Energy Transition Part IV: The Role of Fracking and EOR

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Editor’s note: This is the final article in a four-part series Oil and Gas Investor is featuring with Kenan-Flagler Energy Center at the University of North Carolina (UNC) at Chapel Hill. Read parts one, two and three here.

In May 2021, the Biden administration began showcasing its climate agenda. The agenda’s centerpiece, a “clean electricity standard” (CES), calls for elimination of all greenhouse-gas (GHG) emissions from the U.S. power sector by 2035. Some, especially the utilities charged with carrying this out, would call this plan far-reaching, even radical. But it proved too timid for a coalition of environmental groups, who sent the administration a letter protesting the plan’s half measures. As reported in Politico, the letter advocated as follows:

“More than 600 groups sent a letter to Congress … warning that a CES would promote ‘false climate solutions’ such as natural gas, nuclear and biomass power plants, as well as efforts to keep polluting plants open by capturing their carbon. The dissenters instead called for a stricter renewable electricity standard limited to wind, solar and geothermal power, not only to accelerate the deadline for a zero-emissions grid from 2035 to 2030 but to avoid perpetuating the deep racial, social and ecological injustices of our current fossil-fueled energy system …

“The dissenting groups—including Friends of the Earth, the Center for Biological Diversity, 350.org, the NAACP and Food and Water Watch—say that no plan would be better than a flawed plan that values political viability over scientific necessity and could help prop up natural gas.”

It is of course possible that this effort is largely one of political tactics. Strong protests out on the extremes can make even a radical plan seem moderate by comparison. However, for the sake of gaining some clarity about achieving an energy transition that might be feasible, let us take this environmental position at its word. What does this protest letter say about green plans for transition, and what are they missing?

Clearly the letter rests on a belief that is turning out to be one of the biggest obstacles of climate progress—namely, that wind, solar and battery storage can bring about anything close to zero emissions. This proposition, infeasible in the U.S. power sector, is inapplicable to vast sectors such as aviation, heavy transportation and heavy industry, and largely irrelevant to the global economies producing the most GHG emissions; as such, it blinds its advocates to the difficult tradeoffs which a feasible transition will require.

The importance of facing up to tradeoffs and even embracing those that make climate sense can be illustrated via two unexpected topics: the contributions of fracking and EOR to a successful energy transition. The transition faces submerged reefs which likely will delay and undermine its progress. It turns out that fracking and EOR are two solutions, that could help avoid these reefs as the transition unfolds.

How can it be that perpetuating two forms of fossil fuel development will further climate progress? The answers have to do with three important dimensions of a feasible transition:

• Getting “from here to there” without major distracting disruptions;
• Decarbonizing the Eastern Hemisphere growth economies; and
• Helping carbon capture technologies be proven at scale, enabling their broad deployment.

The first two pertain to fracking while the third will develop on the back of EOR. Let’s discuss how these dimensions may play out within scenarios where fracking and EOR are either enabled or suppressed.

Getting from ‘here to there’

Many statesmen have commented that “events” presented their biggest obstacles. This is another way of saying that the best-formulated plans often go out the window when major crises unfold.

The energy transition is especially vulnerable to event disruption. This is true because the transition will take a long time to carry out. Despite calls for emergency action by 2030 or 2035, most considered plans use 2040 and beyond as the horizon for reaching net-zero emissions. Also consider that many plans concern only components of the broader U.S. economy and not those sectors with the most intense carbon footprints. A feasible transition in the developing world will take even longer.

The transition’s Achilles’ heel is that this long timeframe requires stable, even tranquil conditions for implementation. Crises that threaten life in the “here and now” hold considerable potential for interrupting transition focus. Texas got a dose of this in February 2021, when frigid temperatures resulted in power outages for days across the state. Wind and solar power dropped dramatically, and natural gas was called upon to pick up the slack. Regulators across the country took note. Many are unlikely to support driving natural gas from their power generation stacks anytime soon.

The list of events that could disrupt the transition is long, but these three would be near the top:

• Electric power price inflation;
• Geopolitical disruptions resulting in peak oil prices; and
• Grid power outages, which highlight renewables intermittency risks.

Fracking’s recent contributions to containing these risks have been huge. Allowed to continue without regulatory suppression, these contributions can facilitate the sustained focus on low-carbon solutions that’s needed to progress the transition.

It goes largely unrecognized that fracking allowed renewables to enter power generation without driving up electricity prices in a way that would have invited blowback.

Fracking for natural gas began in earnest around 2009 to 2010 in Texas and Louisiana. It received a second leg with the development of the prolific Marcellus Shale and a third leg as producers developed unconventional oil plays such as the Permian Basin. These plays yielded immense amounts of associated gas. As a result, natural gas prices began a decade-long decline, which ultimately totaled a 63% price cut. It was during this same period when wind and solar were introduced into power grids at scale. Much has been written about how their costs declined over the period as technology and supply chains improved. This literature largely ignores how declining natural gas prices masked the higher costs of early stage renewables projects and canceled out the unrecognized costs of intermittency, grid integration and the forced retirement of plants with existing economic life.

Today, natural gas prices have risen to more than $5 per million Btu. This shows the other side of this equation. With fracking suppressed by first the COVID-19 shock and then the acute anti-fossil fuel hostility rippling through Wall Street and Washington, U.S. gas production is down.

Drilling has been slow to respond, and gas inventories are well below normal levels. Depleted gas inventories and soaring prices are even more conspicuous in Europe and Asia. Price inflation, partly driven by higher energy prices, is elbowing its way toward the top of national political agendas. It would serve being able to sustain the transition focus if the U.S. fracking industry could resume development, produce more oil and gas in the “here and now” and enable the vast set of issues surrounding long duration storage, nuclear, hydrogen and carbon capture to progress without “look what a mess you’ve made” political blowback.

Geopolitical events that produced an oil shock would be a second disruption. Examples include events such as the 1973 Arab-Israeli war and the later Iraqi invasion of Kuwait. Such events force their way to the top of the national agenda by igniting oil price spikes and threatening key American allies. Despite decades of working on energy security, Japan and most of Europe remain dependent on Middle East oil.

Until recently, the U.S. was similarly exposed. Fracking changed that. From a situation where U.S. production totaled only 5 MMbbl/d and was judged in irreversible decline, fracking took oil output to a record 13 MMbbl/d in 2019. That made the U.S. the globe’s largest oil producer. Because much of the fracked oil is light crude, the U.S. also benefited from an oil arbitrage—exporting millions of barrels a day of quality oil while importing lower-grade heavy crude suitable for processing in complex Gulf Coast refineries.

The result was a dramatic drop in U.S. exposure to Middle East oil disruptions. This was demonstrated when Iranian missiles damaged important Saudi oil infrastructure. U.S. oil and stock prices barely reacted. It was more fundamentally at work when the Trump administration imposed severe sanctions on Iranian oil exports. These subsequently dropped below 1 MMbbl/d with barely any response in oil prices.

These results resemble what used to happen when the U.S. served as the market’s reserve supplier prior to 1970. In a sense, fracking is even better suited for this role. Fracking can surge production in a relatively short amount of time. There is no exploration required or no complex offshore platforms to fabricate. The industry needs to mobilize rigs and drill. It can do so in multiple basins including the Permian, Eagle Ford, Bakken and Utica shales. Unconstrained, U.S. fracking can insulate the U.S. economy from supply shocks, price shocks and even from the need to intervene in the Middle East to protect its allies.

Major electric grid supply disruptions constitute the third potential transition disruption. The third article in this series showed what such events look like when it presented the chart of power generation by source during the February 2021 Texas freeze. That event lasted more than 10 days. Wind and solar power declined to negligible contributions. Such battery storage as existed was quickly depleted with little chance to recharge. Though it too was ultimately impacted, natural gas generation not only picked up the slack but serviced much of the load demand surge that frigid weather induced.

The Texas event and outages in California point to several disruption risks. The most obvious one is that renewable power cannot be counted on in the face of prolonged weather events. The less obvious but equally concerning issues are the ability of evolving generation stacks to “load follow” and the amount of reserve capacity maintained in the system. Both California and Texas have been driving fossil fuel plants from their system and accepting the consequences in the form of reduced reserve capacity. In both states, natural gas plants constitute the bulk of the in-state system’s reserve power and its ability to respond quickly to shifts in load demand.

“The challenge of decarbonizing the Eastern Hemisphere is rooted in two conditions. First, much carbonin-tensive heavy industry has migrated from the developed world to this region. Secondly, the region lacks indigenous natural gas supplies.”

Getting “from here to there” in the transition requires avoiding repeated grid failures like those in California and Texas. Residential customers and businesses expect that electricity be available when they want it. Moreover, they will not quietly accept price surges like those that overwhelmed many in the wake of the Texas freeze.

Market design and other issues were involved here, but what is fundamental across all markets is the need for adequate power reserves that can respond to demand and handle severe shocks. This will require plentiful natural gas power generation for the foreseeable future, and those plants will need to be backed by abundant natural gas supplies flowing through adequate logistical infrastructure.

This means the grid needs to be backed by fracking that assures plentiful supplies at reasonable prices. Tight supplies and volatile prices plus inadequate reserve power and growing intermittent generation is a recipe for disruptive events, political blowback and a halting transition.

Decarbonizing the Eastern Hemisphere

A chart, published by the Union of Concerned Scientists, illustrated the CO₂ emissions by country in 2019. There are a couple of things that were highlighted: U.S. emissions combined with those of major European countries plus Canada and Japan comprise only 26% of the total. That is less than China alone. Add India, Brazil and the rest of the developing world to China’s total, and it’s clear that the vast majority of the CO₂ emissions issue resides in the developing world economies.

A CO₂ emissions international monetary fund chart from late 2019 (pre-COVID) showed actual 2018 GDP growth figures for the developed and developing economies as well as late year projections for 2019 and 2020. Both actual and forecast data show the developing world growing at twice the pace of the developed economies.

The charts dramatize two points: the carbon intensity of developing nations and their higher economic growth rates. Together these points underscore where the decarbonization challenge resides. It lies in the developing world and especially in the high-growth economies of Asia.

The challenge of decarbonizing the Eastern Hemisphere is rooted in two conditions. First, much carbon-intensive heavy industry has mi grated from the developed world to this region. Secondly, the region lacks indigenous natural gas supplies. This means that Asia’s surest means for rapidly decarbonizing, substituting natural gas for coal-fired generation, is hard to accomplish there. It also means that industrial demand for natural gas competes for supplies with power generation.

Solving Asia’s decarbonization puzzle will require hybrid contributions. China’s aggressive adoption of renewables, electric vehicles and nuclear power illustrates this formula. However, there is little doubt that ample supplies of LNG are an essential part of this effort. All the grid resiliency and load following arguments apply in these markets; indeed, they are more consequential for locations where demand grows rapidly and industrial uses figure prominently.

The Asia decarbonization challenge powerfully illustrates how the feasible transition requires sustained focus and a tranquil international environment. All of these economies are very dependent on imported energy. China currently imports over 10 MMbbl/d of oil along with large quantities of LNG. India, Japan, Korea and the others are in comparable shape. Any oil and gas supply shock will resonate profoundly in these markets. What was said above about fracking’s role in preventing such shocks applies with even greater force to Eastern Hemisphere economies.

If we assume for now a tranquil supply environment, fracking can then make a second contribution to the Eastern Hemisphere transition. That contribution involves the U.S. having become the globe’s marginal supplier of LNG. Much of Asia’s LNG imports come from the Middle East, especially Qatar. Other supply points include Australia and Papua-New Guinea. However, the prices charged by these suppliers are increasingly influenced, if not set by, exports coming out of the U.S. Gulf Coast. Since 2015, the U.S. has built a considerable LNG export capability, with more capacity on the way. These supplies go in all directions, to Europe, South America and Asia through a widened Panama Canal. U.S. exporters thus “swing” their supply destination to capture the best ‘netback’ price realizations. In the process, they increasingly act as both the market’s marginal supplier and its global price setter.

This surging export capacity came into being because fracking produced such a surplus of natural gas. As documented above, U.S. natural gas prices fell dramatically during the 2010 to 2019 decade. Producers realized that better margins were available from shipping the gas abroad; export projects soon followed, especially when the Trump administration began to fast track regulatory reviews. Soon, global LNG prices began to retreat. LNG contracts, which formerly were both long term and linked to oil prices, began to shorten and to price off U.S. spot gas prices. Asian customers saw their import costs, which often had reached $15 per million Btu, fall by 50% or more.

The beneficial decarbonization effects of U.S. LNG exports are now in danger of plateauing. U.S. gas production reached over 96 billion cubic feet per day (Bcf/d) in 2019. Production then fell below 90 Bcf/d in 2020 and has yet to return to 2019 levels. Moreover, the steady decline in conventional U.S. gas production combined with the rapid declines characteristic of fracked wells means that aggressive U.S. fracking activity will be required to rebuild production and underpin continued LNG export growth.

This all adds up to a choice for the U.S. It can acknowledge the contributions fracking is making to preserve a stable international supply environment and fostering growing, affordable LNG supplies into Asia. Or it can suppress fracking to “avoid fossil fuel dependence” and watch China, India and others build even more coal power plants.

Carbon capture and EOR

Limiting the number of Eastern Hemisphere coal plants, as worthwhile as that is, will only contribute to a feasible transition there. Many other inputs will be needed. These will include carbon capture utilization and sequestration (CCUS). CCUS will need to be that “second pathway,” i.e. the way in which hard to replace existing assets with big carbon footprints will be able to stay in operation and still participate in the transition.

CCUS is at present an “infant industry.” Annual global CO₂ emissions currently run around 35,000 million tons (MMton), while true CCUS captures only 8 to 10 MMton/year (this ignores 20 to 30 MMton/year of CO₂ separation from natural gas, which involves taking CO₂ out of the ground and then returning it). On the other hand, there is a broad consensus among those studying decarbonization that massive CCUS will be needed to achieve a 2 degrees Celsius future. The average CCUS contribution among 12 studies on the subject sees a need for CCUS to capture 7,900 MMton/year by 2040. Nowhere will this need be greater than in the Eastern Hemisphere, where stationary CO₂ sources in industries such as steel and cement are concentrated.

How can CCUS progress from an infant industry to a world-scale transition contributor? There is a process involved here. Most CCUS know-how is concentrated in the oil and gas industry. For years, these companies have separated CO₂ from the natural gas they produce. They also understand how to ship CO₂ and store it safely in underground reservoirs and saline formations. Until now, these companies have been ambivalent about committing capital to CCUS deployed for decarbonization. That recently has changed. Persistent activism has refocused industry attention on moving from research to project development. This was a vital first step.

The second step involves demonstrating better capture technologies at scale. Existing capture technologies are expensive. The best proven technology for use in power plants is aqueous amines. It is capital intensive and power parasitic, meaning it requires considerable energy to work. For example, the thermal efficiency of a 550-megawatt coal plant drops from 40.7% to 32.5% when amines capture is installed. Another way to think of this is that each ton of CO₂ captured this way costs about $70 per ton.

Better technologies are in the works, but these will require firms willing to bear first-of-a-kind project risk. This is where EOR comes into play. EOR using CO₂ offers CCUS pioneers the opportunity to deploy new capture technologies in circumstances offering reasonable return prospects. Consider these economics. Today you can capture CO₂ via amines technology, incur a $70 per ton cost and then incur added costs of $10 to $20 per ton for shipping, sequestering and long-term monitoring/reporting. For this, the 45Q tax provision will compensate up to $50 per ton, assuming you have tax capacity to use it. These economics don’t work and as a result, fewer projects have proceeded on this basis.

Now consider the economics of CO₂ EOR. At present, Permian Basin EOR operators are paying ~$25 per ton for CO₂. They inject slightly above half a ton to extract a barrel of oil. With prices in the $60 to $70 range, that leaves ample margin to support other operating costs and returns on capital. Indeed, these Permian operators are looking for more CO₂ supplies at such levels.

What about the economics for new potential suppliers? With $25 per ton of sales revenue and a $35 per ton 45Q tax credit, they are closer to breakeven with amines capture and logistics costs. With better capture technology and/or a higher CO₂ value, these suppliers could be looking at decent margins. Integrated economics, i.e., margins for an EOR producer who also captures the CO₂ from elsewhere in its system, can be even better.

The point here is that EOR-tied projects are likely to be the proving ground for America’s emerging CCUS technologies. CO₂ EOR revenue plus $35 per ton 45Q tax credit will beat $50 per ton credits at offsetting the costs of capture plus logistics and sequestration underground.

The third stage in this process is large-scale deployment. This will involve adoption of a leading capture technology, the construction of CO₂ trunk lines and the development of both EOR and sequestration sites. The U.S. is uniquely endowed to lead in these areas. It has the technology developers, the logistical know-how, the EOR opportunities and most of all, the underground storage to develop CCUS at scale. As the U.S. provides and deploys better capture technologies, it can then transfer these capacities for applications elsewhere, especially in the Eastern Hemisphere.

EOR projects are thus essential to this process of CCUS technology adoption. Interestingly, CO₂ EOR on its own tends to be emissions beneficial. There are two ways to look at this. Environmental groups will draw a ring around the EOR process. They will ask, within that ring, how much CO₂ is captured versus re-released?

Within this framework, it takes 7,000 to 15,000 cf of captured and injected CO₂ to produce one additional petroleum barrel. The breakeven CO₂ injection level is 10,000 cf, i.e., using more than 10,000 cf of captured CO₂ to produce an additional petroleum barrel is carbon negative. Below a 10,000-cf injection rate, CO₂ EOR is thus slightly carbon positive.

A shorthand way of framing this equation would be that 1 bbl of petroleum releases 0.43 tons of CO₂ when combusted. Typical EOR CO₂ will inject at least 0.5 tons of CO₂ to produce that barrel. Thus CO₂ EOR tends to be carbon negative on its own.

The more rigorous approach assumes that petroleum demand is exogenous and a given in the short run. On this basis, assume that EOR employs 0.5 tons of captured CO₂ to produce one additional barrel. However, that plus production backs another barrel into the ground elsewhere, most likely in Saudi Arabia. The Saudi barrel, if produced, was fully carbon positive. Thus, on a net basis, CO₂ EOR benefits the global atmosphere by avoiding production of an incremental barrel that is produced with no capture.

Considering both the past and likely future contributions of fracking and EOR, we conclude with this: it is shortsighted and counterproductive to advocate that any activity involving continued production of oil and gas will impede the energy transition. The feasible transition will take decades. It will require tranquil international conditions to avoid crises that elbow their way to the top of national agendas. Oil and gas supply and price shocks are the opposite of what the feasible transitions needs to progress.

Finally, the feasible transition will require practical steps to decarbonize the emission-heavy Asian economies. This will require both a growing and affordable international LNG business and the development of CCUS as a viable option for otherwise hard to decarbonize sectors.

Robust fracking activities and EOR projects are vital to developing and sustaining these conditions. A failure to recognize and accommodate these essential facts will result in unintended consequences that will only disrupt and delay the feasible transition.

Stephen Arbogast is the professor of the practice of finance and director of the Kenan-Flagler Energy Center at the University of North Carolina (UNC) at Chapel Hill.