice40 Initiative, to at least counterbalance the heavy price they have paid.

And as part of the push for Biden’s big climate legislation, key members in Congress appear to have made commitments to passing permitting-reform legislation later this year that may benefit (and lower the cost of) new refineries.

It’s a start, but more logical and collaborative thinking will be needed by all participants, given that by 2040, EVs are expected to still only make up about one-third of all cars on the road.

All this means that refineries will be necessary for years to come. What is also needed is both vigorous environmental regulatory oversight and a reasonable permitting process, so that both refineries and communities have a fair say in what they can expect.



Short-Term Pain, Long-Term Gain: Inside Baker Hughes’ Vision For The Energy Transition

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Emily Pickrell, UH Energy Scholar

Technology transitions can be really difficult. Consider the small firm that made buggy whips for horse-drawn carriages in the late 1800s just before Henry Ford introduced the assembly line that produced the Model T. 

Now fast forward to the current challenge, and strategic decisions facing the many different players of the energy industry.

Quarterly returns are one way of evaluating how players are faring as they develop their strategies. But the quarterly returns for buggy whips in 1900 would not have been particularly informative about the transformation awaiting the auto industry.

In a recent article in the Houston Chronicle on Baker Hughes and the oil field services sector, energy journalist Kyra Buckley has shown a similar lack of foresight. She has interpreted a difficult quarter for Baker Hughes to mean a bad strategy, especially when compared to its competitors Halliburton and Schlumberger.

On paper, the comparison is seemingly damning. Baker Hughes had a lackluster second quarter return of $5 billion in revenue, down 2% from this time last year.

That’s a lot less than Halliburton’s bumper season. It reported revenues of $5.07 billion in the last reported quarter, a 36.9% increase from this time last year. Schlumberger had revenue of $6.8 billion, a 20% increase over this time last year.

It is certainly fair to point out the impact of the Russia-Ukraine war and our country’s sanctions on Russia. As a result, Baker Hughes’ Russian nonoperating facilities did not help its bottom-line last year. (Baker Hughes reported a nonoperating loss of $426 million related to its oilfield services unit in Russia.) Yet again, this decision does not equal bad strategy, but rather, common sense.

Part of the problem in even making comparisons is to continue thinking of Baker Hughes as a pure oilfield services company, when it is so clearly positioning itself to compete in the technologies that the energy transition will demand.

Right now, Baker Hughes’ bread and butter is oilfield services and equipment, but they understand the future is in energy technology, and climate change and emissions mitigation – and are acting on it.

This kind of mischaracterization of Baker Hughes – and other companies making similar moves – is troubling, because it garbles the metrics by which to measure the progress they are actually making. They have already actively started doing what will be necessary for the others. They are reinventing themselves to meet tomorrow’s energy needs, rather than those of today.

For example, Vikas Mittal raised concerns in Buckley’s article that Baker Hughes has given in to environmental pressure from its investors, rather than focusing on its customers’ needs for oil field services.

“They want to be a technology company, they want to be a digital company, they want to be a socially responsible company, they want to be a net-zero company,” Mittal said. “The one thing they don’t want to be is a service company.”

Yet Baker Hughes’ revenues from its oilfield servicesunit were up 14% from this time last year. That speaks volumes about its consistent commitment to its customers. You don’t do business with non-performers, especially with Halliburton and Schlumberger waiting in the wings.

Mittal’s interpretation of Baker Hughes’ weaker returns – and where to cast blame – also drastically underplays the importance of the need for technology and service in the low-carbon energy system of the future. 

By the end of the year, the federal government will be investing $3.5 billion in the development of direct air capture hubs and the regulators are busily writing the regulations to cover offshore carbon sequestration, an emerging field of opportunities for companies with skillsets like those of Baker Hughes. The government is getting serious about reigning carbon emissions and smart folks in the energy industry are actively responding in kind.

The picture is the same for the future of hydrogen. Again, the feds are planning to invest $8 billion in the development of clean hydrogen, an energy source for which Houston and its energy industry are uniquely positioned for leadership.

The metaphoric roads are being established as we speak for a huge technology leap, and Baker Hughes is positioning itself to be part of that. It recognizes that the same kind of geological and geophysical data will be required for developing these storage sites, for example.  Its services will be needed – desperately needed in the coming years, in a way that greater expertise in oilfield extraction won’t.

The idea that Baker Hughes, Schlumberger and Halliburton are playing the same game is flawed. Schlumberger and Halliburton had a great quarter, benefitting from soaring oil prices – but depending on traditional oil and gas and nibbling around the edges of the energy transition is playing a short-term, tactical game. They are maximizing earnings now potentially at the expense of their future.

Baker Hughes, Buckley rightly notes, is a leader in liquefied natural gas, which is increasingly being seen as a way to export lower-carbon natural gas. Baker Hughes also has a significant investment in advanced technology which will positions it as well for carbon capture, hydrogen and geothermal markets as they develop and grow. 

At the end of the day, the question for oil field services is whether to continue with a tactical, short-term approach rather than a longer-term strategic vision.

Baker Hughes is positioning itself for the future and taking some short-term pain. We shall see how customers and investors respond in the future. Transitions are hard, but it is really hard to buy a buggy whip today!

Hyperpolarization of Climate Policy – The Politics of American Exceptionalism

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Ramanan Krishnamoorti

Ramanan Krishnamoorti, Chief Energy Officer, University of Houston

Aparajita Datta, UH Research Scholar, University of Houston

The breakthrough in negotiations amongst Democrats in the U.S. Senate on the proposed climate bill surprised many and recentered the climate discussion across the nation. If the bill, also known as the Inflation Reduction Act of 2022, passes through budget reconciliation, it could potentially reduce U.S. emissions by 40% by 2030.

Despite the national security, economic and energy independence benefits the bill may lead to, it has not received any support from Republicans. Lawmakers from red states have remained unmoved on climate legislation for decades. The gridlock over climate change is not new but the scale of the legislative paralysis is. The right and the left are more polarized now than at any point in the last 50 years. Consequently, climate change has become a prime example of “American exceptionalism” – the idea that the U.S. is inherently different from other countries – in politics. The hyperpolarization threatens our way of life, the economy and our position as a global leader.

A few recurrent questions emerge in the current landscape. First, what are the limits to powers of the executive, legislative and judicial branches? Most recently, arguments by the Republicans against executive action on climate change were upheld by the Supreme Court’s conservative supermajority in its ruling on West Virginia v. EPA, which limits the agency’s regulatory authority over curbing greenhouse gas emissions from power plants. Interestingly, the view that it is Congress that must pass laws and allocate funding for climate action – and not the President and federal agencies – seems to be shared by a majority of Americans (61%). However, in a Congress of slim majorities, what does this divide mean for policymaking, and is there a rational middle ground for climate change policy in the U.S.?

In March, the U.S. Securities and Exchange Commission (SEC) proposed new climate disclosure rules that would require publicly traded U.S. companies to quantify, record and disclose climate-related risks and financial impacts in statements and annual reports.  The proposed mandate aims to bolster investor confidence by providing accurate information on a company’s financial health and risks in a transparent and consistent format. Shortly after, SEC’s chairperson, Gary Gensler, said in an interview that “climate disclosures are already happening, and investors are already making use of information about climate risks. But there is no uniformity in how climate risk disclosures are made, making it difficult for investors to make meaningful comparisons. Companies and investors alike would benefit from clear rules of the road. Our role is to bring consistency and comparability.”

But Gensler, who was appointed by President Joe Biden, was met with quick opposition from his Republican colleagues. SEC Commissioner Hester Pierce opposed the proposed rules in a public statement titled “we are not the Securities and Environment Commission – at least not yet.”

The SEC invited public comments on the proposed rules between March 21 and June 17, and over 4,400 were submitted. We analyzed the comments using natural language processing (NLP) methods. Members of Congress submitted 14 comments, with 215 Republican and 152 Democrat lawmakers as signatories. We took a deeper dive into these comments through further qualitative and quantitative analysis.

The analysis[1] mapped the most likely topics in a document as a probability distribution. A cursory look at the analysis appeared to show some overlap between Republican and Democrat lawmakers. Although, a closer look at terms that were most likely to appear together like emissions, investor, climate, justice and environmental, revealed the divergent partisan priorities. The terms justice and environmental were not dominant themes in the Republican submissions, while the others highlight the exceptional partisan divide on the issue.

The sentiment and tone of the submissions from the Democrats indicate that they welcomed and supported the SEC’s efforts. However, they also proposed changes, citing that the rules do not go far enough to address material climate-related disclosure, specifically the inclusion of climate-related lobbying and influencing activities. U.S. Senator Sheldon Whitehouse, a Democrat from Rhode Island, called the omission stunning and a missed opportunity for the SEC.

In sharp contrast, Republicans asserted that the SEC lacks statutory authority to issue the proposed rules. The GOP contends that the new rules would violate the First Amendment, do not reflect reasoned decision-making and would fail an arbitrary and capricious review[2] by the courts. Both U.S. House and Senate Republicans argued in their letters to the SEC that unelected regulators at the SEC do not have the authority for policymaking — elected members of Congress do.

Their opinions were reinforced by the attorney generals of 24 Republican states in a supplemental submission to the SEC, citing the post-deadline development of the Supreme Court’s ruling in West Virginia v. EPA and urging the SEC to abandon the proposed rules. Before the ruling, the SEC had found a likely ally in the EPA. In a submission to the SEC, the EPA stated that it supports the proposed rules and the use of the Greenhouse Gas Reporting Program, and that the Commission has broad authority to promulgate disclosure requirements that are necessary or appropriate in the public interest or for the protection of investors.

One notable exception to this political divide was Senator Joe Manchin, a Democrat serving West Virginia. In a letter to chairperson Gensler, Manchin followed themes and sentiments expressed by congressional Republicans. Manchin stressed that he firmly believes that “the SEC has a duty and responsibility to every American to uphold their mission and prevent an unraveling of our U.S. economy; however, that duty and responsibility, unfortunately, becomes tainted when the Commission publishes rules that seemingly politicize a process aimed at assessing the financial health and compliance of a public company.”

With an equally polarized electorate, it is unsurprising that recent analyses from the Pew Research Center found that 82% of Republicans believe that Biden’s climate policies are taking the country in the wrong direction, while 79% of Democrats believe the president is moving the country in the right direction on climate change. The divide prevailed before Biden took office.  A survey conducted by the University of Houston at the outset of the 2020 presidential elections found that a majority of respondents were concerned about climate change and supported emissions reduction, but the devil is in the details. While 96% percent of voters on the left were concerned about climate change, just over half of the respondents (58%) on the right reported the same. While this chasm may seem wide, the gap between right and left voters has been closing in recent years with growing bipartisan support among voters for the adoption of carbon management to mitigate climate change. What voters cannot agree on is how to decarbonize.

While Americans often bemoan the loss of bipartisanship in Washington, D.C., most are willing[3] to forgive undemocratic behavior to achieve their party’s policy goals and prize party loyalty over all else. Political maneuvering and corrosion of democratic processes follow from this: Issues like climate change are framed as zero-sum games — what one gains, another must lose. Consequently, we are left with problems that never get solved. Lawmakers and voters endlessly argue over the winners and losers of each policy proposition, leaving no room for a rational middle.

Meanwhile, the verdict from the reactions to the SEC’s proposed climate disclosure rules is clear. A new manifestation of the exceptional and untenable partisan divide on key policy issues is permeating across all branches of the government. The electorate and politicians have lost sight of the fact that when it comes to climate change, the collective goals of voters are becoming more aligned while the parties simultaneously move apart from the ideological center. In the absence of bipartisan efforts to reach a rational middle, the American exceptionalism in addressing climate change is likely to continue and wild swings of the policy pendulum should be anticipated.

[1] A Latent Dirichlet Allocation algorithm is an unsupervised learning algorithm that maps a user-specified number of topics shared by documents in a text corpus as a probability distribution.

[2] The arbitrary-or-capricious test defined in the 1946 Administrative Procedure Act (APA), which instructs courts reviewing the actions of agencies to invalidate any rulemaking that they find to be “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.”

[3] The study found that only 3.5% of U.S. voters would cast ballots against their preferred candidates as a punishment for undemocratic behavior.

Amid Environmental Concerns, Community Activism Sparks Course-Correction For Port Of Houston’s Project 11

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Emily Pickrell, UH Energy Scholar, University of Houston

Clogged supply chains are bad for business – and the economy, contributing to the recent spike in inflation.

But coming up with environmentally-friendly solutions are also complicated.

For the Port of Houston, increasing its capacity has meant taking on an expensive and time-consuming expansion, called Project 11, which will widen and deepen the Port channel to allow for larger container ships that had previously been routed to other ports. 

The upgrade will have an undeniable economic benefit, allowing the port to double its capacity to process the 3.5 million containers brought in each year. It will also enable the Port of Houston to handle the growing traffic of massive container ships made possible by the 2016 Panama Canal expansion.

It could also lessen regional air quality issues by increasing the efficiency of vessel movements and reducing potential congestion within the port itself. The expansion will produce an initial 3 percent reduction of nitrogen oxides from vessel emissions. By the end of the project, these reductions should reach 7 percent annually, according to data provided by the Port of Houston.

Yet this massive, multi-year construction project will have an initial negative emissions impact on the surrounding communities. A worst-case evaluation of the dredge work estimated that it could increase regional health expenses by $115 million from the resulting deaths and hospitalizations caused by poor air quality. Indeed, air quality-related mortalities were expected to generate roughly 95% of these costs, according to data from Public Citizen, which has actively followed the port expansion.

Finding a mutually beneficial solution has meant input from state regulators, the local communities and contractors for the Port of Houston.

In these discussions, the local surrounding communities – most of which are historically lower-income historically Black neighborhoods – have been active, ensuring that their concerns were part of the planning process. In the last decade, as the plans for the expansion have progressed, they have formed organizations to better represent their interests, including the Healthy Port Communities Coalition and Achieving Community Tasks Successfully. Public Citizen, a nationally-based consumer rights advocacy group, has also been active in encouraging neighborhood participation.

A top priority for local communities has been the reduction of air pollution that would result from the dredging of the busy 52-mile channel to widen it an additional 170 feet. Dredging a port is by definition a messy and polluting task. Dredging equipment exists that is designed to emit less contaminants, but the Port of Houston did not initially require it on its construction contracts.

Nor were they required to do so, neither by the U.S. Army Corp of Engineers, which reviewed the project to ensure that it met Texas’ commitment to the Clean Air Act, nor by the Texas Commission on Environmental Quality, or TCEQ, which also deemed the plan sufficient to meet its own standards.

The TCEQ acknowledged that the project would result in excess nitrogen oxide emissions but said that the state plan could still absorb this excess amount. It instead recommended that the port favor “contractors who proactively limit air pollutant emissions.” It also encouraged contractors to use lower emission vehicles and equipment whenever possible.

The problem with making higher emissions standards optional is that it shifts the burden in making the case for them to the impacted communities.

“The current state of affairs from a regulatory perspective does not adequately address community concerns and impacts,” said Stephanie Thomas, an air quality researcher with Public Citizen who has been involved in community representation with the Port.

Even so, in this case these neighborhood groups were able to successfully encourage the Port to delay its initial award until a company that would use less-polluting equipment could compete. They did so by attending meetings and speaking regularly with the Port. The Houston Port has identified building a stronger community, addressing stakeholder concerns, and promoting justice as among its key priorities in its 2021 ESG Report.

And while these kinds of targets can sometimes feel like boilerplate, Houston Port commissioners also made a point of talking about the importance of environmental justice in response to the tumultuous summer of 2020.  Sharing their priorities with community members also helped talks with local groups.

“It helped open the doors for some of these conversations and the movement we have had for being able to achieve contracts that incorporate things like environmental impact,” Thomas said.

As the Port of Houston began to push its potential contractors for a cleaner solution, Great Lakes Dredge & Dock offered to do a full renovation of one of the dredges and place a scrubber on its equipment that would reduce the emissions significantly. The final contract award included use of efficient equipment that would reduce NOx emissions 38% better than the standard equipment. 

“It pushed back the project but we were okay with that because of the emissions reductions that were going to happen because of the upgrades,” said Trae Camble, the director of environmental affairs at the Port of Houston. 

This kind of negotiating is also being championed by the Biden administration.


“The rules of engagement on environmental justice have changed,” said Tracy Hester, an environmental law professor at the University of Houston. “Under the Biden Administration, the federal government now puts much more emphasis on bringing disadvantaged communities to the table and on avoiding unfair environmental impacts from governmental action.” 

As part of this, Biden established the Justice40 Initiative, which calls for 40 percent of the overall benefits of federal infrastructure investments to be channeled to disadvantaged communities. It made it a priority to increase the benefits and lower the unfair environmental costs that impacted communities have disproportionately shouldered in the past.

And while this initiative came after most of these negotiations, it reflects a new tone and hopefully will help establish a precedent.

It’s a first step to fill the gap between relatively permissive federal and state regulations that still allow disadvantaged communities to bear the lion’s share of the burden in protecting their own interests.

Investment, Environmental and Security Priorities Drive High Gas Prices

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Emily Pickrell, UH Energy Scholar, University of Houston

For many consumers, gasoline prices in the last couple of years have felt perplexing. 

In 2020, they bottomed out at $1.97/gallon at the height of the pandemic. Last week, gas prices hovered around a demoralizing (from the customer perspective, anyway) national average of $4.80/gallon. 

These prices are up 35% from their $3.10/gallon national average this time last summer. They have eased slightly in the last couple of weeks, after hitting a high of $4.95/gallon in mid-June.

Yet it is premature to assume that they will go back to their 2021 range anytime soon. These higher prices, driven by several interconnected considerations, will likely stick around for some time, even though oil prices have fallen from their $123 per barrel peak in March.

The current high price of oil is the obvious main reason for higher gas prices. Global oil production, especially in the U.S., has suffered from insufficient financial investment, as the focus instead shifts on a potential bonanza from the energy transition.

And while higher oil prices are encouraging the return of some of this investment, it is taking some time for investment dollars to end up as barrels of oil, ready for consumption. The disconnect between demand and supply was initially even bigger in the post-pandemic travel spike, but this is expected to normalize in the coming months, with more production coming online.

An aging and insufficient refinery network in the U.S. is an additional culprit for gasoline prices, even as the regulatory climate makes it nearly impossible to bring new refineries online.

Building a refinery is pricey: It costs an estimated $7 billion to $10 billion, and take 5-7 years, not including the time to acquire a site. Strict regulatory and environmental permitting standards are a big part of the reason that refineries are so expensive to build. Expectations that the energy transition will be rapid has likely made these challenges more formidable, even though the full transition to EVs is estimated to take several decades. Currently, EVs make up only 2.5% of vehicles on the road.  

From a refiner’s perspective, this all means that their investment decision only makes sense if the refinery can be expected to operate for several decades.

And this is one of the biggest walls that expanding our domestic refinery capacity is running up against, especially as the transition away from fossil fuel starts to take hold for passenger vehicles.

The belief that refineries may be obsolete in the coming years has essentially discouraged new investment, despite the current price spike for gasoline.

“We have not built a new refinery in four decades,” said Ramanan Krishnamoorti, the chief energy officer at the University of Houston. “The investments it would require are seen as too significant, especially if the energy transition is truly going to be happen and their products are not going to be demanded.”

The same problem has made the current fleet of refineries increasingly difficult to keep online. On the Gulf Coast, some of the refineries that had been operating were more than 60 years old. They had reached a point where the maintenance and upkeep were prohibitive. 

Again, the cost-benefit analysis has to be applied – if a refinery’s lifetime is less than 20 to 25 years, the investment is not considered to be worth it, regardless of today’s gasoline prices.

As a result, over the last three years, the U.S. has shut down about a million barrels of refining capacity, leaving the remaining refineries running at about 95% capacity.

And running at this high level will, in turn, likely lead to future operational issues for the on-line refineries, as it makes preventive maintenance impossible. (Operating at 85% capacity provides better strategies for the long-term health of the refineries.)

Added to domestic refinery constraints is impact on global gasoline supply from the Russia-Ukraine war. The war has effectively forced the European Union to make commitments of removing Russian gasoline from the European market. The EU has already stated it will lower its consumption of Russian gasoline imports by two-thirds in the next 12 months.

Prior to the war, Russia was exporting about half of the 10 million barrels per day (b/d) of crude oil and condensates it produced – and about half of this was going in turn to various European neighbors. 

Europe’s decision to shun oil and refined gasoline from Russia has been a blessing for U.S. refiners, by tightening the global gasoline supply, as Europe increases its demand of imports from the Middle East and other locations.

Some oil analysts believe that the end of the war would bring prices down.

“There’s no question if we woke up one morning and Putin was not in charge anymore, prices would drop precipitously,” said Tom Kloza, global head of energy analysis at OPIS. “That has been a catalyst taking prices horribly higher in the last 90 days or so.”

Meanwhile, the cumulative impact of these forces is showing up in domestic storage reserves. There has been a 20% drop, compared with this time last year.

And while prices have been drifting down in the last couple of weeks, it will be September at the earliest before there is significant movement on gasoline prices. These decreases will be driven first by more oil production coming online, which will cause oil prices to fall. It will also be accompanied by the expected drop in demand for gasoline consumption, as the summer ends. This drop may also be even steeper if the economic indicators of a possible recession turn out to be true.

And, of course, all of this presumes that the Gulf Coast weather will not further complicate the situation. 

“Inventories are down really low right now,” Krishnamoorti said. “One big hurricane, and we will easily surpass six dollars a gallon.”

Can Biden’s Climate Goals Stay On Course Amid America’s LNG Export Growth?

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Emily Pickrell, UH Energy Scholar, University of Houston

The Russia-Ukraine war has reshaped the energy landscape, sending gas prices up and leaving Europe scrambling to disconnect itself from Russian oil.

In the U.S., it is also being used as a justification for expanding our exports of liquefied natural gas, or LNG. In March, the Biden administration discussed energy security concerns before promising to increase liquefied natural gas shipments to Europe. The commitment now stands at 15 billion cubic meters by 2022, with additional increases expected.

The challenge for the Biden administration will be balancing the much greater carbon footprint of LNG relative to pipeline gas with its climate change priorities. The need for this is already being championed by groups like Project Canary, which is pushing private companies and investors to report the emissions impact of their natural gas supplies.

LNG is somewhere between 50% and 200% more carbon intensive than piped gas, according to data from Wood Mackenzie. Its higher carbon intensity – that is, the amount of carbon produced per unit of energy generated – is due to the additional processing and transportation required.

Biden’s environmental goals have been some of the most clearly targeted at reducing the impact of climate change of any administration to date. They have included goals of a 100% clean energy economy and net-zero emissions by 2050. The administration has followed up on these goals with specific targets, such as plans to cut methane emissions 30% by 2030.

“One of the most important things we can do in this decisive decade is — to keep 1.5 degrees in reach — is reduce our methane emissions as quickly as possible,” Biden said in a recent speech. 

It has pinpointed specific ways to achieve these reductions, tightening up regulations on venting and flaring of natural gas, and focusing on leak reductions and abandoned wells as ways to reduce methane leakage.

Yet while Europe’s protection seems like a reasonable justification for approving more U.S. LNG terminals, it is misleading to raise it as the principle driver for growing U.S. production.

Indeed, while the U.S. is working to meet as much of this LNG demand as it can, production had been scaling up long before Russian tanks rolled over Ukraine’s borders. U.S. exports of LNG averaged 9.7 billion cubic feet per day (bcf/d) in 2021, up 50% from 2020. Europe was receiving about a third of these exports in 2021: it averaged 3.3 bcf/d of LNG imported from the United States during 2021, up 32% from the previous year.

The rate of production growth was especially sharp last year, as several facilities finished construction and became operational:  As a result, the U.S. shipped 6.7 bcf/d of LNG to Europe in December 2021, double its average rate for the year.

The U.S. is encouraging the development of more terminals through its permitting process.

The Federal Energy Regulatory Commission, or FERC, recently gave the go-ahead to three LNG and related pipeline projects that had been in permitting limbo: Cheniere Energy’s Stage 3 project in Corpus Christi, Energy Transfer’s Lake Charles LNG project and Gator Express’ pipelines that will support Venture Global’s Plaquemines LNG’s start-up.

The Biden administration is trying hard to both demonstrate that it is taking climate-warming emissions and Europe’s geopolitical energy supply woes seriously. And if these two goals seem contradictory, they are – at least in the short term. 

“It is going to be complicated,” said Tracy Hester, who teaches environmental law at the University of Houston Law Center. “It is becoming apparent that the need for LNG in the short term has caused the energy transition to become much more complicated. It comes down to the fact that the expedited delivery of LNG to Europe has become a higher priority.”

Policy options for Biden in dealing with problematic methane emissions, Hester said, is to emphasize regulatory oversight that make methane as clean as possible, while still continuing to emphasize that natural gas is not a long-term answer to climate change issues.

At the same time, communities are also expressing concerns about these big LNG projects and their impact on neighborhoods.

For example, Save the Rio Grande, a Texas-based environmental coalition, has raised concerns about both the extraction of natural gas and the environmental cost of the LNG processing facilities, noting that “large-scale air emissions of 2.5 particulates, NOx & VOC’s is not in the public interest” in an April 27, 2022 letter to the Federal Energy Regulatory Commission.

A recent explosion at the Freeport LNG Facility on Texas’ Gulf Coast illustrates the validity of these kinds of concerns.

Protests are starting to focus around the long timeline for new LNG investments. Save the Rio Grande has pointed out that the not only will the new LNG facilities will essentially lock in 25-30 years of associated emissions.

And it is the high cost of building the facilities that will inevitably end up justifying the need to keep them running for decades, if only to recoup the amount spent on their construction.

For example, an LNG project under construction near Lake Charles, Louisiana is expected to cost energy company Tellurian more than $27 billion in construction and associated infrastructure costs. Shell and Energy Transfer are working on an export terminal to complement existing gasification and import facilities – with a price tag of somewhere between $12 billion to $16 billion.

“Once you start supplying Europe LNG from the US, those suppliers that engage in that activity are not going to be very willing to retrench at a later date,” said Pablo Pinto, director of the Center for Public Policy of the University of Houston’s Hobby School for Public Affairs. “Investing in LNG means developing an infrastructure that relies on hydrocarbons, even though you say you are trying to move away from them.”

None of this is to detract from the reality that the projected LNG growth over the next decade will be essential for global economic growth, especially for Europe.

Yet what will also be essential for the planet’s future climate conditions will be identifying pathways to reduce its carbon intensity.

As Guyana’s Oil Business Booms, Could A New Deal With Exxon Loom?

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Emily Pickrell, UH Energy Scholar, University of Houston

The tiny South American country of Guyana has been transformative for Exxon Mobil Corp. in the last decade, after the oil titan made the first of a series of gigantic discoveries just off its coast.

As the country moves into its new role as a prolific oil producer, it’s time for it to now take the helm in managing these relationships.

Indeed, its current arrangement with Exxon and partners — Hess and Chinese CNOOC — reveals the story of a country that was new to the game and inexperienced in negotiations several years ago. 

This team first found oil in Guyana seven years ago and has since made an astonishing 18 oil discoveries in its giant Guyanese Stabroek block.

These discoveries contain generous fossil fuel wealth: nearly 11 billion barrels of recoverable oil and gas potential and counting, following the latest spate of new discoveries in April. Exxon and its partners have invested more than $10 billion in production and plan to pump 1.2 million barrels of oil and gas per day from the block by 2027.

The challenges in discovering this oil should not be discounted.

Before 2015, offshore Guyana was considered a high-risk frontier basin, despite its potential. Since 1965, 45 wells had been drilled in attempts to find the sweet spot of success – and failed. It took Exxon’s technical genius, confidence and financing to finally hit the jackpot.

Even so, the resulting 2016 terms on how to share this production has been controversial, as it is more generous to Exxon than what many of Guyana’s peers have agreed to.

The current contract was negotiated in 2016 and takes most of the terms of a 1999 agreement. It splits the oil output at 50-50 between the government and Exxon, and gives Guyana a 2% royalty (the 1999 agreement had a 1% royalty). The oil split reflects the costs and risks a company faces in any particular project and can vary significantly from country to country, and by contract. In this light, a 50-50 split for a new producer is not especially unusual.

But it is the additional terms in the agreement where Exxon really benefits, according to Tom Mitro, a former Chevron executive with decades of experience negotiating international contracts. Mitro is also a former director of the University of Houston’s Global Energy, Development and Sustainability program.

Mitro pointed out that for the many other negotiable clauses in the contract, they were established in favor of Exxon – an approach that most of Guyana’s peers have not agreed to.

For example, one provision allows Exxon to recover all interest on loans borrowed to fund the development of related oil projects.  In practice, this means that the operator and its partners are able to charge Guyana for the cost of borrowing from their affiliates with no limits. 

“Contracts typically have cost recovery mechanisms, but usually with limits,” Mitro said, explaining that without written limits, companies can abuse the amount of borrowing they do within the conglomerate.

Another provision allows Exxon to not have to pay any income tax on their profit share, and that the government will provide a receipt that can be used for tax deduction purposes elsewhere.

There is a clause that allows Exxon the right to get cost recovery oil right from the beginning, to cover the future decommissioning and abandonment of the project at its end. These costs will not be actually incurred for several years. 

“In this case, the government is giving Exxon something of value – oil – to cover Exxon’s future costs,” Mitro said, noting that it is unusual to pay upfront for a future expense because of the recognized time value of money.

While Exxon’s experience and deeper knowledge of contracts likely strengthened their negotiating position, on Guyana’s side, domestic politics also played a role in the deal cut. The negotiations came just before a contentious election, and the promised revenue was advertised as offering a better future for Guyana.

It also came right before Exxon publicly announced that results from a second exploratory well indicated that Exxon would recover more than twice the amount of oil it had originally expected.

In retrospect, the biggest challenge for Guyana is the extremely short time frame for its transition itself from a non-oil producer to one with reserves rivalling Mexico or Angola. And to be fair, it has been Exxon’s vision which has led this change, with its 2015 discovery of Guyana’s oil and its subsequent investment in bringing that oil to market.

The oil and gas industry rewards risk and technical experience. Exxon displayed both of these brilliantly, making a huge deepwater exploration gamble with no assurance of success in a country with no history of oil production.

Exxon has justified the contract by saying that the terms reflect those for a country with no track record and thus higher risk, which is reflected in the terms of a production sharing agreement.

“It offers globally competitive terms,” said Exxon spokesperson Casey Norton, in a 2020 interview with the Wall Street Journal. “It was done at a time where there was significant technical and financial risk.”

Julian Cardenas, an energy law professor at the University of Houston, agrees, noting that Guyana is now in a better position to negotiate better terms with future investors because of its track record of its geological potential.  

However, potential is no longer everything in the international oil game, as Venezuela well illustrates.  Guyana’s ability to attract future investment will depend on its demonstrating that it will honor its contracts and the rule of law. 

“Guyana needs to take responsibility for those deals, recognizing that these deals also have an end date,” said Cardenas. “Of course, there is always room for improvements and mutual renegotiation. But this won’t be Guyana’s only opportunity.  They will be much better served by focusing on offering new rounds and making better deals.” 

Indeed, both sides have already benefited from the new-found oil.

Exxon began production in late 2019 and now pumps roughly 220,000 barrels of oil per day in Guyana, roughly 6% of its global production. The company says the production has created jobs for more than 3,500 Guyanese. The Exxon consortium and its direct contractors are also spending more than $200 million on local suppliers each year. Its current deal is expected to bring in nearly $170 billion in revenue in the years ahead.

It’s a position that many in Guyana also hold, as the country tries to find the balance between being seen as an attractive investment location and making sure it is not Big Oil’s stooge.

“Recall that when the 2% royalty was agreed, we had just discovered oil and had still not produced a drop,” wrote Donald Singh, a process coordinator at Guyana Geology and Mines Commission, in a 2019 letter to editor of the Guyana Chronicle responding to criticism of Guyana’s low royalty percentage. “Guyana’s exploration success certainly merits a raise in royalty rates, but I think we must proceed with the goal of establishing a track record as a reliable producer.”

On the other hand, that was two years ago, and now Guyana is looking like a major contributor to Exxon’s bottom line.

It’s a good time for both sides to think about the long term. Guyana could, for example, identify the points in the current contracts where government approval is required, and use that to tweak terms that some see as unduly favorable to Exxon at Guyana’s expense, such as gas flaring rights.

From Exxon’s side, its reputation would be well served by doing its upmost to support Guyana’s ability to develop into a more mature oil nation – one that is known for its ability to balance its desire to do business with the needs of its people, for their long-term benefit.

Europe’s Warm Embrace of LNG Raises Methane Emissions Concerns

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Emily Pickrell, UH Energy Scholar, University of Houston

Europe is desperately seeking more natural gas imports in the name of national security but is scrambling to explain how this production fits into the global need to reduce damaging methane and greenhouse gas emissions.

It’s a good example of a growing issue: how energy resources may meet immediate national economic and security needs, yet could disrupt long term climate change goals.

Europe’s interest in more LNG imports is logical. Its dependence on Russian gas has become unworkable, given the current Russia-Ukraine war. While Europe has worked hard to tout its interest in renewable energy, Putin’s threat to Europe has provided a security justification to explore alternative pathways to import gas. 

Russia currently supplies (by pipeline) about 40% of Europe’s natural gas demand, with few readily available alternatives. The European Union has been vocal about its need to replace Russian fossil fuels and has introduced its RePowerEU plan, which will focus on increasing energy efficiency and clean energy use. In doing so, it hopes to cut Russian oil and gas imports by two-third this year and the remaining one-third by 2027.

But the bulk of the remainder will be made up for with gas from LNG. Though expansion of pipelines from Spain could also ultimately allow more natural gas inflow in to Europe, Europe must have immediate replacements that can come online now and in the near future.  For this plan to work, Europe will need to make huge infrastructure investments in regasification facilities, and this may factor into a huge greenhouse gas emissions increase, including methane.

European officials have already started to acknowledge how damaging these methane emissions can be. The global warming potential of methane is estimated to be more than 80 times that of carbon dioxide in the first 20 years after it is released, according to the International Energy Agency’s Methane Tracker website.

Even after 100 years, it is still about 30 times more potent than carbon dioxide molecules. And while methane emissions come from many source – agriculture, for example – the emissions coming from the energy industry have technology solutions, such as leak detections or ending the practice of venting gas.

Looking at how LNG compares to Russian gas’ dismal environmental footprint does not provide much comfort that Europe will be able to reduce global methane emissions by this change.

It’s true that Russian gas from Gazprom is notoriously dirty: the Russian natural gas production involves high methane emissions. Russia’s oil and gas industry emitted 18.3 million tons of methane in 2021, exceeding the 17 million tons emitted by the U.S. or the 4 million tons of methane emitted by European oil and gas production.

Yet LNG is dirtier.

In a direct comparison, even the relatively clean LNG from Qatar or Australia emits between 60 to 175% more gashouse gas emissions than Russia’s natural gas. U.S. gas is even worse, because of the high fugitive methane emissions that occur in production and processing.

LNG does better in a head-to-head comparison with coal. Using LNG in power plants can reduce emissions 40% to 100% from coal power, depending on how the LNG was produced and shipped, as well as the quality of the coal and the methods for mining it.

Prior to the Ukraine invasion, Europe had already begun to try to address the need to reduce methane emissions. In 2020, the EU’s Methane Strategy was published. This strategy proposed more accurate measurements and reporting as a place to start.

“The existing systems we have for collecting and reconciling methane data do not allow us to identify with high precision where emissions happen, and in what volumes,” the European Commission wrote on its website, explaining its proposed reduction methodology. “Every chance to reinforce our capability to have good, independent, reliable numbers will translate into more focused, better-targeted actions.” 

The strategy details plans to tally methane emissions from all sources, including natural gas imported into EU countries. Europe’s Green Deal, a set of policy initiatives designed to make the EU climate neutral by 2050, also has methane provisions.

It includes plans for requirements for better reporting, obligations to improve leak detection and repair and establishes rules to eliminate routine venting and flaring.

In the COP26 climate summit, European leaders were vocal about others following their lead: they pushed hard for a 30% reduction in methane emissions from 2020 levels by the end of the decade.

Now, in light of the war, the situation is looking more complicated, and there are now seven LNG facilities under construction and 26 more planned, as Europe gets more aggressive about moving away from Russian gas.

“I do think that security has trumped climate concerns in Europe, and there seems to be no role for Russian gas in the future without major geo-political changes,” said Victor Flatt, the co-director of the Environment, Energy, and Natural Resources Center at the University of Houston Law Center. “Being addicted to Russian oil and gas is a big, big problem. In that sense, security trumps climate, at least for now.”

Europe is attempting to balance this projected LNG growth with more offshore wind and other renewable projects.

Yet Europe’s decision to invest in LNG could undermine its own methane reduction commitments, especially since the significant investment made will tend to justify continuing these operations for decades to come.