The challenge of negative emissions

The XPrize Foundation was set up in 1994, offering a cash prize to reward innovation in spaceflight, but since then it has broadened its remit to address more earthbound concerns. Prizes have been offered for technological progress in several energy-related fields, including one for recovering spilled oil from the sea, and another sponsored by Royal Dutch Shell for deep water exploration. This week Elon Musk offered the most generous XPrize yet: $100 million for successful innovations in “carbon removal at gigaton scale”.

Negative emissions technologies that take carbon dioxide out of the atmosphere are crucial components of many scenarios for meeting the goal of the Paris Agreement to limit global warming to “well below” 2°C. Wood Mackenzie’s latest 2°C scenario projects carbon removal capacity rising from just 50 million tons of CO2 a year in 2020 to 5.8 billion tons a year by 2050. Most of that is captured emissions from power generation and other industries. But a significant proportion of it comes from “nature-based solutions”, such as restoring forests and wetlands, and from direct air capture of carbon dioxide.

Direct air capture (DAC) is a technology that is attracting growing interest. Occidental Petroleum is developing the world’s first industrial-scale DAC plant, in the Permian Basin, in partnership with a company called Carbon Engineering that has Oxy, Chevron and Bill Gates among its investors. The CO2 will be used for enhanced oil recovery, making it possible for Occidental to say the emissions from its crude have been offset by carbon sequestered in the reservoir. The company is already storing about 20 million tons of CO2 a year, and its Oxy Low Carbon Ventures unit announced last month that it had delivered the industry’s first cargo of “carbon neutral oil”, a sale of 2 million barrels to Reliance Industries of India.

The problem is that DAC remains very expensive. Its near-term cost has been estimated at US$230-US$266 per ton captured: a level well above even the highest carbon prices in effect today. With California’s Low Carbon Fuel Standard credits and the 45Q US federal tax credit, plus the value of the CO2 itself, Occidental’s project has been reported to bring in $250 per ton, with a cost less than that. That cost is probably still too high for large-scale deployment to be viable, however. The Wood Mackenzie 2°C scenario envisages a carbon price of about US$100 per ton in 2050, meaning that DAC would either need more targeted support, or for its cost to fall significantly.

That is where Musk’s XPrize comes in. To win the competition, teams must demonstrate they have a negative emissions solution, such as DAC, nature-based projects, or anything else, which can “economically scale to gigaton levels”. The goal is to find solutions that collectively can go well beyond the 2°C scenario and remove 10 billion tons of CO2 from the atmosphere each year by 2050. After 18 months, the 15 most promising ideas will be given US$1 million each to help them build full-scale demonstrations, with a grand prize of US$50 million for the ultimate winner. “Whatever it takes,” Musk said. “Time is of the essence”.

The XPrize has had some success in spurring innovation. SpaceShipOne, the winner of the first prize, was the first private sector spacecraft, and the forerunner of the SpaceShipTwo used by Virgin Galactic, which was aiming for a test flight on Saturday. Offering a prize is no guarantee that there will be a winner, however. The US$20 million Google Lunar XPrize, for a private sector moon landing, went unclaimed.

Projects for capturing and storing CO2 from power plants and other industrial sources today require prices of US$35-US$120 per ton to be viable, according to Wood Mackenzie’s latest overview, making them generally look much more competitive than DAC. And even those projects face challenges. The Petra Nova plant in Texas suspended operation as of August 2020, and will be shuttered indefinitely. There are big questions of policy and market design, as well as technological innovation, that will need to be solved if the carbon capture is to grow at the pace that will be needed to achieve a 2°C goal.

Meanwhile, Musk’s commitment to carbon reduction seemed appropriate this week, given his new enthusiasm for Bitcoin. It was revealed in Tesla’s annual report for 2020 that the company had invested US$1.5 billion in Bitcoin, and expected soon to begin accepting the cryptocurrency as a form of payment for its products, “subject to applicable laws and initially on a limited basis”. New analysis from Cambridge University suggests Bitcoin uses more power than the entire country of Argentina.

President Biden’s energy policy meets resistance

President Joe Biden was also talking about encouraging low-carbon energy innovation this week. The Department of Energy announced $100 million in funding for “transformative clean energy technology research and development”, via the Advanced Research Projects Agency-Energy. The money is intended to support technology that is “so high-risk that it can’t get support, but so potentially high-impact that it should”. The funding is part of the administration’s wider push to advance low-carbon technologies including energy storage, advanced grid management tools, hydrogen and carbon capture. If you think your work might be eligible for support, you can apply here.

Government funding for energy innovation is a policy that is broadly popular, and it was significant to see that the department’s announcement included a statement of support from Senator Joe Manchin, a centrist Democrat from the coal and gas-producing state of West Virginia, who plays a key role in the balance of power in the Senate. “I will continue supporting the Department’s investment in these much needed technologies of the future”, Manchin said.

Policies to restrict fossil fuel production, however, are much more controversial, and some of Biden’s early moves on that front came in for criticism this week. Manchin said this week that he “will always be an outspoken advocate for an all-of-the-above energy policy that includes fracking and responsible energy infrastructure development”, and wrote to President Biden urging him to reverse his decision to block the Keystone XL oil pipeline. Last week Manchin and six other Democratic senators joined Republicans to vote on a non-binding resolution to stop federal agencies banning hydraulic fracturing. That is a step Biden has repeatedly said he is not going to take, but the vote was nevertheless interesting as an indication of potential opposition to future moves that would restrict the oil and gas industry.

Both of New Mexico’s Democratic senators voted for that pro-fracking resolution. New Mexico has the most federal acreage leased for oil and gas production of any state in the US, and has been at the heart of concerns about the Biden administration’s restrictions on operations on public lands and waters. New lease sales in federal areas have been “paused” pending a review, and for 60 days permits for drilling and other activities on lands and waters already leased cannot be awarded by local offices, but only by nine senior officials. Some permits have continued to be awarded, but there has been confusion over how the new temporary system works.

For New Mexico, where 55% of oil and gas wells are drilled on federal land, the uncertainty has been a real issue. The state’s Energy, Minerals and Natural Resources Department wrote to the federal government this week, asking it to clarify aspects of the permitting process.

Initially, the effect of these actions on US oil and gas production is expected to be very small. Onshore federal areas account for only 6% of US oil production and 8% of US gas production, and operators in those areas have generally stocked up on permits in anticipation of the administration’s restrictions. Most of the best federal acreage has already been leased, so a ban on new lease sales would be expected to have only a marginal effect, even in the long run.

However, if it does become more difficult or impossible to secure permits for drilling and other operations on federal lands, the impact would be greater. Research published this week by Pablo Prudencio, a Wood Mackenzie research analyst for Lower 48 upstream oil and gas, showed a range of scenarios for possible restrictions on permitting. In a scenario with existing permits honored and granted two-year extensions as required, but no new permits awarded, US oil supply in 2030 would be expected to take a hit of up to 800,000 barrels a day, compared to our base case forecast.

The net impact on US output would be offset by rigs and frack crews being redeployed from federal areas to private lands. If operators drill out their inventory of wells on private lands first, the impact on US oil production in 2030 would be closer to 500,000 b/d. And as operators use up all their opportunities in New Mexico, they would shift activity to other states. Those potential impacts will be a reason for the Biden administration to think carefully about what to do once its review of federal leasing and permitting is complete.

In brief

World oil prices continued to climb, with Brent crude breaking through $60 a barrel on Monday. Prices are at their highest for 13 months.

The price of carbon emissions allowances in the EU’s trading system has hit a new record high, rising above €40 per ton for the first time. Meanwhile, the Intercontinental Exchange group is moving the base for trading EU allowances to Amsterdam from London as a result of Brexit.

Royal Dutch Shell held its annual strategy day, setting out its plans to “accelerate its transformation into a provider of net-zero emissions energy products and services”. The presentation included plenty of significant detail, including projections that the company’s total greenhouse gas emissions peaked in 2018, and its oil production peaked in 2019. One key theme was the emphasis on growth in customer-facing businesses. Over time, Shell plans to shift more of its capital spending to its growth businesses, which include marketing, renewables and nature-based projects for carbon removal.

Total is proposing to change its name to TotalEnergies, to “anchor” its planned transformation into a broad-based energy company. Patrick Pouyanné, chief executive, said that by 2030 the group’s profile would be transformed. Growth is to come from two pillars, LNG and renewables and electricity, while oil products are expected to fall from 55% to 30% of sales. The proposed name change is being put to a vote of shareholders at the company’s Annual General Meeting in May.

Qatar Petroleum has taken the final investment decision for the North Field East Project, the world’s largest LNG development. It will have four trains, each with a capacity of 8 million tons per year, raising Qatar’s total LNG production capacity from 77 million to 110 million tons per year. The total cost has been projected as US$28.75 billion, and the project is scheduled to start production in the fourth quarter of 2025. Giles Farrer, Wood Mackenzie’s head of LNG and gas asset research, commented: “At a long-term breakeven price of just over $4 per million British thermal units, it’s right at the bottom of the global LNG cost curve, alongside Arctic Russian projects”.

Saad Sherida Al-Kaabi, Qatar’s minister of state for energy affairs, said the North Field East investment decision was “of particular importance as it comes at a critical time when the world is still reeling from the effects of a global pandemic and related depressed economies”. It showed that Qatar had a “steadfast commitment… to supply the world with the clean energy it needs,” he added. The project will also have several features intended to cut its greenhouse gas emissions, including using solar power for part of its electricity supplies, and building the largest carbon dioxide capture system ever used in the LNG industry.

California’s Public Utilities Commission has ordered the state’s three big electricity companies to line up additional sources of supply, to avoid a repeat of the blackouts that hit last summer.

German utilities have warned that the government’s plans for hydrogen pipelines will not allow a rapid transition to zero-carbon “green hydrogen”, produced by electrolysing water using renewable energy.

And finally: another energy book that looks well worth your time. The Extraction State is a history of natural gas in the US, from the industry’s origins in Pennsylvania in the 1870s (ignoring some small earlier efforts) to the present day. It’s written by Charles Blanchard, head of North America gas analytics for the trading house Mercuria, who has an engaging eye for detail as well as knowledge of the markets. The first chapter includes a vivid description of Pittsburgh as a coal town just after the Civil War, like “hell with the lid taken off”, and the story of a huge blown-out gas well that burned for four years. There have been many books written about oil, and very few about natural gas. It is good to see that gap being filled.

Other views

Simon Flowers — Big oil’s offshore wind journey is only just the beginning

Gavin Thompson — Batteries with Chinese characteristics

Ram Chandrasekaran — Electric vehicle sales are in the fast lane

Frank Yu — What do Japan’s soaring spot power prices mean for the energy transition?

Tanya Fiedler et al — Business risk and the emergence of climate analytics

Sammy Roth — Joe Biden wants 100% clean energy. Will California show that it’s possible?

John Kemp — Oil refineries are not national security assets

Quote of the week

“I wish he hadn’t done that on the first day… It did and will cost us jobs in the process. I wish he had paired that more carefully with the thing that he did second, by saying: ‘here’s where we’re creating jobs’.” — Richard Trumka, president of the AFL-CIO union federation and an ally of President Joe Biden, criticised the timing of his withdrawal of the presidential permit for the Keystone XL oil pipeline.

Chart of the week

This comes from a fascinating new report from Wood Mackenzie’s Mark Oberstoetter and Mfon Usoro, looking at the greenhouse gas emissions of US oil production in the Gulf of Mexico. Using our recently updated Emissions Benchmarking Tool, which profiles emissions for more than 2,800 oil and gas assets around the world, Oberstoetter and Usoro were able to compare the carbon intensity of the principal sources of crude used in the US. Numerous factors drive the differences in intensity: emissions in Venezuela, Colombia and Canada are driven by the more energy-intensive processes needed to produce the heavier crude qualities, while in Iraq flaring is the big problem. The overall picture is clear, however: the deep water of the Gulf of Mexico is one of the lowest-carbon sources of oil used in the US, with only Saudi Arabia coming in lower. In the light of that, Oberstoetter and Usoro argue, restrictions on US production in the Gulf could end up having a counterproductive impact on global emissions. “Removing or handicapping a low emitter hurts the collective global average”, they write.