Pillar 1. Decarbonisation of extractives and managing uncertainties
This Pillar provides guidance on how fossil fuel developing economies can manage the risks associated with the continuous reliance on fossil fuels in a global decarbonised economy, while at the same time balancing renewed energy security concerns. It provides guidance on how to reduce emissions from production, processing, transportation and refining through an enabling environment that incentivises the deployment of best available technologies and practices. In that regard, Pillar 1 sets out detailed recommendations for developing producer governments, fossil fuel companies, and importer countries to reduce methane emissions and routine flaring across the fossil fuel value chain, to integrate renewable energy into upstream extractive projects, and to explore the potential for the deployment of Carbon Capture (Utilisation) and Storage to reduce emissions from energy intensive and hard-to-abate industrial sectors over the long term.
Policy makers face the challenge of managing uncertainties associated with low-carbon pathways. Uncertainty exists with respect to the characteristics of the future energy mix over time and the speed of the transition. Developments in geopolitics, energy security, international climate policy and global energy markets that are beyond national governments’ control, including the revival of interest in carbon border taxation or in the carbon content of energy sources, can accelerate the need for fossil fuel producing developing countries to transition to a low-carbon development pathway.
Russia’s invasion of Ukraine has caused significant volatility in global commodity markets, causing prices for energy to rise. This ongoing instability in the global energy landscape can cause uncertainty around the reliability of future export revenues as importer economies diversify their sources of supply, while also pursuing strategies to expand carbon constraints and foster their energy independence.
Uncertainty about technology development, including the availability and affordability of substitute technologies, means that governments have to anticipate a variety of outcomes under different scenarios, including those that could prove most disruptive to their economies (Bradley, Lahn and Pye, 2018[1]). The transition risks related to the oil and gas sector may affect the fiscal stability of fossil fuel producer countries, as well as their ability to spend revenues, invest in infrastructure for future generations, and increase their macroeconomic exposure to carbon lock-in and value destruction (Laan and Giulio Maino, 2022[2]).
In order to improve understanding about the uncertainties and risks of continuous reliance on fossil fuels, governments should carry out an economy-wide analysis of their exposure to risks, including the linkages between fossil fuel production, revenues and investment in infrastructure, and fully appreciate the implications for fiscal stability and revenue spending.
Governments should also consider the value stranding and high-carbon infrastructure lock-in created by conventional technologies, which leads to path dependence, constraining or making more challenging the pursuit of alternative low-carbon pathways. The risk for producer countries of being locked into carbon intensive development trajectories has increased with Russia’s invasion of Ukraine as crude oil and natural gas prices have risen significantly, leaving little incentives for producer countries to reduce fossil production and exports.
Governments should consider prioritising the following actions:
Assess their exposure to continuous reliance on fossil fuels by determining the total sum of public finance invested in the fossil fuel sector, including the assets and liabilities of national oil companies (NOCs) and public finance reinvested in the fossil fuel sector.
Consider the implications of lower fossil fuel revenues for foreign exchange reserves that are crucial for a country’s ability to make international payments, including for imports of fossil fuel products, food and medicines.
Consider the potential delays impacting the flow of fossil fuel revenues and the distribution of risks between governments and investors; and structure fiscal terms in order to ensure the payment of early revenue as soon as production starts, in accordance with Guiding Principle VIII of the OECD Development Centre’s Guiding Principles for Durable Extractive Contracts (OECD, 2020[3]).
Consider that the revenue-generation potential of fossil fuel projects depends on how production is allocated to domestic and export markets, as prioritisation of supply to the domestic market may result in lower revenues (where prices are subsidised or kept under the market value of the resources).
Assess the implications of continuous reliance on fossil fuels on domestic fiscal stability, including budgetary dependence on fossil fuel revenues, growing local fossil fuel consumption (including rising import dependence), and higher debt exposure.
Consider the risk of sovereign credit rating downgrades due to carbon risk exposure, with increased cost of borrowing, and the resulting difficulties in accessing climate finance and green finance mechanisms.
Review the applicable legal and fiscal regimes for extractive industries, as well as existing contractual terms to identify provisions that increase exposure to risks, such as “take or pay” clauses where the host country must take supply or pay a penalty.
Understand the impact of continuous reliance on fossil fuels on direct and indirect employment along the oil and gas value chain, including in industries that supply the fossil fuel sector.
Consider the economy-wide impacts of upstream fossil fuel developments, beyond the sector itself.
Develop a long-term strategy towards net-zero and set short-term targets for the implementation of carbon-abatement measures in the fossil fuel sector, as detailed under Pillar 1, Section 1.2.
Consider that in the longer-term, re-investment in the sector and replacement of reserves will become increasingly challenging in a declining market, particularly where higher-cost, high-carbon marginal production is concerned.
Reduce reliance on external debt, by broadening financing capacity and the domestic tax base, find alternative foreign exchange flows and redress the balance of trade (see Pillar 3, Section 3.3).
Manage rent-seeking and incumbent interests, knowing that gaining broad societal support will be crucial to overcoming resistance to the transition. This calls for building a shared understanding within society of the goals to be achieved, articulating the steps to be undertaken and the resources to be deployed to realise such a large-scale and profound transformation.
Several studies have found that fossil fuel producer countries could see major losses in revenues by 2030 and 2050, in particular under high price scenarios and if failing to restructure their fiscal regimes in line with the low-carbon transition (see Pillar 3). In an analysis of the impact of the low-carbon transition on government revenues from oil and gas, Carbon Tracker use the Sustainable Development Scenario of the International Energy Agency (IEA) as a low-carbon demand scenario. The analysis assumes a flat real long-term oil price of USD 40 per barrel of oil (bbl), and compares it with industry expectations of mid USD 60s/bbl derived from Rystad Energy’s base case price outlook, and demand volumes under the IEA’s Stated Policies Scenario. In this analysis, total government revenues would be USD 18 trillion lower over the next two decades under the low-carbon scenario, compared with industry expectations –corresponding to a 58% drop. Such a drop, if it happens, would take place in a context where the average debt level of fossil fuel-dependent countries increased from 24% of GDP in 2010 to 46% in 2018 and even further after the COVID-19 pandemic. In countries that lack sovereign wealth funds, or access to credit markets, this will contribute to fiscal strains.
According to IISD projections, a global phase-out of fossil fuels consistent with the 2°C pathway would reduce direct public fossil fuel revenues for Brazil, the People’s Republic of China (hereafter “China”), Indonesia and the Russian Federation to around 35% of 2019 levels by 2050, and for India and South Africa to around 65% of 2019 levels. Under a 1.5°C pathway, the IISD estimated that fossil fuel revenues in BRIICS countries would fall to around 10% of 2019 levels by 2050 consistent with the IEA’s Net Zero Emissions by 2050 Scenario (Laan and Giulio Maino, 2022[2]).
In its analysis of NOCs investments, the Natural Resource Governance Institute finds that NOCs could invest more than USD 400 billion (in 2021 prices), or 22% of total capital expenditures through 2030, in oil and gas projects that will break even only if the world exceeds the global carbon budget. Most of this capital expenditure – more than USD 365 billion – corresponds to developing and emerging economies. The analysis emphasises that NOCs can profit from these investments only if the world fails to limit climate change, and also raises the possibility of government bailouts of NOCs that overinvest in future production capacity.
Source: (Coffin, Dalman and Grant, 2021[4]; Manley and Heller, 2021[5]).
Actions requiring international support in contexts where government capacity is low:
Consider the likely significant decline in fossil fuel revenues linked to the anticipated reduction of global demand for fossil fuels and tightening emission reduction requirements and environmental standards on imports.
Use prudent price scenarios for fossil fuel prices to limit potentially significant revenue losses, given the anticipated speed of decline in oil and gas demand and prices under a 1.5°C pathway.
Consider the declining economic value of carbon-intensive investment projects and the risk of stranded assets, as fossil fuel resources and associated infrastructure, may be prematurely written down and/or stranded due to climate commitments, energy and investment trends.
Consider that the long-term and capital-intensive nature of fossil fuel-based infrastructure investments that require fossil fuels as either energy for domestic power production, process heat generation, feedstock (affecting national energy demand and emissions trajectories) or that are necessary to bring the fuels to export may create or exacerbate path dependence (unless high costs for replacement or retrofitting are incurred). This can lock-out new technologies as they become more competitive, by hindering or considerably slowing down alternative pathways to support growing access to energy and green industrial development.
Assess the sustainability of debt linked to fossil fuels and the specific vulnerability associated with borrowing against future fossil fuel production (resource-backed loans), taking into consideration the full potential range of fossil fuel revenue outcomes (and therefore foreign exchange earnings or needs) and time frames for production (and thus diversification) under different climate scenarios, including the ‘lowest-case’ scenario for fossil fuel demand. Developing countries should take particular care when deciding to enter into resource-backed loans. In this respect, analysis and recommendations from the OECD-DAC’s Programme of Work on Illicit Financial Flows in Oil Commodity Trading provides useful guidance (Porter and Anderson, 2021[6]).
Increase resilience and reduce dependence on fossil fuel exports, by prioritising the use of fossil fuel revenues to support the implementation of a wider green growth and sustainable diversification strategy, beyond fossil fuel-based value chains (see Pillar 3, Section 3.2).
Central banks, ministries of finance and revenue management institutions should consider prioritising the following actions:
Review revenue management frameworks in light of the risks of continuous reliance on fossil fuels and low-carbon opportunities, including the regulations and mechanisms that allocate fossil fuel revenues to spending through the national budget, investment (e.g. through a national development bank) and savings through Sovereign Wealth Funds (SWFs), where in place (including stabilisation and “future generations” funds).
Consider the implications for the profitability and fiscal stability of government (where significant sums of public and private finance are invested in the sector), the companies (including NOCs), as well as the sectors and economies that are most exposed to market risks (e.g. devalued or stranded assets).
When allocating fossil fuel revenues through the national budget, consider how best to distribute revenues between short-term needs, including delivering core physical and social infrastructure and long-term wealth creation, and how revenues might be used to drive clean energy and green growth and finance the implementation of Nationally Determined Contributions (NDC) (where they are likely to arrive in time).
Consider that established fossil fuel revenues could in principle be used to support the implementation of a green transformation strategy at home while production is exported – instead of following the traditional “fossil fuel-led” development pathway that emphasises the development of linkages between the fossil fuel sector and fossil fuel-based value chains, which serve to increase risks. This option is unlikely to be available to new producers, given the timeframe to market and anticipated speed of decline in oil and gas demand and prices under a 1.5°C pathway.
Develop robust investment strategies, including through increased collaboration between SWFs (where in place) and strategic investment funds, in order to hedge the national budget from shocks, and develop alternative industries that are likely to replace fossil fuel as an energy source or invest in sustainable infrastructure, sustainable agriculture and other green growth opportunities.
Actions requiring international support in contexts where government capacity is low:
Develop carbon-pricing capacities to support broader fiscal reforms, including the gradual introduction of carbon tax regimes, and where appropriate, the incorporation of shadow carbon pricing in investment decisions and market access, and the removal of inefficient fossil fuel subsidies (see Pillar 3, Section 3.3).
Develop robust climate-related disclosure and reporting mechanisms for the financial sector, based on the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD).
Energy and industry ministries should consider prioritising the following actions:
Assess demand for energy services by households, industry and transport, and systematically review the stages (and delivery modalities) of energy systems needed to deliver them (e.g. decisions on extraction, generation, transmission, and distribution).
Prioritise the end goal of improving reliable and affordable access to clean and sustainable energy services and associated needs (e.g. operational flexibility and resilience, greenhouse gas abatement) and enable competition between different solutions, rather than the means (fossil fuel supply), choosing fossil fuel supply only when truly needed. This will help: 1) draw upon the broad range of available resources that can cost-effectively and reliably meet those needs; 2) more accurately project domestic energy demand; 3) identify the “lowest-cost” means of delivering reliable and affordable access to achieve energy and industrialisation goals, including the right balance between on- and off-grid power supplies; and 4) counterbalance the political economy, rent-seeking, and path dependence that tend to emerge around the development of the fossil fuel sector.
Consider the impact on land, air and water use that the development of the fossil fuel sector would entail, compared to potential alternative uses of the same scarce resources. Assessing the “trade-offs” and costs of the externalities of energy choices also requires consideration of the current and future value of livelihoods, land and economic potential that may be affected by large-scale infrastructure decisions.
Identify forms of state support to the production and consumption of fossil fuels and determine how they affect the economic viability of fossil fuel projects. For further guidance on fossil fuel subsidies reform, refer to Pillar 3, Section 3.3.1.
Identify industries and sectors that are most affected and/or less prepared for the low-carbon transition, with due consideration given to local small producers and businesses.
Actions requiring international support in contexts where government capacity is low:
Monitor the value of fossil fuel investments over time. Assess the vulnerability of any project to being stranded (or of resources being left undeveloped) by determining its position on the cost curve of production. Compare a project’s break-even price (or shut-in price) to those of other projects along the cost curve, and best available data on commercially viable cost of production under different transition scenarios. Projects that are high-carbon and with a higher cost of production will be more vulnerable to stranding.
Consider the costs of expensive retrofitting or retirement of high-carbon infrastructure in initial decision-making regarding the role of fossil fuels in the domestic economy, and risks of associated infrastructure investments.
Consider that, with an anticipated physical life span of at least 30 years, any new large-scale power and industrial infrastructure should be or have the capacity to become carbon neutral. This means that infrastructure should either be designed to have zero emissions in use, or that emissions should be offset in some other way (e.g. through some combination of CC(U)S, afforestation and other negative emissions technologies) or built to be as energy efficient as possible with the capacity to integrate an increased share of on-grid or off-grid renewables or hydrogen (see Pillar 2, Section 2.3).
1.1.1. Understanding the transition risks facing new and emerging producers
New and emerging fossil fuel producer developing countries planning to monetise their resources face additional transition risks compared with mature producers. Long-term declining market dynamics mean more projects will be competing for a smaller pool of capital, and projects with a shorter investment cycle, that are less risky, low-carbon and where production costs are lower will be more likely to attract financing. For new and emerging producers that have yet to build oil and gas infrastructure and have high production costs, leapfrogging to renewables may be a better option than investing in oil and gas.
New and emerging producers with low production costs can reasonably expect to be able to exploit their reserves, but will need to reduce emissions as far as possible to remain competitive and find an export market, unless they supply the domestic market or markets where carbon is not priced.
At the same time, new and emerging producers investing in low-cost oil and gas projects and associated infrastructure should carefully assess the risk of stranded assets and being locked into carbon intensive development pathways. Governments and their NOCs need to assess whether investments in oil and gas will generate sufficient returns to justify risks, and should adjust the risk-reward equation in light of these considerations. Understanding whether oil and gas investments, including in downstream industries, will be capable of generating the same returns in the future as they do today, and balancing these considerations against the benefits of investing in renewable energy instead will be key to managing downside risks and capturing remaining value from resources for citizens.
Abatement is becoming a metric factored into sourcing and financing decisions for oil and gas projects. Importing countries and investors will assess project emission profiles in the light of environmental, social and governance (ESG) requirements and only those at the bottom of the emissions curve are likely to be exported or succeed in attracting finance. In some respects, new and emerging producers have an advantage because they are starting from scratch in terms of their infrastructure and systems which they can design and construct to: 1) minimise emissions from the outset (rather than undertaking a potentially expensive exercise of retrofitting existing infrastructure); and 2) be transition ready, enabling a gradual switch to renewable and/or low-carbon fuels use (see also Pillar 2, Section 2.3).
Building a “first class” modern oil and gas industry means minimising fugitive emissions, and deploying the best available technologies, such as upstream electrification through renewables, flaring and methane emissions reduction mechanisms, and CO2 abatement through carbon capture, utilisation and storage (CC(U)S), in order to develop systems that are as low-carbon as possible.
Governments of new and emerging producers should consider prioritising the following actions:
Leapfrog to renewables if oil and gas production costs are high and there is no infrastructure in place. Projects which get stranded in the low-carbon transition are likely to be the most expensive ones, and a realistic assessment of whether an asset will still be considered as such and economically viable in the medium and long term is key to managing downside risks and avoiding wasteful expenditure. The opportunity cost of investing in oil and gas should be assessed against the benefits of investing in alternative low-carbon technologies and renewables.
Differentiate between investment and value to a country and its citizens. Governments need to carefully consider the balance of risk and reward for oil and gas projects and the development of downstream industries (e.g. petrochemical manufacturing), understanding that a project which is capable of generating returns now may not be capable of doing so in the relatively near future, given the rapidly changing market dynamics for oil and gas.
If pursuing plans to develop their oil and gas resources, governments should develop a modern and efficient oil and gas industry that leverages the best available technologies for emissions abatement and minimises fugitive emissions.
Adopt responsive fiscal terms for oil and gas investment, whereby the government share of financial benefits automatically increases when profitability is high, and conversely decreases when profitability is low, consistent with Guiding Principle VIII of the OECD Development Centre’s Guiding Principles for Durable Extractive Contracts. This can contribute to the long-term sustainability of extractive contracts and reduce the incentives for either party to seek renegotiation (OECD, 2020[3]).
Develop a long-term green strategy from the outset and avoid high-carbon dependence (including upon oil and gas revenues, fuel inputs to energy and industry, and employment).
Foster greater accountability for how fossil fuel revenues are spent and assess whether these contribute effectively to economic diversification, including through consultative processes.
Actions requiring international support in contexts where government capacity is low:
Align the fossil fuel sector with NDCs and long-term low greenhouse gas (GHG) emission development strategies to 2050 under the United Nations Framework Convention on Climate Change (UNFCCC) process, by considering the full costs of a fossil fuel-led development pathway, and the co-benefits of a low-carbon pathway, including reduced air pollution and water stress, sustainable land use and investment in sustainable infrastructure and green sectors of the economy.
Consider how the country might leapfrog traditional fossil fuel led high-emissions industrial development, with associated adverse public health and environmental impacts and avoid rent dependence that can “crowd out” agriculture, light manufacturing, services and other industries that can support sustainable economic diversification (see Pillar 3, Section 3.2).
Review production or expansion plans in the light of the likely lower value proposition of fossil fuels and declining export market.
1.1.2. Aligning the investment strategies of national oil companies with low-carbon transition pathways
National oil companies (NOCs) are important players in developing countries. The revenue collected is equivalent to 20% of government revenue in 25 countries. However, on average only USD 1 in every USD 4 earned by the NOC is transferred back to government. In many cases, the expansionist mandate of NOCs, designed when it was created to maximise state capture of value in the oil and gas sector, means that NOCs prioritise spending on oil and gas projects at the expense of other areas of the economy (Manley and Heller, 2021[7]). The NRGI estimates that on current investment trajectories, NOCs will invest USD 400 billion over the next decade in high-cost projects which will break even only if global warming exceeds a 2-degree increase. Some USD 365 billion of investment is in fossil fuel producer emerging and developing economies. The dominant role of an NOC in the economy can in some contexts mean it is considered too big to fail, and in consequence, the NOC is permitted to take on more and more debt to avoid collapse. If the NOC continues to pursue high-cost investments which do not pay off, it may request a bailout, at substantial cost to the taxpayer, and with implications for a country’s credit rating (Manley and Heller, 2021[7]).
Moreover, investing in projects which may not break even could also entail significant opportunity costs, given that public money would be better spent on furthering socio-economic objectives, investing in the low-carbon transition, paying off national debt, or invested elsewhere for higher returns (Manley and Heller, 2021[7]).
Governments and NOCs should also be cognisant of existing long-term oil and gas agreements as these may contain terms that limit the ability of governments to transition toward a low-carbon economy. Stabilisation, force majeure and arbitration clauses may constrain governments that seek to apply new regulations to existing petroleum projects and may not adequately allocate risk or the costs of climate impacts between the government or NOCs and the investor (Woodroffe, 2021[8]). New or re-negotiated oil and gas agreements should specifically consider the imposition of new requirements related to climate change that may be introduced by governments consistent with the OECD Development Centre’s Guiding Principles for Durable Extractive Contracts. Guiding Principle VII can be used for dealing with new requirements related to climate change adaptation issues. In addition, the provisions of Guiding Principle VII and VIII can also be used to share the costs of the deployment of new clean technology to reduce emissions (OECD, 2020[3]) (see Pillar 1, Section 1.2).
Governments should consider prioritising the following actions:
Assess planned NOC investments against national low-carbon development strategies, including how planned projects perform against multiple demand scenarios. This assessment should consider which scenarios are likely to generate returns. A similar exercise needs to take place for existing projects. Through this exercise, the government can understand the exposure of national finances and the economy if planned investments fail to break even (Manley and Heller, 2021[5]).
Consider shortening investment cycles with shorter payback periods to avoid risks of stranded assets and technological lock-in.
For countries with high production costs, and particularly where NOC debt is high and government is highly dependent on NOC revenue to maintain public spending, consider strategies to gradually reduce exposure to NOC’ financial difficulties, including by enhancing efficiency of operations, lowering their Unit Operating Costs., and eventually putting a limit on NOC spending or limit state participation in projects. (Manley and Heller, 2021[7]).
Address expansionist mandates (where applicable) which incentivise an NOC to spend much of what it earns to grow the national oil industry. Whilst an expansionist approach made sense when most NOCs were created, it is no longer appropriate given market changes. Adapting NOCs’ mandates to pursue less risky projects which can in turn fund low-carbon investments in other areas of the economy will help to manage risks and gradually reduce fossil fuel dependence. This is particularly the case where a country has high production costs, given that projects are less likely to break even, and stranded assets are likely.
Assess the terms of existing long-term oil and gas agreements to determine if there are any limitations on the government’s ability to enforce new regulatory requirements to respond to climate change and advance the low-carbon transition.
When negotiating or re-negotiating oil and gas agreements, introduce terms consistent with Guiding Principle VII of the OECD Development Centre’s Guiding Principles for Durable Extractive Contracts to avoid liability for regulatory changes necessary to meet the objectives of the Paris Agreement and advance the low-carbon transition (OECD, 2020[3]).
Where possible, resist NOC’ requests for tax breaks to maintain production levels for projects where production costs are high. Tax breaks only serve to shift the cost burden from the NOC to the taxpayer and make it more challenging for governments to take capital out of the NOC. Ultimately, governments should avoid a race to the bottom where production is maintained but tax exemptions result in limited or no benefit to citizens (Manley and Heller, 2021[5]).
Consider establishing NOC borrowing ceilings and require government approval to exceed limits. Taking on more debt to maintain production increases the risk of an expensive government bailout, particularly if production costs are high, as the NOC will have limited recourse to more profitable projects to keep pace with debt repayments if prices are low. Governments can also limit borrowing from domestic lenders, such as commercial banks, given that the economic implications could be more profound if the NOC gets into financial difficulty (Manley and Heller, 2021[7]).
Limit state participation in projects as a means to reduce exposure to risk. Carried interests can also limit up front costs for governments and NOCs and reduce risks, as NOCs will have spent less money up front if projects fail (NRGI, 2021).
Future trajectories regarding the role of fossil fuels in the global energy system depend on assumptions made regarding transition pathways and the availability and affordability of clean technologies. Meeting the growing demand for energy, while achieving sustainable development (including economic, environmental and social objectives) requires transforming the way energy is produced and consumed by relying on negative emission or carbon neutral technologies. The discovery of new information regarding non-CO2 emissions may also have implications for the choice of fossil fuels and their sustainable use unless abatement technologies are deployed.
A transitional step towards a net-zero economy, where fossil fuels are part of the energy mix, is to reduce emissions from production, processing, transportation and refining through the deployment of the best available technologies and practices. Although it is important that emissions from oil and gas production are reduced as much as possible, EFFECT recognises that the implementation of some of the technological options set out in this section will depend on the specific circumstances of the operations, country or region and may not be feasible for all countries (e.g. CC(U)S). However, all countries should endeavour to take steps to implement regulations and measures to reduce flaring, venting and fugitive methane emissions across the value chain of oil and gas projects.
The adoption of new technologies and best practices will come with costs that will need to be borne by the parties involved in oil and gas production (governments, NOCs, IOCs etc.). To allocate these costs on an equitable basis, EFFECT recommends an alternative approach for existing and new oil and gas projects and depending on the deployment of different low carbon technologies.
For existing oil and gas projects:
The costs of the adoption of best available technologies and best practices are shared between the government and the investor and treated as any other project costs for the purposes of tax deductibility, and cost recovery in production sharing contracts, in line with the OECD Development Centre’s Guiding Principles for Durable Extractive Contracts (OECD, 2020[3]). In oil and gas production sharing agreements, these additional costs would be recoverable from the allocation of “cost oil” or “cost gas”. In mining contracts, these additional costs would be treated as deductible expenses in both income taxes and rent taxes.
The costs for the deployment of methane emissions reduction technologies should be borne by the investor.
The costs for the deployment of technologies to capture associated gas should be borne by the investor. When associated gas is captured and put to productive use, with the creation of additional value for the host country, the parties might consider whether the costs associated with stopping flaring and gathering gas are chargeable against oil and gas project development expenses.
The costs for the deployment of upstream renewable energy electrification for new projects should be borne by the investor. When upstream renewable energy electrification generates excess power with co-benefits for the host country, the parties might consider whether the costs associated with stopping flaring and gathering gas are chargeable against oil and gas project development expenses.
The costs for the deployment of CC(U)S should be borne by industry, but government support is still required (see Pillar 1, Section 1.2.7).
Determine the carbon footprint of current and planned fossil fuel production, transport and use, by understanding the sources of emissions in the oil and gas value chain, noting that CO2 emissions are concentrated in the upstream oil production phase, whereas methane emissions occur more broadly across the value chain (Lorenzato et al., 2022[10]).
Enhance the efficiency of oil and gas operations by reducing methane leakages, electrifying upstream operations and deploying carbon capture and storage (where feasible).
Ensure that any new investments in oil and gas production are really necessary for energy security needs, have multi-purpose use (i.e. the ability to transport low-carbon fuels such as hydrogen and ammonia), and are designed to have the smallest carbon footprint possible (Bordoff and O’Sullivan, 2022[11]).
Grant preference to new oil and gas infrastructure investments with shorter payback periods. These investments may include conditions where the government has the right to wind down the asset against compensation after a specified time, or where the investment has yielded a certain return (Bordoff and O’Sullivan, 2022[11]).
1.2.1. Methane emissions reduction
Reducing methane emissions is the single most important and cost-effective way to bring down emissions and improve efficiency in the oil and gas industry.
Methane emissions can be released at different stages of the oil and gas value chain, from the production and processing of gas, and the transmission and distribution to end-users, to the decommissioning of well sites, including orphaned wells. While some emissions are fugitive (i.e. accidental, through faulty seals or leaking valves), others are vented (i.e. intentionally) and often carried out for safety reasons or due to the design of the facility or equipment. Fugitive emissions (leakages) from “super emitter” sources can occur across the different segments of the gas value chain: at well sites, gas-processing plants, liquids storage tanks, transmission compressor stations, and distribution systems.
In contrast to coal, natural gas use can contribute to the reduction of CO2 emissions due to its lower carbon intensity. However, the benefits associated with the reduction of CO2 emissions may be partially, or completely, offset by methane emissions from gas production, transport and use. This may also undermine the benefits of the use of gas over other fossil fuels in terms of their carbon footprint, due to the high global warming effect of methane emissions.
A wide variety of technologies and measures are available to reduce methane emissions from the oil and gas value chain. If all available technologies and measures were to be deployed across the oil and gas value chain, the IEA estimates that this would reduce methane emissions by 75%. Furthermore, the IEA estimates that around 45% of the 79 Mt total emissions could be avoided with measures that would have no net cost (IEA, 2021[12]). Methane is also a valuable product and in many cases can be sold if it is captured.
Relative to coal, the construction of additional natural gas power plants has the potential to both produce excess near-term warming (if methane leakage rates are high) and excess long-term warming (if the deployment of natural gas plants today delays the transition to low-carbon emission technologies).
Targets for greenhouse gas emissions (GHG) can be defined as absolute targets or as intensity targets.
An absolute target refers to a target that aims to reduce GHG emissions by a set amount.
Intensity-based targets are expressed as units of GHG emissions per unit of activity. Activity can be measured at an aggregate level, for example in terms of GDP or per capita GDP, or at a more detailed level based on measures of underlying efficiency of the economy.
Intensity-based targets do not necessarily cap emissions. In fact, even if intensity targets are achieved, emissions may grow as the economy grows. For intensity-based targets to deliver absolute emission reductions the targets should be demanding enough: if the rate of decline in emissions intensity is higher than the rate of GDP growth, then absolute emissions will fall. An alternative approach is to combine intensity targets with absolute targets or caps.
Source: Authors.
Governments should consider prioritising the following actions:
Undertake a mapping of institutions and agencies that could be involved in addressing methane emissions as well as any pre-existing policies or regulations that address methane emissions or affect indirectly methane emissions.
Set progressively ambitious methane emissions reduction targets.
In February 2022, the Colombian Ministry of Mines and Energy introduced flaring and fugitive methane emissions regulations, to reduce emissions from upstream oil and gas activities at a national level. In so doing, they became the first Latin American country to regulate methane emissions from oil and gas. These regulations were developed over a period of five years with significant multi-stakeholder input. The Ministry of Mines and Energy convened expert workshops and undertook a comparative analysis of regulatory requirements globally to reduce emissions on a source-by-source basis.
The new regulations adopt some of the best practices seen in other jurisdictions and requires operators to do the following:
Carry out a Leak Detection and Repair (LDAR) programme to inspect oil and gas facilities.
Install vapour recovery units, redirect the gas for utilisation or send gas to flare from existing gas-driven pneumatic pumps or altogether replace them with electric or compressed air driven devices.
Redirect emissions from compressors, substitute seals and other measures.
Verify every year, through a third party, that flares are operating efficiently.
Source: (Banks and Miranda-González, 2022[13]).
Establish a regulatory framework for the measurement, disclosure, reporting and verification of NOC and IOC carbon emissions, using existing reporting templates such as the IPIECA-API-IOGP Sustainability Reporting Guidance, the Oil and Gas Methane Partnership (OGMP) standard, and the Methane Guiding Principles. Governments should support the harmonisation of multiple existing standards for CO2 and methane emissions reporting.
Require the public disclosure of methane emissions information, including publication on a website. This added layer of scrutiny may create an additional incentive for companies to comply (IEA, 2021[14]).
Incorporate both flaring and fugitive methane emissions into the same regulatory instrument. This approach has been taken recently by Colombia (see Box1.5). Traditionally, these issues have been treated separately, which can cause regulatory inefficiencies and gaps and lead to confusion and uncertainty (Banks and Miranda-González, 2022[13]).
Understand the barriers that may prevent companies, including NOCs, from undertaking actions to drive methane reductions that appear to be cost-effective – for example, a lack of information, infrastructure, investment incentives, or the flow of revenues between governments and NOCs (IEA, 2021[14]).
Ensure that infrastructure policy is consistent with zero routine flaring and reduced venting objectives and supports the building of pipelines necessary to evacuate gas.
Introduce methane reduction requirements in the planning stages of projects, requiring new installations or developments to utilise zero-emitting technologies and have plans in place to capture gas and deliver it to the market.
Consider introducing methane emission reduction requirements in upstream exploration and production contracts or licences (IEA, 2021[14]).
Require over time the replacement of equipment that is designed to vent methane with technologies that are zero emitting or the use of vapour collection to reroute vented methane back into the pipeline.
Require detection campaigns with specified frequency (e.g. quarterly), and specify equipment to be used, detection thresholds and time limits for repairs. Using methane regulations allows for the use of alternative leak detection and repair programmes that can achieve equivalent outcomes.
Treat capital expenditures on equipment to reduce emissions as any other project cost for the purposes of tax deductibility.
Actions requiring international support in contexts where government capacity is low:
Develop an emissions profile to identify how much methane is emitted and determine the location of the biggest sources, measure to the extent possible and estimate the level of emissions, and identify problem sources and abatement solutions involving industry stakeholders.
Design robust leak detection and repair programmes (LDAR) based on environmental outcomes that emphasise repairing detected leaks and preventing leaks.
Establish a comprehensive and transparent production accounting system that includes methane emissions reporting, recordkeeping and disclosure, and third-party verification requirements.
Develop protocols for incorporating new data such as satellite, flyovers and on-the-ground surveys, into national inventories.
Consider off-balance sheet financing for upstream and midstream methane emissions abatement, where oil and gas operators contribute to a special purpose vehicle (SPV). The SPV conducts the due diligence, measurement and repairs, and then monetises emissions reductions through direct gas sales, by generating carbon offsets, or through a fee by the operator (IEA, 2021[15]).
Directly invest in building new infrastructure or adopt policies that allow for the spreading of development costs across multiple firms and end-users (IEA, 2021[14]).
Consider independent labelling and certification of low-carbon oil and gas with comprehensive and transparent production data and accompanying methane emissions data.
The oil and gas industry accounts for 23.1% of global anthropogenic methane emissions, representing the second highest source of anthropogenic emissions after agriculture (39.6%), and ahead of waste (20.5%), coal (12.2%) and other sources, including bioenergy and biomass burning (4.6%).
The IEA estimates that around 80 million tonnes of methane were emitted to the atmosphere from oil and gas operations in 2021. Methane leaks in 2021 from fossil fuel operations, if captured and marketed, would have made an additional 180 billion cubic metres of gas available to the market, an amount similar to all the gas used in Europe’s power sector.
Source: (IEA, 2022[16]).
What can the fossil fuel industry do?
Reducing methane emissions across the value chain:
Participate in voluntary initiatives to reduce methane emissions in the oil and gas sector. Examples of such initiatives include Global Methane Alliance, the Oil & Gas Methane Partnership (OGMP), the Oil and Gas Climate Initiative (OGCI), the Methane Guiding Principles, and the Global Methane Initiative (GMI).
Systematically improve methane management by applying a management system (e.g. the plan-do-check-act cycle) to the elements of reducing methane emissions (Methane Guiding Principles, 2020[17]).
Build methane reduction efforts into company culture. For example, through the integration of methane reduction into existing business and operational procedures and the establishment of new learning opportunities relating to emissions reductions for both technical and non-technical staff (Methane Guiding Principles, 2020[17]).
Establish measurement, disclosure and reporting, and verification procedures for flaring, methane venting, and carbon emissions, satisfying government requirements in the host country and reporting templates such as the IPIECA-API-IOGP Sustainability Reporting Guidance, and the OGMP standard.
Reducing methane emissions in upstream production:
Incorporate emissions reduction considerations into overall business and operating strategies, including by setting short-term targets towards achieving net-zero, and share information acquired within the company and across the oil and gas industry.
Identify known sources and potential sources of emissions in an inventory.
Carry out robust emissions surveys to provide a basis for understanding methane emissions sources and levels to evaluate plans to mitigate emissions. These should include both desktop studies and field surveys (CCAC, 2017[18]).
Quantify methane emissions directly by measuring emission rates and use this information to create or update inventories.
Acquire an overview of cost-effective readily available abatement options and adopt specific strategies for specific projects.
If methane needs to be released – prioritise recycling or flaring over venting. Check that flare systems are operating according to design (Methane Guiding Principles, 2020[17]).
Use smart metering and controls to reduce end-user energy use and emissions (e.g. gas turbines and boilers) (Methane Guiding Principles, 2020[17]).
Phase-in use of the incumbent and emerging zero or lower emission technology to improve measurement of methane emissions.
Regularly review the scope, quality and frequency of emissions reporting.
Reducing methane emissions in transmission, storage, and distribution:
Compile an accurate inventory of emissions from all sources.
Start with low-cost measures then try implementing those with higher costs. For example, recompress gas instead of venting, install vapour recovery units on crude oil and condensate storage tanks. In the absence of these units, dissolved methane can evaporate and be vented into the atmosphere (IEA, 2020[19]).
Consider modern, high-integrity materials and jointing technology when constructing downstream distribution networks.
Systematically reduce methane emissions by minimising potential fugitive and venting sources, perform inspections and prioritise repairs, and consider new technology (e.g. detection, quantification, condition monitoring and predictive maintenance).
Reduce methane emissions that result from energy use: use smart metering and controls to reduce end-user energy use and emissions, maintain gas-fired equipment to operate according to design, when replacing equipment update with the latest proven energy-efficient models, and consider upgrading.
In line with its net-zero carbon strategy and a specific target to reduce methane emissions by 45% by 2025 compared to 2015 levels, Snam, an energy infrastructure company for transmission network and natural gas storage capacity, has deployed gas recompression systems to reduce venting.
When maintenance is needed on sections of pipeline, operators usually block the smallest possible section of the pipeline and depressurise it by venting natural gas into the atmosphere. For a high-pressure large diameter pipeline, the volume of gas vented may be significant. Large transmission pipelines can pump down, using portable compressors, to lower the pressure in the pipeline before maintenance work and repairs to effectively reduce methane emissions. However, the process takes time and is not suitable for every situation. Snam has deployed mobile compressors that can pull the line pressure down to 0-5 bar, thereby reducing the emissions vented by very close to 100% for maintenance activities in high-pressure large diameter pipelines. These measures have resulted in the reduction of gas venting of 5 360 000 sm3 of gas in 2018 and 380 000 sm3 of gas in 2019.
Source: (Methane Guiding Principles, 2020[20]).
What can government and the fossil fuel industry do together?
Establish a collaborative process to improve national inventories reports for oil and gas methane emissions by defining the different categories of emissions, reviewing the approach to emission estimation and data compilation, and updating the process after construction of the inventory.
Share data openly to advance research geoscience and technology improvements and impacts.
Build on existing initiatives to encourage knowledge-sharing and best practices within the industry (IEA, 2021[14]). Examples include the Global Methane Alliance, the Oil & Gas Methane Partnership (OGMP), the Oil and Gas Climate Initiative (OGCI), the Methane Guiding Principles and the Global Methane Initiative (GMI).
Build institutional capacity to undertake measurement, reporting and verification activities and to deliver methane emissions reductions.
What can IOCs/NOCs do together to reduce methane emissions?
Align objectives to ensure a common understanding and commitment to reducing methane emissions in oil and gas operations.
Transparently share information on methane emissions to identify business opportunities for capturing, producing and selling associated gas.
NOCs should engage with international initiatives to share knowledge and build capacity, and should also seek to follow international standards to reduce methane emissions across their operations.
1.2.2. Enabling measures and incentives
In order to reduce the carbon footprint of the oil and gas sector, governments should adopt incrementally stronger policies for emissions reduction to incentivise and promote a transition to future lower-emission technologies, and influence the development of domestic gas market reforms.
Without such enabling measures, high natural gas supply may accelerate the phase-out of coal-fired electricity, but will also increase electricity use and slow the decarbonisation process by delaying the use and price-competitiveness of renewable energy technologies. Conversely, flexible demand growth, with higher efficiency and renewable energy deployment, could mitigate fiscal risks and account stress as well as increase energy security.
The pricing of fuel is also essential to incentivise low-carbon pathways.
Governments should consider prioritising the following actions:
Consider introducing GHG emissions standards/targets for gas production, transport and use.
Where feasible, set incremental targets for the mandatory adoption of renewable energy sources for power generation.
Avoid the sale of fuel to the domestic market untaxed, or below export prices, as this can disincentivise energy efficiency and widen inequality (by benefiting disproportionately the rich who use more energy than the poor). This also risks locking in rising fuel demand and locking out clean technologies and infrastructures (Bradley, Lahn and Pye, 2018[1]).
When fuel substitution is considered, the consumer price of the alternative fuel should be high enough to make investment in infrastructure and processing commercially feasible, yet low enough to ensure it is used instead of less efficient fuels, such as diesel, wood, charcoal and coal (Bradley, Lahn and Pye, 2018[1]).
Actions requiring international support in contexts where government capacity is low:
Envision reducing black carbon and sulphur dioxide (SO2) emissions through point source pollution controls.
Understand the full costs of gas production, processing, transport (pipelines), distribution (city gas networks) and storage (compressed natural gas stations), emissions, water demand and land use, even if not immediately applied to the domestic fuel price (Bradley, Lahn and Pye, 2018[1]).
1.2.3. Utilising associated gas
Associated gas is natural gas that is produced along with crude oil, and typically separated from the oil at the wellhead. Associated gas has often been seen as an inconvenient by-product of oil production: it is generally less valuable than oil per unit of output and is costlier to transport and store. Oil and gas projects that have small gas volumes, are geographically remote, or suffer from a lack of infrastructure or market for gas, will routinely flare or vent the associated gas, emitting large volumes of CO2, some methane, and other volatile organic compounds (VOCs). As a result, thousands of gas flares at oil production sites around the globe burn approximately 140 billion cubic metres of natural gas annually, causing more than 300 million tonnes of CO2 to be emitted to the atmosphere (World Bank, 2022[21]).
Flaring of gas not only contributes to climate change and impacts the environment but also wastes a valuable energy resource that could be used to advance the sustainable development and low-carbon transition in producing countries. For example, if the amount of gas which is flared on an annual basis were used for power generation, it could provide about 750 billion kWh of electricity, or more than the African continent’s current annual electricity consumption.
Associated gas can be utilised in a number of ways: reinjected for enhanced oil production, transmitted into natural gas distribution networks (i.e. pipelines), used for on-site electricity generation, converted into compressed natural gas (CNG) or liquefied natural gas (LNG), converted from gas to liquids (GTL) to produce synthetic fuel (e.g. methanol), used as feedstock for the petrochemical industry or to produce blue hydrogen, if CC(U)S is applied to the resulting CO2 emissions.
However, only 75% of the associated gas produced globally is put to productive use, either marketed directly to end consumers via gas distribution networks, used on-site as a source of power or heat, or reinjected into oil wells to create pressure for secondary liquids recovery. The remainder (some 200 bcm in 2018) is either flared (140 bcm) or vented to the atmosphere (an estimated 60 bcm) (IEA, 2019[22]).
Commercial viability is a significant barrier to the utilisation of associated gas, as operators seek to secure long-term reliable off-take agreements with anchor customers for the sale of gas to the domestic market. In many developing countries this will be the power sector due to growing demand for electricity. However, power utilities suffer from grid instability and financial difficulties that can lead to large payment arrears where power utilities are unable to pay for gas “purchased”. Furthermore, IOCs may be subject to gas export restrictions, leaving flaring as the only alternative should domestic customers be unable to pay (World Bank, 2022[23]).
Consequently, the capture of associated gas by upstream operators is dependent on gas pricing reforms and competitive downstream energy markets with efficient and transparent legal and regulatory frameworks that provide fair and non-discriminatory access to markets. Many of these enabling measures and regulatory reforms may be outside the mandate of the ministry in charge of oil and gas. Therefore, governments should ensure that an integrated energy sector strategy is implemented to set out the necessary reforms across the gas value chain (World Bank, 2022[23]).
Governments can also set specific gas flaring and venting reduction targets in their NDCs, although few oil-producing countries have done this to date. These targets can be assigned to the government, or, where relevant, to the NOC. For example, in Colombia, Ecopetrol has an interim target to reduce gas flaring by 77% by 2022 (down from 2017 levels), and has linked its targets to Colombia’s NDC, which refers to scaling up the utilisation of associated gas (World Bank, 2022[24]).
In many cases, the monetisation of associated gas can be a financial solution to flaring as associated gas should be viewed as an asset, not an unwanted by-product of oil production. Associated gas is ordinarily re-injected into the field for enhanced oil recovery. Where this is not feasible, there are several options available to operators to monetise associated gas, instead of flaring it into the atmosphere. These include:
converted to power, with the latter used on-site by the oil operator
converted to power, with the latter sold to external off-takers
Source: (Lorenzato et al., 2022[10]).
Governments should consider prioritising the following actions:
Develop overall policy for the capture and use of associated gas, with due consideration for the risks associated with continuous reliance on fossil fuels under Pillar 1, Section 1. This policy should specify the role that flare and vent reductions of associated gas play in achieving overall climate policy objectives (World Bank, 2004[25]); (IEA, 2021[14]).
Ensure that oil producers have the legal right to monetise associated gas, including through gas exports (World Bank, 2022[23])
Ensure that regulatory agencies have clearly defined responsibilities with no overlapping or conflicting mandates, and that these agencies are properly resourced. The spreading of gas flaring and venting institutional responsibilities across different ministries and in some countries even NOCs, can lead to unclear reporting lines, conflicting mandates, and reduced effectiveness of the regulatory agency. For example, in countries with a dedicated ministry for oil and gas, flaring and venting may fall under the responsibility of the ministry responsible for the environment (Lorenzato et al., 2022[10]). Where regulatory functions are split among different authorities, governments should put in place processes requiring the authorities to cooperate in cross-cutting areas, such as the issuance of flaring permits or the approval of oil field development plans. Interagency co-ordination is essential and can be achieved using dedicated liaison officers (World Bank, 2022[23]).
Combine monitoring and enforcement powers under one single agency.
Establish a gas and electricity regulatory agency that efficiently regulates natural monopolies of gas processing, transmission and distribution and implements open access rules to gas networks to foster competition and provide opportunities to market associated gas downstream. Although third-party access can often be secured through contractual negotiations, the substantial bargaining power held by the transmission network’s owners may require regulatory intervention (Columbia University, 2016[26]).
Grant preferential access for associated gas into the national gas pipeline system and preferential access for electricity produced from associated gas to the wholesale market (Lorenzato et al., 2022[10]).
Establish fit-for-purpose methods for measuring the volume of gas flared and vented (by metering or using engineering estimates) and require IOCs and NOCs to submit this information to the regulator on a regular basis. Engineering estimates can offer an alternative when measurement is difficult or too costly, provided that standardised estimation methods are specified and monitored. Regulators should consider new technologies such as continuous monitoring systems, aerial surveillance, and satellite instruments as independent sources of data. (World Bank, 2022[23]).
Collect and publicly disclose information on flaring and venting, by requiring oil and gas companies, including NOCs, to publicly disclose such information. Disclosure of information can help strengthen existing regulations and build trust in the industry with the affected communities, civil society and the public (World Bank, 2022[23]).
Require that routine flaring at existing oil fields ends as soon as possible, and no later than 2030 (World Bank, 2022[21]).
For new projects, governments should require that field development plans for new oil fields incorporate sustainable utilisation or conservation of the field’s associated gas without routine flaring (World Bank, 2022[21]).
Clearly define in regulation the circumstances under which operators can flare and vent associated gas without prior approval from the relevant regulatory authority, with reporting requirements and sanctions for non-compliance. Examples of such circumstances include safety or unavoidable technical reasons (World Bank, 2004[25]); (IEA, 2021[14]); (World Bank, 2022[23]).
Include dissuasive and proportionate enforcement mechanisms in relevant regulations to deal with non-compliance of flaring and venting of associated gas: for example, penalties and fines, and revocation of the production/operation license (World Bank, 2004[25]). Any type of mandatory payment (penalty, fine, fee) should be established at a sufficiently high level to make the alternative of investing in flaring and venting reduction more attractive than paying the penalty. However, the payment should not be so high that shutting down oil production becomes the only viable option (World Bank, 2022[23]).
Encourage the utilisation of associated gas to contribute to the security of supply, by providing for an associated gas profit split between NOCs and IOCs.
Require that operators on adjacent fields collaborate to capture associated gas where necessary. A portfolio approach that clusters several small flares under the same project is often required to build a minimum of economies of scale and to hedge against the uncertainty and unpredictability of flare profiles (Lorenzato et al., 2022[10]).
Actions requiring international support in contexts where government capacity is low:
Consider providing fiscal incentives to reduce the flaring and venting of associated gas. Preferential treatment of gas production through lower taxes and royalties compared to oil production may provide a positive incentive to produce gas and develop downstream gas network and markets or LNG facilities for export (World Bank, 2004[25]). When considering the development of options for the commercialisation of associated gas, governments should consider the effects on this new market(s) if oil production is scaled back (IEA, 2020[19]).
Before granting permission to operators to flare or vent associated gas for economic reasons, require that companies satisfy the regulatory authority that they have investigated all reasonable alternatives to flaring and venting, including reinjection for improved oil recovery or storage, or gas gathering, treatment and sale to downstream energy markets (World Bank, 2004[25]).
Nigeria has reduced its flaring of associated gas from 60% to 6%. This and future reductions are supported by policy changes in Nigeria that include:
1. a requirement for all upstream development plans to include a plan for commercialising or evacuating the associated gas
2. a requirement for production sharing contracts to include a gas utilisation plan
4. a penalty for the flaring of gas, with proceeds going to environmental mitigation in host communities (the Petroleum Industry Act 2021 also stipulates that the proceeds from flare penalties will be used to carry out environmental remediation).
The efforts of the Nigerian National Petroleum Corporation (NNPC) to reduce flaring have followed from policies, incentives and programmes of the Federal Government of Nigeria, including the enactment of Nigeria’s Liquefied Natural Gas Act, the Associated Gas Reinjection Act, and the Flare Gas (Prevention of Waste and Pollution) Regulations. NNPC and its partners are funding some of the flare gas monetisation projects, while others are being carried out in collaboration with third-party off-takers. Nigeria’s Ofon Upstream Emissions Reduction (UER) initiative makes use of UER certificates, which can then be sold to fuel suppliers, to be counted towards their emissions reduction. In the Ofon case, the UERs were sold to the Total Lindsey Oil Refinery for approximately EUR 1 million, to be converted into GHG credits. Ofon UERs were externally verified and validated by Nord Cert Gmbh.
Source: (OECD Development Centre, 2021[27]).
What can the fossil fuel industry do?
Follow international industry standards, while setting improvement targets for flaring and venting reduction as well as standardised monitoring and reporting procedures.
Join the World Bank’s Zero Routine Flaring by 2030 initiative to co-operate to eliminate routine flaring no later than 2030. Join the Global Gas Flaring Reduction Partnership (GGFR) to work to end routine gas flaring at oil production sites. Oil companies with routine flaring at existing oil fields should implement economically viable solutions to eliminate this legacy flaring as soon as possible, and no later than 2030 (World Bank, 2022[21]).
Investigate commercial uses for associated gas, including on-site electricity generation, conversion to CNG or LNG, and viability of GTL or feedstock for the petrochemical industry.
Establish an appropriate mechanism for the collection, public disclosure, and reporting on flaring and venting volumes and frequency.
Share data on established good practices from other jurisdictions. The sharing of data and learning from practices in other oil- and gas-producing countries can enhance and drive the pace of implementation of abatement measures (World Bank, 2022[23]).
What can importing countries do?
Recognise their shared responsibility for curbing flaring and venting in producing countries. The Imported Flare Gas (IFG) Index is based on the concept that when a country imports crude oil from another country, it is also importing the flaring intensity of the producing country in proportion to the amount of crude oil imported, especially when international agreements and national commitments on climate mitigation incentivise countries to reduce emissions throughout the life cycle (World Bank, 2021[28]).
Provide technical and financial support for the deployment of best available technologies for emissions abatement.
Establish partnerships to build capacity for measurement, verification and reporting of CO2 and methane emissions.
Require IOCs operating from their jurisdictions to deploy the best available technologies for emissions abatement wherever they operate.
Implement “collect and buy” schemes where importing countries agree to purchase associated gas that would have otherwise been flared. Long-term gas purchase agreements for associated gas can incentivise producing countries to invest in technologies and infrastructure to capture associated gas.
What can government and the fossil fuel industry do together?
Jointly develop transparent and effective standards for the monitoring and reporting of flaring and venting of associated gas (World Bank, 2004[25]); (IEA, 2021[14]).
Commit to publicly report the flaring of associated gas on an annual basis in accordance with the World Bank’s Zero Routine Flaring by 2030 initiative.
Investigate the potential for a domestic natural gas market in order to monetise any associated gas. For example, some developing countries, in partnership with industry, are looking at financially viable options to build downstream gas network to use associated gas (e.g. the West Africa Gas Pipeline, which aims to reduce gas flaring in Nigeria by exporting associated gas to neighbouring Benin, Togo and Ghana) (World Bank, 2004[25]).
Join the World Bank’s Zero Routine Flaring by 2030 initiative and the Global Gas Flaring Reduction Partnership (GGFR) to work toward the identification of solutions to technical and regulatory barriers to flaring reduction by developing country-specific flaring reduction programmes, conducting research, sharing best practices, raising awareness, increasing the global commitments to end routine flaring, and advancing flare measurements and reporting.
The development of gas infrastructure can greatly reduce flaring and venting by capturing associated gas. Constructing export terminals, pipeline networks, compression facilities, and reinjection wells, makes it economically feasible to capture and use associated gas that would otherwise be flared or vented.
The development of gas infrastructure can be financed through transformative public-private partnerships between NOCs and private investors. Such partnerships allow parties to pool resources and avoid imposing the full burden of overcoming the infrastructure challenges on individual companies, and can enable flaring reduction projects. Examples of public-private partnerships that have successfully developed infrastructure to capture associated gas include the Angola LNG Project and the El Merk Central Processing Facility in Algeria.
The development of conventional gas infrastructure may not be feasible for all projects, especially where there is a lack of existing infrastructure or where demand for gas is low and there are issues with power supply and transmission. In these scenarios, small-scale LNG facilities (with relatively low investment compared to pipelines or large facilities), LNG distribution by trucks and LNG refuelling stations offer possible solutions to improve gas distribution flexibility.
Source: (Calel and Mahdav, 2020[29]); (Tractebel Engineering, 2015[30]); (World Bank, 2022[23]).
1.2.4. Reducing methane emissions across the LNG value chain
The global LNG industry is rapidly expanding with huge increases in supply and trading, and numbers of exporters and importers, and with several new projects due to come on stream during the early 2020s. LNG projects are projected to account for around 80% of the increase in global gas trade up to 2040 (Stern, 2019[31]). This projected increase in LNG trade may lead to an increase in global GHG emissions, particularly as LNG transport, in general, is more emissions intensive than pipeline transport (IEA, 2019[32]). For many supplying countries, only limited verified emissions data are available, which can be further complicated by disparities in regional and industry practices around flaring, venting, permitted valves and the types of storage tanks or compressors used in LNG processes (Stern, 2019[31]); (Blanton and Mosis, 2021[33]).
Emissions can occur across the LNG life cycle – during liquefaction, shipping, and regasification. The liquefaction of gas is an energy-intensive process, as the gas needs to be cooled to -162°C, and the energy required for this process can equate to 11-13% of the gas arriving at the liquefaction terminal (Stern, 2019[31]). Emissions from liquefaction derive from fuel combustion for electricity, natural gas venting and also fugitive methane leaks (Abrahams et al., 2015[34]). Emissions can also be present during transportation and can include boil-off gas from cargo tank to engine and methane slip during fuel combustion. Emissions intensity varies across different LNG ship sizes and types of propulsion, and can be further blurred where, in an increasingly liquid LNG market, cargos may change direction/intended destination several times prior to final delivery (Stern, 2019[31]). The emissions intensity of the regasification stage of the LNG life cycle is less clear. There is a wide variation in energy required for regasification due to differences in ambient air temperatures and availability of seawater for heating. In some cases, regasification facilities are co-located near power plants, which can minimise the direct emissions from energy required to regasify LNG (Abrahams et al., 2015[34]).
Typical LNG projects may take 5 years to build and have an operating life of at least 25 years – in many cases extending beyond 2050. Consequently, developing country producer governments should consider how the introduction of new GHG reduction requirements by importer countries may impact new LNG projects over their operating life. These regulations may dictate how long LNG can be sold as unabated methane, and potentially increase costs and lower expected returns from new LNG projects (Stern, 2019[31]). Developing country producer governments should also recognise that several of the largest LNG importers (e.g. France, Japan, South Korea, Spain and the United Kingdom) have pledged to become carbon-neutral by 2050, and by 2060 in China’s case (Blanton and Mosis, 2021[33]).
Governments should consider prioritising the following actions:
Stay abreast of policy developments on LNG emissions in importing countries affecting the choice of suppliers (Stern, 2019[31]). It is likely that GHG emission regulations will be introduced by importing countries during the life of LNG projects that continue/commence operating post-2030.
Introduce requirements for LNG project operators to measure emissions during liquefaction, shipping, and regasification (where possible) (Stern, 2019[31]).
Actions requiring international support in contexts where government capacity is low:
Consider whether importing countries plan to introduce GHG emission reduction requirements for new LNG projects when assessing the commercial viability of LNG projects.
Introduce strict decarbonisation requirements for new LNG projects. For example, in Western Australia, the Gorgon LNG project only received regulatory approval once CC(U)S was integrated into the project to capture the CO2 (Stern, 2019[31]).
Establish a measurement, disclosure and reporting, and verification framework for emissions from liquefaction, shipping, and regasification and provide for complete transparency of emissions data and the methodology used to compile them (Stern, 2019[31]); (Methane Guiding Principles, 2020[36]).
Disclose aggregated emissions data in line with recognised international standards, for example the International Organization for Standardization (ISO) framework or the International Group of Liquefied Natural Gas Importers’ MRV and GHG Neutral Framework. Methodologies for emissions measurement, emissions ratios, and accounting practices differ across companies and jurisdictions, so the provision of data in ISO format can ensure better comparability of GHG emissions across the LNG life cycle (Blanton and Mosis, 2021[33]); (GIIGNL, 2021[37]).
Prevent emissions during liquefaction, shipping and regasification whenever possible and reduce those emissions that cannot be prevented (Methane Guiding Principles, 2020[36]).
Identify and repair equipment that is not working properly (Methane Guiding Principles, 2020[36]).
Introduce electrification into the liquefaction process using renewable energy in place of natural gas in order to reduce its energy intensity. Electrification trains and integration of liquefaction projects with CC(U)S have already resulted in emissions reductions (IEA, 2019[32]); (Dauger, 2020[38]).
Consider progressively replacing natural gas feedstock with biogas and biomethane feedstock (depending on availability) (Stern, 2019[31]); (Dauger, 2020[38]).
Participate in voluntary initiatives to reduce methane emissions in the LNG sector. One such example is the International Group of Liquefied Natural Gas Importers (GIIGNL).
Since 2013, Enagás, a Spanish natural gas transmission company that operates Spain’s gas grid and also owns four liquefied natural gas regasification terminals in the country, has implemented a number of best practices to reduce emissions at three LNG regasification plants in Spain:
Leak detection and repair (LDAR) programmes. These are conducted every year at the LNG terminals that Enagás operate in Spain (Barcelona, Cartagena, Huelva) to identify and reduce fugitive emissions. This includes the use of a portable detector (a point sensor) on a daily basis, during start-ups and during maintenance.
Mitigation of emissions from venting. This includes eliminating pneumatics powered by gas, optimising tank pressure, monitoring rod packing (on the boil off gas compressor), LNG truck loading vapour exchange, purging hoses and LNG arms with nitrogen prior to disconnection, and dry disconnecting couplings in LNG truck loading facilities.
Reducing boil-off gas (BOG) venting. During the design phase of their three LNG terminals, Enagás implemented BOG recovery units to recover, compress and send the BOG to the recondenser to be converted into LNG. In 2015, Enagás installed high-pressure BOG compressors to inject non-recoverable BOG into the grid during loading and unloading operations and zero or low send-out modes.
The introduction of these best practices has had a significant impact on emissions from Enagás LNG regasification plants in Spain. Since 2013, total methane emissions have been reduced by 89%, fugitive emissions have decreased by 55% and emissions from venting by 98%.
Source: (Methane Guiding Principles, 2020[36]).
What can importing countries do?
Introduce emission requirements on deliveries of imported LNG as part of their own GHG reduction targets and engage with producers to reduce life cycle emissions from LNG (Stern, 2019[31]) (Blanton and Mosis, 2021[33]).
Introduce requirements for electrifying the regasification process using renewable energy and integrate CC(U)S for CO2 storage, where appropriate (Stern, 2019[31]).
Support the research and development of emissions monitoring along the LNG value chain and encourage the disclosure of emissions calculations and offsets (Blanton and Mosis, 2021[33]).
1.2.5. Reducing methane emissions from coal mining
According to the IEA, in 2021 the global energy sector was responsible for emitting around 135 million tonnes (Mt) of methane into the atmosphere. Of those 135 Mt of methane emissions, an estimated 42 Mt were from coal mine methane – more than oil (41 Mt), extracting, processing and transporting natural gas (39 Mt), bioenergy (9 Mt) and leaks from end-use equipment (4 Mt). The United States Environmental Protection Agency (US EPA) estimates that the coal-mining industry is responsible for 11% of global methane emissions from all human activities (U.S. EPA, 2019[39]). By way of example, coal-related methane emissions from China, the world’s largest coal producer and emitter of coal mine methane, are equivalent to the total CO2 emissions from international shipping (IEA, 2022[16]). The amount of methane emissions from coal mines is likely to be higher than IEA estimates as they do not include emissions from abandoned coal mines due to difficulties in sourcing reliable data. However, recent estimates indicate that abandoned coal mines could account for almost one-fifth of methane emissions from worldwide coal production (IEA, 2022[16]).
Methane occurs naturally in coal seams and the surrounding strata, and is emitted during the mining process. Underground mines are the single largest source of coal mine methane emissions in most countries, as they are typically much deeper than surface mines and the methane content per ton of coal mined increases with increasing depth (GMI, 2011[40]). Furthermore, methane must be removed from underground coal mines, as it is explosive in nature and poses a safety hazard to coal miners. Large-scale ventilation systems move massive quantities of air through the mine but also release large amounts of very low-concentration ventilation air methane (VAM) into the atmosphere (GMI, 2011[40]). VAM accounts for the largest source of coal mine methane emissions globally. In some instances, VAM is supplemented by a degasification system consisting of a network of boreholes and gas pipelines that may be used to capture methane before, during, and after mining activities to keep the methane concentration within safe limits (U.S. EPA, 2015[41]). Methane emissions do not necessarily stop when the mine halts production, as abandoned or closed mines can continue to emit methane from ventilation pipes or boreholes.
There are a number of challenges to the mitigation and reduction of coal mine methane emissions. These include accessing appropriate technology to assess resources, install drainage systems, and select appropriate end use technologies (U.S. EPA, 2015[41]). Commercial utilisation of coal-bed methane is possible, but presents technical and economically viability issues in the absence of policy incentives. As a result, methane drained from coal mines is mostly vented, and there are limited efforts to capture fugitive methane emissions (Delevingne et al., 2020[43]). Further challenges include a lack of adequate infrastructure to transport the gas, clear establishment of property rights to the same gas, and access to capital or financing (U.S. EPA, 2015[41]). Lastly, as countries continue to produce coal, coal mine operators tend to extract coal at increasingly greater depths where, on average, the methane content per tonne is higher (Kholod et al., 2020[44]). However, there are also significant opportunities to reduce methane emissions in the near term by deploying existing technologies and monetising coal mine methane. Methane captured from coal mining can be used in the coal production process, for electricity generation or sold as natural gas. In situations where coal mine methane cannot be effectively captured, the methane may be flared (as opposed to vented), as methane is destroyed by combustion and converted to CO2, a far less potent GHG (Pandey, Gautam and Agrawal, 2018[42]).
Governments should consider prioritising the following actions:
Establish an appropriate mechanism for the collection and dissemination of credible and unbiased data on coal mine methane emissions, including technical and market information (GMI, 2011[40]).
Implement regulations and policies to govern coal mine methane capture and use. Ensure that the property rights of the gas are clearly allocated and understood (GMI, 2011[40]); (U.S. EPA, 2015[41]).
Provide incentives for the deployment of new technologies in small and medium-sized mines.
Implement regulations to ensure that the liability of coal mine operators for methane emissions continues after the mine has been abandoned/closed.
Actions requiring international support in contexts where government capacity is low:
Introduce policies and regulatory regimes to incentivise or require the use of technologies to capture VAM (IEA, 2022[16]).
Introduce requirements for coal mine operators to capture methane using degasification wells and drainage boreholes prior to the start of production (IEA, 2022[16]).
Implement a programme to remediate abandoned coal mines. For example, in the United States, the Abandoned Mine Land programme provides funding for remediating thousands of currently leaking, abandoned coal mines in order to reduce methane emissions. This programme has the benefit of employing tens of thousands of dislocated energy workers in affected communities across the country (Office of Domestic Climate Policy, 2021[45]).
Initiate dialogues and exchange programmes across developing and advanced economies to share international good practices for coal mine closures.
What can the fossil fuel industry do?
Explore options for using coal mine methane in the coal production process (coal drying, heat source for mine ventilation, etc.) (U.S. EPA, 2015[41]).
Explore options for using coal mine methane for on-site power generation. Coal mining is an energy-intensive process, which requires a high electricity load to run equipment including mining machines, conveyor belts, desalination plants, coal preparation plants and ventilation fans. Methane-fired power generation technologies such as gas engines, gas turbines and fuel cells can be used for on-site power while also reducing energy consumption during the coal production process (Pandey, Gautam and Agrawal, 2018[42]).
Explore options for commercialising coal mine methane for electricity or heating – for example, district heating, boiler fuel, town gas or sale directly into natural gas pipeline systems (U.S. EPA, 2015[41]).
Explore options for using coal mine methane as a chemical feedstock to produce synthetic fuels and chemicals – for example, methanol (Pandey, Gautam and Agrawal, 2018[42]).
What can governments and the fossil fuel industry do together?
Transparently share data to advance research geoscience and technological improvements, and to build capacity.
Engage with international public-private partnerships such as the Global Methane Initiative (GMI) to facilitate project development and to advance methane recovery and use at underground coal mines throughout the world (GMI, 2011[40]).
Jointly explore options for commercialising coal mine methane, including in a cluster development with several coal mines/operators. Commercialisation may include: power generation, district heating, boiler fuel, or town gas, or sale directly into natural gas pipeline systems (U.S. EPA, 2015[41]).
Jointly explore the feasibility of flooding abandoned underground coal mines in order to stabilise the hydrostatic pressure on the coal seams which will significantly reduce methane emissions. Systems will need to be put in place to monitor hydrogeological and geotechnical aspects of the mine (Kholod et al., 2020[44]).
1.2.6. Integrating renewables into upstream extractive projects
In order to meet climate objectives, electricity generation for industrial use would need to be fully decarbonised, using electricity from centralised grid or off-grid, supplied by renewable energy sources. This process will in turn depend on the existing and potential supply of decarbonised electricity (and hence the availability of renewable sources, hydrogen or synthetic hydrocarbon sourced net zero emission liquids and gases). Depending on its emissions intensity, the use of grid-based electricity can increase the efficiency of oil and gas and mining operations. This is already the case in some upstream operations, for instance, at the Johan Sverdrup field in Norway, where renewable electricity from the grid is used.
However, many oil and gas operations in developing and emerging economies are in remote locations, disconnected from power plants, where the grid-based supply is not always reliable. Therefore, an alternative approach is to deploy, for instance, decentralised renewable energy sources with storage systems, or off-grid nuclear power reactors (small modular reactors), where cost-competitive. Such initiatives have started to become more widespread, and include a 10 MW Sonatrach-Eni project to power an Algerian oil field with solar PV, or a new 88 MW wind facility to supply electricity to offshore platforms in the Norwegian Sea. Small modular reactors (SMRs) are attracting interest as a low-carbon alternative energy source in resource extraction and mining. In Canada, the oil sands industry is considering SMRs as potential power and heat source (Governments of Ontario, New Brunswick, Saskatchewan and Alberta, 2022[46]), with a demonstration project foreseen to be operational by the mid-to-late 2020s (Global First Power, 2020[47]). Meanwhile, the Russian Federation is planning to use floating and land-based SMRs in power supply for extractive industries (RAOS JSC, 2019[48]). SMRs generally have a power output of between 1 megawatt electric (MWe) and 300 MWe (compared to approximately 1 000 MWe for large reactors). Their components can be manufactured in a factory and transported and assembled on-site, their modularity enabling capacity to be expanded according to the required energy demand. The energy output from SMRs can be used not only to power resource extraction at mining sites, but also for heat supply for residential and industrial applications, including district heating, desalination, and industrial processes.
The IEA has estimated the potential size of integrating renewables into upstream oil and gas operations based on the costs and emissions savings of installing different-sized hybrid solar PV, wind and battery storage systems at new oil and gas facilities. The assessment suggests that it is technically possible to reduce upstream emissions by over 500 Mt CO2 by installing decentralised renewable systems when new resources are first developed.
Governments should consider prioritising the following actions:
Where feasible, mandate the adoption of renewable energy sources for power generation.
Consider the potential contribution of SMRs in decarbonising mining activities and other industrial sectors as part of a portfolio of technological solutions.
Actions requiring international support in contexts where government capacity is low:
Depending on the context, consider introducing a carbon tax, or cap and trade systems, to be eventually integrated with carbon offsets, and phase out inefficient fossil fuel subsidies that disincentivise investments in low-carbon technologies (see also Pillar 3, Section 3.3.1).
Engage with international organisations, such as the Nuclear Energy Agency (NEA) and the International Atomic Energy Agency (IAEA), to develop a better understanding of SMRs.
What can the fossil fuel industry do?
Scope the possibilities for the cost-effective use of renewables in existing and new oil and gas projects.
Understand the economics and technical requirements (e.g. back-up supply in case of power outage) for such an investment.
Prioritise the use of renewable electricity in upstream operations over fossil fuel sources, where renewable sources are a cost-effective alternative.
Advocate and apply for government support through available national and sub-national programs to mitigate financial risk associated with early adoption of SMRs.
Build relationships between SMRs developers and potential customers for further collaboration toward demonstration and deployment.
1.2.7. Deploying carbon capture (utilisation) and storage technology
CC(U)S refers to the process of capturing carbon dioxide (CO2) before it enters the atmosphere, transporting it, and either storing it underground (i.e. in a geological reservoir) or recycling it for industrial usage.
Fossil fuel producer countries may consider the deployment of CC(U)S technologies to reduce emissions in the upstream oil and gas sector as well as other energy intensive and hard-to-abate industrial sectors, such as the cement and fertiliser industries. In addition, the deployment of CC(U)S can help avoid job losses in industries where continued production depends on emissions abatement and allow for a smoother transition to a net zero economy.
Different applications of CC(U)S imply different costs. These costs are largely determined by the initial concentration of the CO2 captured, the availability and proximity of storage capacity and transport infrastructure and the existence of a robust business case. For example, one projection finds that in natural gas processing and fertiliser production, concentrated streams of CO2 can be captured and stored at costs as low as USD 15-25 per tonne of CO2, depending on location. Coal fired power plants retrofitted with CC(U)S have delivered at costs of around USD 65 per tonne of CO2, and studies show that these costs could come down to USD 45 per tonne for new projects (IEA, 2020[49]); (International CCS Knowledge Centre, 2018[50]).
There is considerable potential for cost reductions. Such potential is linked to learning-by-doing effects as CC(U)S is scaled up for different types of applications; reduction of capital and operating costs due to economies of scale and optimisation of operations and maintenance; digitalisation and technology spill-overs from other industries, and improved business models where costs are shared through CC(U)S hubs with broad industry participation (IEA, 2020[49]). The large-scale roll out of CC(U)S is not solely within the sphere of influence of producing countries, but also heavily relies on progress towards climate objectives in consumer markets, in terms of achieving the critical mass required to create demand, technology development and financing. However, perceived levels of risk remain relatively high, driving up financing costs (Global CCS Institute, 2020[51]), and for this reason, government support is essential.
There may be significant opportunities for fossil fuel producer countries to scale up the deployment of CC(U)S, as more than half of the investment required for industrial CC(U)S would need to be located in developing countries (IEA, 2012[52]). However, governments should also consider the risks of relying on assumptions about the timing and costs of global CC(U)S deployment. Implementation of CC(U)S faces technological, economic, institutional, ecological-environmental and socio-cultural barriers, and current rates of CC(U)S deployment are below those in modelled pathways limiting global warming to 1.5°C or 2°C. Many existing CC(U)S projects have been designed for enhanced oil recovery, and only 8 of the 26 existing global CC(U)S projects are dedicated to the long-term storage of CO2. Furthermore, the IPCC has also stated that the global deployment of CC(U)S technologies should be limited to 3.8 Gt CO2 per year (under a scenario of medium feasibility concerns), which may constrain global scale-up (IPCC, 2022[53]).
Canada: In 2021, the Government of Canada launched the development of a federal CC(U)S Strategy to enable the CC(U)S industry to realise its GHG reduction and commercial potential on the path to a net-zero economy. In 2022, the government announced that they would invest CAD 319 million over seven years into research, development and demonstrations to advance the commercial viability of CC(U)S technologies. These funds will support businesses, academia, non-profits, government and federal laboratories on the path to net-zero emissions by 2050.
European Union: The Innovation Fund (EUR 10 billion from 2020-30) provides funding programmes for the demonstration of innovative low-carbon technologies and processes in energy-intensive industries, including products substituting carbon-intensive ones. Examples include carbon capture and utilisation, the construction and operation of carbon capture and storage (CCS) and innovative renewable energy generation and storage.
The Netherlands: The Sustainable Energy Transition Scheme (SDE++) is intended to stimulate the production of clean and sustainable energy. CC(U)S and blue hydrogen are also eligible. It is financed by surcharge on the energy bills of citizens and companies.
United Kingdom: The Carbon Capture and Storage Infrastructure Fund (GBP 1 billion) is intended to support deployment of CC(U)S in a minimum of two clusters by the mid-2020s, and four clusters by 2030 at the latest, with an ambition to capture 10 Mt CO₂/year by 2030. In is intended to provide support for capital expenditures on CO2 transport and storage networks, and industrial carbon capture projects.
Source: (IEA, 2022[54]); (BEIS, 2021[55]); (Directorate-General for Climate Action, 2022[56]).
Governments should consider prioritising the following actions:
Provide the national geological survey authority, or equivalent government entity, including NOCs, with the capacity to undertake geological mapping to identify and assess CO2 storage sites, and establish a national register or atlas, enabling the licensing and commercialisation of CC(U)S activities. This process does not need to be resource-intensive, as geological surveys can base storage mapping activities largely on existing geological information generated by oil and gas exploration and production.
Determine whether highly concentrated large-point source emitters of CO2 are relatively close and well connected to potential storage sites.
Allocate CC(U)S projects to companies that already have the required capacity with regard to geological knowledge, relevant operational experience, and infrastructure capacity to develop and operate CC(U)S infrastructure.
Develop a CC(U)S investment-friendly tax regime (see Box 1.13).
Where incentives for CC(U)S are in place, ensure they reflect a fair sharing of the risks and costs between governments and investors.
Actions requiring international support in contexts where government capacity is low:
Establish CC(U)S regulatory frameworks, including independent third-party verification of storage sites, provisions for monitoring, environmental impact assessments, consultation mechanisms, and requirements for post-closure stewardship of projects, including liability and provisions for long-term monitoring, to provide the private sector with the necessary confidence to invest (Global CCS Institute, 2020[51]).
Consider working with neighbouring countries to develop a regional framework for the sequestration, transport and storage of CO2, drawing on the experience of the London Protocol and the Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR). This would help remove legal barriers to a regional cluster-based CC(U)S approach.
Undertake an in-depth cost-benefit analysis to assess capture and storage efficiency and integrity, as leakage undermines economics, public acceptance, and environmental benefits.
Establish capacity within the public sector, or through partnerships with private specialist firms, to conform to relevant ISO standards (27914:2017; 27915:2017; 27916:2019) for carbon dioxide capture, transportation and geological storage at milestones in the CC(U)S project life-cycle: screening and selection of storage sites, qualification of site, application for permits, design and development of project, and operation and closure.
Develop CC(U)S pilots and then demonstration projects to foment the research and deployment rates needed for CC(U)S to take off in developing countries (Almendra et al., 2011[58]).
Play a co-ordinating role to establish CC(U)S hubs across high-carbon industrial sectors to achieve scale and create demand for CO2 storage. The development of CC(U)S hubs in industrial areas, where CC(U)S transport and storage infrastructure is shared among various industrial users, can reduce capture and storage costs through economies of scale. This, in turn, reduces the costs for industrial facilities of incorporating CC(U)S into their production process, and could attract new investments, while maintaining existing facilities under increasingly climate-constrained conditions (IEA, 2019[59]).
Consider emission standards and labelling or certification of low-carbon products.
Provide long-term predictability for investors considering investing in CC(U)S. This may include a price on carbon sufficiently high to push industry players to join forces to invest in CC(U)S, or tax credits such as the 45Q in the United States, which provides the price visibility for investing in CC(U)S.
Where feasible, provide grant support, government investment, operational subsidies (tax credits, contracts-for-difference, feed-in tariffs), demand-side measures (public procurement), CC(U)S-specific market mechanisms (tradable certificates and carbon storage units), and funding for research and development.
Carbon taxation can help deploy CCS in natural gas production. In 1990, during the planning phase of the Sleipner project, located in the Norwegian part of the North Sea, it became clear that the natural gas contained about 9% of CO2, exceeding customers’ specifications of a maximum 2.5% share. Therefore, the CO2 content needed to be reduced before the natural gas could be sold. Rather than venting the separated CO2, Equinor, the operator of the field, decided to invest in CCS technology. In 1991, the Norwegian government introduced an offshore CO2 tax in an effort to reduce emissions. This tax would have applied to any CO2 released from gas extracted from Sleipner. The CO2 tax was one of the triggers for operator Statoil’s plans to separate CO2 offshore and inject it into deeper geological layers. Due to the Norwegian CO2 emissions tax, it became more economical to store the CO2 once captured than venting it.
Source: (OECD Development Centre, 2019[60]).
What can the fossil fuel industry do?
For storage purposes, share relevant geological information, including the capacity of depleted reservoirs, including the results of geophysics and geochemical assessments, with national geological survey authorities and NOCs.
Inform governments where gaps in geoscience knowledge may exist that inhibit investment in the deployment of CC(U)S.
Support technology transfer to NOCs or other relevant government entity in charge of CC(U)S deployment.
Introduce feasibility studies into industrial hubs to better understand the economic viability of CC(U)S applications including linkages to broader economic development opportunities such as hydrogen production (see Pillar 3, Section 3.2).
Leverage horizontal cross-sector industry collaboration in industrial hubs to lower high upfront capital costs and enable the development of potential pilot projects that benefit industry stakeholders.
Quest CCS project, Canada
Public-private collaborative approaches in Alberta have led to achievements in the deployment of CC(U)S technology. The Shell Quest CCS project received CAD 120 million from the Government of Canada and CAD 745 million from the Alberta government to sequester CO2 emissions from oil sands operations in Alberta. The Shell Quest plant has sequestered 5 million tonnes of carbon dioxide emissions and has reported savings in operating costs, with the facility operating at CAD 25 tonne of stored CO2 instead of the anticipated CAD 40 per tonne. Alberta remains the leading provincial candidate to deploy CC(U)S technologies, with the Alberta Carbon Trunk Line (ACTL) project opening in 2020. Canada’s recognition of CC(U)S as technologically and commercially viable has been outlined in the federal budget, with tax incentives for companies that invest capital in CC(U)S projects.
Longship CCS project, Norway
The Longship CCS project will capture and store the carbon emissions of Norcem's cement factory (confirmed) and Fortum Oslo's Varme waste incineration facility (planned, pending full financing). Longship CCS plans to demonstrate that the deployed CC(U)S technology is functional for larger industrial plants and can set a new standard for future industrial projects. "Northern Lights", the storage part of the Longship project, is a joint project between Equinor, Shell and Total, financially supported by the Norwegian government through Longship. The Northern Lights project will transport liquid CO2 from capture facilities to a terminal on the Norwegian North Sea coastline. From there, the CO2 will be pumped through pipelines to a geological reservoir beneath the seabed. Longship builds on Norway’s experience from the Sleipner CCS Project, operational since 1996 as a result of Norway’s carbon tax for the oil and gas sector, implemented since 1991.
Norway has established a framework of research and financing entities to support the deployment of CC(U)S through partnerships with private companies. This includes the development, construction, and operationalisation of the Longship CCS project. The framework consists of three main components: Gassnova, CLIMIT and TCM. Gassnova was established by the Norwegian authorities in 2005 to further the development of technologies and knowledge related to CC(U)S. Gassnova also serves as the adviser to the government on this issue and has been tasked with administrating the research and financing programme CLIMIT, and with ensuring the testing and developing of CC(U)S technologies at the Technology Centre Mongstad (TCM). CLIMIT and TCM are key elements for the realisation of Europe’s first industrial-scale project for carbon capture and storage, Longship CCS. CLIMIT was set up in 2005 by the Norwegian Ministry of Petroleum and Energy, to support the development of CC(U)S technology for gas power plants. The scheme was expanded in 2008 to include power generation based on all fossil fuels, and in 2010 industrial emissions were included. CLIMIT’s primary objective is to contribute to the development of technology and solutions for CC(U)S by providing financial support to projects that will: develop knowledge, expertise, technology and solutions that can contribute towards cost reductions and international deployment of CC(U)S.
Test Centre Mongstad (TCM) is the world’s largest test centre for developing CO2 capture technologies, and a leading competence centre for carbon capture. TCM was established to test, verify and demonstrate different technologies related to cost-efficient and industrial-scale CO2 capture, and also provides advisory services to carbon capture projects. TCM offers technology developers and project developers’ opportunities to reduce technological and financial risk, by testing and verifying carbon capture technology ahead of full-scale application. TCM is owned by the Norwegian State, through Gassnova (73.9%), together with the industrial partners Equinor (8.7%), Shell (8.7%) and Total (8.7%). Equinor is the operator of the facility.
Source: (Bakx, 2020[61]); (CCS Norway, 2022[62]).
1.2.8. Utilising CO2
Carbon dioxide (CO2) is a major contributor to climate change. However, CO2 can also be a valuable input to a range of processes and products including the production of fuels, chemicals and building materials. Interest in this quality is reflected in increasing support from governments, industry and investors, with global private funding for CO2 use start-ups reaching nearly USD 1 billion over the last decade (IEA, 2019[63]).
Utilisation processes are designed to convert CO2 into higher-value products (e.g. fuels, plastics) or into stable products for long-term storage (e.g. concrete, minerals). CO2 can also be used to produce methanol, which in turn, can be used to produce energy or as a component of automotive fuel (see also Pillar 3, Section 3.6). The fertiliser industry is the largest consumer of CO2, with around 130 Mt CO2 per year used in urea manufacturing. This is followed by the oil sector where 70-80 Mt CO2 is used annually for enhanced oil recovery (EOR), which equates to around 5% of the total crude oil production in the United States. CO2 is also used in the production of food and beverages, the fabrication of metal, in cooling, fire suppression and greenhouses to stimulate plant growth (IEA, 2019[63]); (Hepburn et al., 2019[64]).
While some technologies are still at an early stage of development, CO2 use can support climate goals where the application is scalable, uses low-carbon energy and displaces a product with higher life-cycle emissions. However, CO2 use does not necessarily reduce emissions, and quantifying climate benefits is a complex process, requiring a comprehensive life cycle assessment of its impacts as well as an understanding of market dynamics (IEA, 2019[63]); (Hepburn et al., 2019[64]).
Governments should consider prioritising the following actions:
Ensure policy and investment decisions for CO2 use applications are informed by robust life-cycle analysis that provides improved understanding and quantification of the climate benefits and risks associated with continuous reliance on fossil fuels (IEA, 2019[63]; Hepburn et al., 2019[64]).
Identify opportunities for the use of CO2 to create petrochemical products. For example, several companies have built pilot plants producing methane and methanol from CO2 and hydrogen. Commercial production of CO2-derived methanol and methane could be possible in markets where both low-cost renewable energy and CO2 are available, such as Chile, Iceland and North Africa (IEA, 2019[63]).
Actions requiring international support in contexts where government capacity is low:
Identify and enable early market opportunities for CO2 use that are scalable, commercially feasible and can deliver emissions reductions. The use of CO2 in building materials is one such opportunity as the CO2 remains sequestered well beyond the lifespan of the infrastructure itself (IEA, 2019[63]); (Hepburn et al., 2019[64]).
Consider introducing public procurement guidelines for low-carbon products. This can create an early market for CO2-derived products with verifiable CO2 emissions reductions, and promote innovation and investment (IEA, 2019[63]).
Establish performance-based standards for products such as building materials, fuels and chemicals to facilitate the uptake of CO2-derived alternatives (IEA, 2019[63]).
Support research development and demonstration for future applications of CO2 use that could play a role in a net-zero economy, including as a carbon source for aviation fuel – a sector that is difficult to decarbonise (IEA, 2019[63]; Hepburn et al., 2019[64]).
Consider putting a price on carbon. Carbon pricing can act as an incentive to capture CO2 and use it (or sell it for use) in the manufacture of products or services, provided this is the cheapest compliance strategy for the emitter. Carbon pricing of around USD 40 to USD 80 per tonne of CO2, and increasing over time, may be sufficient to scale-up CO2 utilisation (IEA, 2019[63]; Hepburn et al., 2019[64]).
What can the fossil fuel industry do?
Undertake research, development and demonstration to test the climate benefits of CO2 use applications, including chemicals and aviation fuels (Hepburn et al., 2019[64]).
Consider using CO2 for enhanced oil recovery in existing fields. Naturally, recoverable oil in a reservoir typically represents about 20% of the resource, but injecting CO2 can stimulate additional production of up to 13%. Companies should evaluate which reservoirs may be suitable for CO2 enhanced oil recovery (Ward, 2020[65]).
Extractive-based developing and emerging economies are confronted with a large technology gap, which needs to be addressed to avoid hampering their transition to a low-carbon future. According to the World Bank, low-income countries account for just 0.01% of low-carbon technology exports and 0.3% of imports, whereas between 2010 and 2015, high-income countries produced 80% of all low-carbon technology innovations (Pigato et al., 2020[66]). To ensure a just and equitable low-carbon transition, it is necessary for developing countries to have access to low-carbon technologies, based on technology transfer and innovation, capacity building, and finance so they can reap the benefits from a sustainable, resilient and inclusive recovery and integrate existing low-carbon value chains or create new regional ones.
Without targeted policy support and long-term financing, extractive-based developing and emerging economies will continue to face an investment preference for high-carbon technologies, given the capital sunk into pre-existing fossil fuel value chains and the high-carbon industries created around them (Pigato et al., 2020[66]).
However, extractive-based developing and emerging economies need to seize opportunities from the low-carbon technology sector, which would provide a new driver for sustainable economic growth and greener job creation. Getting policy, regulation and pricing right is crucial to a country’s attractiveness for low-carbon finance and technology transfer.
1.3.1. Creating an enabling environment to incentivise the deployment of low-carbon technology
Governments should consider prioritising the following actions:
Phase-out inefficient fossil fuel subsidies that hinder investments in new low-carbon technology, including by shifting public resources away from NOC spending on the highest-risk oil and gas projects (see also Pillar 3, Section 3.3.1).
Consider the potential of a long-term commitment to carbon pricing to guide investment decisions taken by both public and private sector actors, and reduce the risks of stranded assets and stranded jobs (see also Pillar 3, Section 3.3.1).
Consider the revenue potential of carbon pricing, to support domestic resource mobilisation efforts. Developing and emerging economies would be able to raise revenue equivalent to approximately 1% of GDP on average if they raised carbon rates on fossil fuels to a benchmark of EUR 30 per tonne of CO2 (OECD, 2021[67]) (see also Pillar 3, Section 3.3.1).
Reform fuel excise taxes to better align with the climate costs of fuel. Fuel-based carbon taxes are the most common form of carbon taxation in many countries. In countries that lack the administrative capacity to manage an emission trading system or a carbon tax, excise taxes that reflect the targeted price on carbon can be an effective policy instrument to make polluters pay for these externalities. In order to incentivise reduced emissions during production, fuel excise taxes would also have to be charged on the share of natural gas that oil and gas companies use for their own production process – to run generators, for use in refineries, etc. (see also Pillar 3, Section 3.3.1).
Actions requiring international support in contexts where government capacity is low:
Build capacity to measure and monitor emissions and apply carbon pricing to analysis and decision making. Institutions that manage and operate in the upstream – including ministries of energy and power, upstream regulators and NOCs – can help manage emissions (Bradley, Lahn and Pye, 2018[1]).
Use a carbon price in studies for public investment projects, including for environmental impact assessments, to ensure that the right decarbonisation incentives are in place.
Consider providing public funding (grants, loans and concessional debt) to reduce the risks of basic research and demonstration projects, combined with tax credits for private involvement in low-carbon technology demonstration projects.
Mitigate the distributional effects of tax reforms, ensuring that the poor will be able to access clean and affordable energy. Consider using part of the revenues from carbon price reform to meet social objectives (see also Pillar 3, Section 3.3.1).
Consider the potential of carbon pricing to help tackle informality and lower the relative tax burden on the formal sector. Unlike many direct taxes, where firms and individuals can avoid taxation by operating in the informal economy, energy taxation and carbon taxes can be more difficult to avoid since even informal firms must buy energy from the formal sector.
Ensure that carbon pricing does not generate unsustainable biofuel switching, which could lead to deforestation or is otherwise unsustainable. Implement and enforce policies that ensure the sustainability of biofuels, as outlined in Pillar 3, Section 3.2.4.
Foster technology trade among countries, including through the reduction of tariffs to lower technology trade barriers and providing subsidies to encourage more technology trade.
Consider the introduction of a differential tax treatment for the import of energy intensive equipment coupled with restrictions on the production of high-carbon products to guide the market and promote the development of local high value-added and low-carbon industries.
Use NOC and government licensing and set procurement standards to steer the domestic market in low-carbon products and services. Set incentives for industry to meet emission targets, such as making licensing and procurement contingent on industry hitting such emissions targets.
Establish the right price regimes to incentivise cleaner, more efficient practices, and gradually taxing higher-emissions fuels and use the revenues to invest in low-carbon development (including public goods), as discussed in Pillar 3, Section 3.3.
Consider introducing wellhead carbon taxes to reduce emissions from oil and gas projects, as well as from coal mining. These taxes are collected from producers rather than consumers of fossil fuels and unlike emissions-based carbon taxes, wellhead taxes are not rebated when fuel is exported. Hence, they generate a revenue stream for producing countries. Wellhead taxes also offer a possible alternative solution to carbon border adjustment taxes (Peszko et al., 2020[68]).
Wellhead taxes
As proposed by the World Bank, wellhead taxes can provide an alternative to carbon border adjustment taxes (CBATs). Wellhead taxes have not yet been tried out, but could become a relevant alternative if countries or trade blocks introduce CBATs.
The main differences between wellhead taxes, carbon taxes, and carbon border adjustment taxes is their placement along the energy value chain, and the distribution of the proceeds.
Wellhead taxes are collected from producers “at the wellhead”, so that consumers of fossil fuel products both in the producing and the importing country pay for the emissions associated with the extracted oil, gas or coal. Wellhead taxes shift the carbon tax base from importing countries, where a carbon tax would be levied on consumers of fossil fuel products, to exporting countries, where the wellhead tax is levied on producers. If the carbon price used to determine the wellhead tax is the same as the carbon price applied in the importing country, fossil fuel consumption will be equally costly in both countries. In its “extreme” version, the wellhead tax is collected from producers at the wellhead only, with all of the proceeds remaining in the exporting country. In more realistic versions, various revenue-sharing ratios would be bilaterally or multilaterally negotiated between fossil fuel exporters and importers through agreements on the harmonised tax rates. This can be calculated so that the exporting country retains (roughly) the share of wellhead taxes paid by its citizens, while the importing country would retain the share paid by consumers.
In principle, wellhead taxes can provide an incentive for industry and citizens to shift to renewable energy sources, which are not subject to this tax, However, as they are levied at a considerable distance from the end consumer, it can be hard for this instrument to change end consumer behaviour. Furthermore, since wellhead taxes are not levied directly on GHG emissions, they address only energy-related emissions. Wellhead taxes will therefore not provide incentives for curbing process emissions from industry. In cement production, for example, emissions resulting from chemical processes can be as much as 60% of total emissions. Wellhead taxes will also not address other non-energy related emissions, for example in agriculture. Thus, for non-energy related emissions, wellhead taxes would need to be complemented with other measures.
As an alternative to carbon pricing (carbon taxes or emissions trading schemes), wellhead taxes are easy to estimate and levy.
Carbon pricing
Carbon pricing differs from wellhead taxes in that it is a direct price on GHG emissions. This means that a carbon price, whether in the form of a carbon tax or an emissions trading scheme, can in principle be imposed on any type of emissions source, in any sector. The proceeds from carbon pricing, levied on consumers on fossil fuels, go in entirety to the country where the tax is levied. Compared to wellhead taxes, carbon pricing is more complex to administrate. At the firm level, carbon pricing requires capacity to measure and report emissions. At the government level, carbon pricing requires capacity to monitor and verify firms’ compliance and accuracy of reporting.
Carbon border adjustment taxes
Carbon border adjustment taxes, or mechanisms, consist in the importing country (or trade block) of imposing a carbon price on the imported product, based on an estimate of the emissions embedded in the product and the difference between the carbon price in the exporting and the importing country. The tax is paid at the border by the importers, and all of the revenues from the CBAT go to the importing country.
When a carbon price is imposed in the exporting and importing country, fossil fuel producers and other energy-intensive industries are charged for their emissions in both countries. There is no need for a CBAT if the carbon price in the two countries is the same and is implemented equally efficiently in both countries. If the exporting country has a lower carbon price, companies in the importing country will lose competitiveness, necessitating a partial CBAT.
Source: (Peszko et al., 2020[68]).
1.3.2. Fostering sustainable technology transfer
Sustainable technology transfer is a multifaceted process that goes far beyond the transmission of technological hardware, and covers the transmission of knowledge, experience and skills to deploy, operate, maintain, adapt, improve and reproduce the transferred technology. It follows that technology transfer requires system-wide, process-driven thinking to foster a process of learning and interactive collaboration among different stakeholders (e.g. governments, private sector entities, financial institutions, non-governmental organisations (NGOs) and research/education institutions). The deployment and diffusion of new technologies will depend on countries’ pre-existing technological capabilities, size of market and productive capital base, which underpin the large capital investments needed to produce and eventually exporting low-carbon technology, as well as the ability of countries and sectors to build new human, physical, institutional, organisational and financial capabilities, particularly for complex technology. The transfer of technology will also depend on: 1) the ability of technology providers and third-party organisations to identify impactful projects and suitable partners in host countries; 2) the creation by host governments of policy, regulatory, and legal frameworks that reduce risks and attract private and public investors; and 3) the ability of firms in host countries to understand, select, adapt and replicate viable technologies that are suited to domestic circumstances and needs (Pigato et al., 2020[66]).
While some recommendations are targeted at IOCs and NOCs, it is recognised that other players in the value chain (e.g. service companies, local companies) must be considered to identify broader opportunities to accelerate and implement sustainable technology transfer.
Bearing in mind that there are different types of NOCs (operators and non-operators) with different mandates, capabilities and resources, which will have a bearing on outcomes, governments should provide the necessary enabling conditions and long-term incentives to effectively promote sustainable technology transfer from IOCs to NOCs in order to reduce emissions and improve efficiency of upstream, midstream and downstream operations.
Governments should consider prioritising the following actions:
Uphold good governance and the rule of law, and provide political stability through a predictable and transparent legal, regulatory and economic environment.
Incorporate technology transfer obligations into contractual arrangements, such as licensing between business partners, joint ventures and co-operation agreements.
Consider providing for a share of operational management and staff positions for the NOC, as the shareholding partner, in order to promote the development of both technical and managerial skills. Capacity building is a key issue for technology transfer to recipient emerging and developing countries and their NOCs, and should be taken into account at an early stage in project planning, by providing for NOC management and staff positions in the cooperation project or joint venture.
Actions requiring international support in contexts where government capacity is low:
Adopt a climate and emissions reduction strategy, including emissions reduction targets and caps. Where relevant, this should include natural gas and associated gas, in particular to provide clarity to investors and facilitate systemic and industry-wide solutions, as opposed to individual company or project approaches.
Review existing legal instruments for the petroleum sector, including the introduction of obligations for operators to deploy industry best practices and best available technological solutions for decarbonising operations. For example, any field development plan should incorporate plans for decarbonising operations and managing the risk of stranded assets.
Assess the available human, physical, financial, and organisational capital as well as the up-front costs of low-carbon technologies.
Assess the need for complementary investment in infrastructure, such as pipelines for associated gas or storage, and power grids and transmission networks for effective renewable energy deployment.
Provide fiscal incentives and fast-tracking decision-making processes, such as tax exemptions or subsidies, for investments in feasibility studies for low-carbon technology deployment, in order to de-risk investments.
Share the costs and risks for technical and capital-intensive carbon reduction technologies by adopting a systemic approach that stimulates the creation of multiple partnerships across the value chain.
Assess the readiness for a market for decarbonised products.
Identify opportunities for technology transfer that reflect the country context and proactively engage with government.
Incorporate technology transfer into the design and implementation of projects.
Consistently deploy best available technologies and practices in their operations across different countries, going beyond applicable regulatory requirements.
Offer free carry equity to the NOC. Free carry equity allows capital constrained NOCs to deploy low-carbon technology that they may otherwise not be able to deploy. Due consideration should be given to increased exposure to risk of continuous reliance on fossil fuels, since the value of the carry will be drawn from the government take of revenues, potentially putting public capital at risk of stranding.
What can IOCs and NOCs do together?
Ensure that projects generate acceptable returns for all parties and that risk/rewards sharing arrangements are reflected in the terms of the licence or production sharing agreement.
Establish an IOC/NOC peer-to-peer learning process, whereby the most experienced NOCs and IOCs share insights around emissions management, carbon pricing and markets, and the integration of energy efficiency measures and renewable energy within the industry, as well as the reform of long-term commercial strategies and national mandates.
Ensure management commitment within the IOCs and NOCs to drive technology transfer.
Involve local energy companies, service providers and original equipment manufacturers (OEM) in the deployment of technology transfer solutions.
Second NOC staff to more experienced NOCs or IOCs to familiarise themselves with low-carbon technologies.
Share data on GHG emissions (e.g. methane and CO2) among IOCs and NOCs to enable appropriate deployment of technology.
Channel technology transfer through joint ventures and leverage state participation as a conduit for transferring know-how and best practice among several operators.
What can development finance institutions do?
Provide technical support for the development of an enabling regulatory framework for the uptake and transfer of low-carbon technologies.
Fund pre-investment feasibility studies for low-carbon technology deployment to provide the basis for evidence-based investment decision making.
Assist NOCs and their governments in negotiating contracts, including technology transfer and cost/risk-sharing clauses.
Deploy guarantees to reduce the risk for private investors and attract private investments and commercial financing to support decarbonisation in developing countries. The guarantor agrees to pay part or the entire amount due on a loan, equity or other instrument in the event of non-payment by the obligor or loss of value in the case of investment. Such schemes provide risk mitigation with respect to obligations due from government and government-owned entities – such as NOCs to private investors.
Background
In October 2020, the NNPC and Sterling Exploration and Energy Production Company (SEEPCO) signed an agreement for the development and commercialisation of gas from the Oil Mining Lease 143. The agreement on associated gas processing and commercialisation seeks to help reduce gas flaring and its environmental hazards, and to promote gas production and utilisation in the domestic market. NNPC had encouraged SEEPCO to monetise not only associated gas but also non-associated gas, but this was postponed until the joint development agreement could be signed.
Project structure
The gas processing plant is structured as a lease-to-own contract, with original equipment manufacturers (OEMs) providing full financing for the equipment. The main OEMs are Exterran and GCI, which between them provide the main components of the plant. Exterran provides the dehydration unit, the heat exchanger, the sub-cooling unit, and the mechanical refrigeration; GCI has delivered the compressors and generators, as well as the debutaniser, the de-methaniser, and de-propaniser.
The rate of down payment on OEM financing will be determined by the productivity of the plant and the price of natural gas. At current production and price levels, SEEPCO and NNPC expect to take joint ownership of the project within seven years after the project becomes fully operational in the second quarter of 2021. SEEPCO will then own 83% of the equity, whereas NNPC will own 17%, corresponding to its initial share of the project in the form of free carry. In return for the free carry, NNPC provides expertise and knowledge of the local Nigerian context. Among other things, NNPC took care of permitting and liaising with local and federal authorities, agreements with landowners, as well as communication with communities affected by the construction of installations and pipelines, and with other local stakeholders. SEEPCO pays the land lease, and other expenses not directly related to the OEM equipment.
Knowledge transfer
NNPC and SEEPCO contemplated knowledge transfer from the start of project planning, and decided to embed knowledge transfer into the managerial structure of the processing plant. As such, the processing plant is staffed jointly by NNPC and SEEPCO managers and staff, with the general manager coming from SEEPCO, and three deputy managers distributed between NNPC (two deputy managers) and SEEPCO (one deputy manager). To determine training needs, SEEPCO conducted a SWOT analysis of NNPC and SEEPCO teams, based on nominations of candidates by each of the companies. One conclusion from the SWOT analysis was that neither of the two companies possessed the required profile for the general manager position, and a general manager was hired externally. Training was organised as a top-down exercise, with representatives from Exterran and GCI providing on-site as well as classroom training, for the SEEPCO general manager and the NNPC and SEEPCO deputy managers. The onsite training took NNPC and SEEPCO managers and staff through the project stages of commissioning and ramping up, to full productive capacity, over a period of about six months. The OEMs provided two different teams for the commissioning period and the operational period, respectively. At the plant, the OEM teams provided on-the-job training for the manager and three deputy managers. These 4 were in turn responsible for training 12 staff each, 10 of them local and 2 expatriates in each training group.
Exterran and GCI will maintain on-site staff for one year. NNPC, SEEPCO, Exterran, and GCI will then hold a two-way assessment to decide whether the joint NNPC-SEEPCO operational team is ready to take over plant operations, after operational and maintenance routines are well established among NNPC and SEEPCO staff. This will enable Exterran and GCI representatives to move offsite, permitting them to reduce their costs. There is no definitive deadline for OEMs to move off-site, and the consortium will undertake quarterly reviews to determine whether an extension of OEM on-site presence is necessary. SEEPCO and NNPC plan for a major capacity-building review in 2025, with intermediate annual reviews, and will take account of continuous technological developments in natural gas processing. SEEPCO and NNPC also have sought to further transparency and openness between themselves as partners, and to facilitate integration of NNPC and SEEPCO staff activities at the shared processing plant into a single operational structure.
Climate benefits
The climate benefits of the processing plant come from the avoidance of flaring, so that gas that would have been flared can now be used for electricity production at a 1500 MW plant now under construction. Then remaining natural gas will be delivered to customers in gas-based industries, fertiliser production, and other commercial customers. As these customers would otherwise have used non-associated gas, the total emissions resulting from gas delivered to these customers is reduced.
Whereas carbon capture and storage for CO2 resulting from natural gas processing could be contemplated in the future, this option has not yet been considered.
Transfer technology lessons
Transfer technology lessons from the NNPC-SEEPCO case study include:
Transparency: private oil companies gain from being transparent about their emissions with governments, NOCs, and other partners. In the case of SEEPCO, gas that SEEPCO vented and flared was identified by NNPC as a business opportunity for capturing, producing and selling not only associated gas, but also non-associated gas.
Partner knowledge and experience: it is important to work with partners that have the required capacity. Capacity development can go both ways – from IOC to NOC, but also from NOC to IOC or independent producers. This is particularly the case where the NOC is a large and well-established company with a broad set of competencies, and the private counterpart is a smaller company with a narrower set of capabilities. In this case, NNPC helped SEEPCO enter the midstream space.
Commercial mind set: it is important to design well-functioning business models across the natural gas value chain, with functional partnerships along each level of the chain.
Bringing in regulators early: collaborative arrangements need to involve regulators in the process at an early stage. Early attention to regulatory issues is likely to reduce regulatory compliance costs at later stages, and cumulative compliance costs throughout the lifecycle of the project.
Customer base: off-take agreements must be ready when the plant starts producing.
Source: Adapted from the interventions by NNPC and SEEPCO to the Sixteenth Plenary Meeting of the Policy Dialogue on Natural Resource-based Development on 1 July 2021.
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[23] World Bank (2022), Global Flaring and Venting Regulations: A Comparative Review of Policies, World Bank, https://www.worldbank.org/en/topic/extractiveindustries/publication/global-flaring-and-venting-regulations.
[21] World Bank (2022), Zero Routine Flaring by 2030 (ZRF) Initiative, https://www.worldbank.org/en/programs/zero-routine-flaring-by-2030/initiative-text.
[28] World Bank (2021), Gas Flaring Volume and Flaring Intensity Charts, Global Gas Flaring Reduction Partnership (GGFR), https://www.worldbank.org/en/programs/gasflaringreduction/global-flaring-data#imported-flare-gas-index.
[25] World Bank (2004), Regulation of associated gas flaring and venting : a global overview and lessons from international experience, World Bank Group, Washington D.C., http://documents.worldbank.org/curated/en/590561468765565919/Regulation-of-associated-gas-flaring-and-venting-a-global-overview-and-lessons-from-international-experience.