Rystad Energy - Energy Knowledge House
Rystad Energy - Energy Knowledge House

Commentary

Carbon pricing to create billion-dollar market for the services industry

Carbon pricing will be a heavy burden for the oil and gas industry, which could be facing a $100 billion bill over the next decade as global CO2 emissions are increasingly covered by taxes and quotas. E&P companies will have to be willing to invest in solutions and technologies to address emissions, which now have to be priced into economic considerations for discoveries and projects during the concept phase, be factored into brownfield strategies, and, in many cases, could speed up a project’s shutdown and decommissioning. At the same time, emissions will create a growing and important market for the services industry that could be looking at around 500 projects worldwide that will require upgrades.

Carbon pricing will be a heavy burden for the oil and gas industry, which could be facing a $100 billion bill over the next decade as global CO2 emissions are increasingly covered by taxes and quotas. E&P companies will have to be willing to invest in solutions and technologies to address emissions, which now have to be priced into economic considerations for discoveries and projects during the concept phase, be factored into brownfield strategies, and, in many cases, could speed up a project’s shutdown and decommissioning. At the same time, emissions will create a growing and important market for the services industry that could be looking at around 500 projects worldwide that will require upgrades.

The global community emitted around 60 billion tonnes (gigatonnes, Gt) of CO2 in 2020. Around 20 Gt of this came from the oil and gas industry, including 1 Gt of CO2 emitted by the upstream sector, with around 70% related to the process of extracting oil and gas, and 30% related to flaring and venting. In addition, over 1 Gt of CO2 was emitted by midstream and downstream operations through transport and refining, and up to 19 Gt of emissions related to the combustion of end products. For upstream emissions, around 63% was due to conventional onshore activity, while offshore accounted for 26%, and shale 11%. North America emitted around 300 million tonnes (Mt) of CO2 due to extreme volumes associated with flaring in US onshore activity. The increased shale activity even placed North America ahead of the Middle East, which emitted around 200 Mt of CO2 last year (Figure 1).  

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Governments have tried to regulate emissions through two financial mechanisms: emissions trading system (ETS) – which typically operate as cap-and-trade systems, meaning that the volume of emissions permitted within a region is capped, and market participants are granted a certain emissions allowance – and direct carbon taxes. More global emissions are increasingly covered by CO2 taxes, CO2 quotas, or both. In 2020, 11% of global emissions were covered by an ETS, and this is expected to rise to 18% in 2021 as nations such as China introduce similar schemes. If emissions covered by direct carbon taxes are included, about 23% of global emissions could be covered.

Over the past five years, the European Union’s ETS price has been increasing, and it stabilized at about EUR 30 per tonne (Figure 2). More countries in Europe are incorporating strict carbon targets, such as the UK, which is targeting net-zero by 2050, and Denmark, which is experimenting with policies that could end up holding leaders legally responsible for emissions targets.20210215_OFS_Co2 supplier commnetary_Fig2.jpgWhile the future carbon price will depend on policies and policymakers, it will put a heavy burden on the oil and gas industry. The industry might see some special exempts, but even a global effective carbon price of $50 per tonne would create annual expenses of around $50 billion, based on the 2020 emissions level – equal to around 10% of the overall production cost of oil and gas fields. Some of this charge will be tax-deductible based on local fiscal regimes, but over 10 years, the costs to the industry could quickly total $100 billion.

In some oil and gas producing markets, this cost is imminent and poses challenges. Norway’s government proposed in January to more than double the country’s tax on CO2 emissions by 2030 as part of its measures to combat climate change, from the current rate of NOK 800 ($94) per tonne to a ceiling of NOK 2,000 ($235) per tonne. This is likely to boost production costs for the upstream sector, which accounts for about one-quarter of the country’s current CO2 emissions, and potentially reduce the competitiveness of Norwegian oil and gas fields. As a result, abatement measures such as electrification and CO2 injection will become more attractive.

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If higher carbon prices and stricter regulations incentivize abatements, E&Ps will be willing to invest to reduce emissions, and the most efficient way would be to power facilities and equipment with clean energy. For instance, by powering offshore oil and gas fields from shore, companies can reduce the need for gas-fired power turbines or engines on platforms. Direct use of renewable energy from offshore wind combined with storage has also received increased attention as the costs of this technology have come down. Equinor, for instance, plans to use 11 floating turbines at its Norwegian Hywind Tampen project to power the Gullfaks and Snorre fields.

Meanwhile, in onshore operations, abating CO2 emissions from the production stage has been done by replacing the power source for fluid compression or artificial lift by removing CO2 intensive gas engines and instead connecting to the grid, solar panels or onshore wind turbines. In addition, flaring, venting and leakage fugitive emissions can be prevented and controlled by smart sensors and sniffing technology, while enhanced oil recovery (EOR) initiatives have gained attention amid the latest cost reductions in the supply chain and increased focus on brownfield work and life-time extension projects.  

Potential candidates
As we move forward, the changes to CO2 emissions taxes and regulations will affect all projects. Emissions will have to be priced in economic considerations for discoveries and projects during the concept phase, but will also impact brownfield strategies, and in many cases, speed up the shutdown and decommissioning of aging projects by up to 10 years. Rystad Energy research shows there are around 500 projects that are likely to require investments in CO2 abatement solutions, based on the size and current robust field economics (Figure 4). Each of these projects could potentially emit more than 500,000 tonnes of CO2 per year based on production volumes and hydrocarbon mix. Out of these, around 55% are producing onshore fields, 23% producing offshore fields, and around 22% are projects under development or planned to be developed before 2035. Based on local regulations, these projects will make economic sense only if operators invest to reduce emissions.

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For many companies, the increased attention on emissions will be a burden that may spur divestments to optimize asset portfolios. Others may see it as an opportunity to take action. For instance, Qatar Petroleum recently sanctioned the North Field Expansion project, ramping up the LNG capacity from 77 million to 110 million tonnes per year. The company is moving forward with a CO2 capture and sequestration (CCS) system that will be integrated in the wider CCS system under development at the Ras Laffan terminal, which will export the gas from the expansion project. Qatar Petroleum also aims to cut an additional 1 million tonnes of CO2 emissions per year by using solar power and other measures. Nevertheless, for the supplier industry, the impact will be positive, at least in the short term, either because of the massive investments in CO2 solutions, or the acceleration of the huge decommissioning market. 

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