Methane Abatement in Developing Countries

8. Regulatory building block 5: Incentivising methane emissions abatement

Box 8.1. EFFECT recommendations: Economic instruments and incentives to reduce methane emissions

What can governments do?

• Implement a reward-penalty system to incentivise methane emissions reduction

• Ensure that the ownership of associated gas is clear and understand associated implications

• Address gas infrastructure challenges

• Ensure that methane investments are cost-recoverable

• Encourage associated gas clustering opportunities

• Prioritise access for associated gas into the gas network.

Source: Adapted from (OECD, 2022[1]).

Compliance with measurement, monitoring, reporting, verification and other methane abatement requirements can imply higher operating and capital costs, making oil and gas projects less profitable. Such additional costs are the price of negative externalities of oil and gas projects on the environment that need to be factored into project feasibility studies. In practice, incremental costs can deter both governments and operators from delivering deep emissions cuts.

Governments should consider providing incentives for companies to reduce methane emissions from upstream oil and gas operations. Such incentives can be a powerful companion tool to methane abatement requirements and can incentivise oil and gas companies and other market participants to invest in technologies and infrastructure to reduce methane emissions.

In order to incentivise operators to contribute to curbing emissions, governments can design a carefully balanced reward-penalty system with a view to ensuring that it is cost-effective for companies to deploy technologies and solutions that reduce methane emissions. Alongside financial rewards for oil and gas companies that take action to reduce their emissions, the system should also penalise those that do not comply with methane abatement regulations.

The reward component

The reward component can take different forms, including through direct financial support for methane abatement, cost-recovery provisions under production sharing agreements (PSAs), and market-based mechanisms.

Direct public financial support for methane abatement

Some governments provide direct financial support to oil and gas companies to reduce methane emissions from their oil and gas operations. For example, in the United States, the Inflation Reduction Act 2022 established the Methane Emissions Reduction Program which makes available USD 1.55 billion for financial and technical assistance for methane abatement in the oil and gas sector.1 In Canada, the Emissions Reduction Fund 2020 provides a mechanism where oil and gas companies can receive financial support to reduce routine venting of natural gas from oil and gas operations beyond compliance with regulatory requirements – see Box 8.2.

Box 8.2. Incentivising methane reductions in Canada: The Methane Emissions Reduction Program

Launched in 2020, the Emissions Reduction Fund (ERF) aims to incentivise onshore and offshore oil and gas companies invest in clean solutions to reduce GHG emissions and retain jobs in the sector. Applications to the ERF can be made by Canadian upstream oil and gas companies as well as midstream gathering and processing infrastructure companies.

Project requirements

ERF onshore projects considered for funding must eliminate routine intentional venting or flaring of methane emissions and surpass the applicable regulatory requirements for the facility/operation and must result in net emissions reductions that are verifiably incremental to what is required under the relevant regulation(s). Potential projects include, but are not limited to, the following examples:

• Projects that eliminate venting and/or flaring sources at surface facilities (e.g. single wells, multi-well batteries, gas processing, tanks, etc.)

• Pipeline infrastructure projects that will facilitate the conservation of otherwise vented and/or flared gas streams

• Projects that conserve otherwise vented or flared methane rich gas for onsite fuel use; and

• Projects that eliminate venting from pneumatic devices.

Funding requirements

In order to attract substantial projects that will have a noticeable impact, the ERF onshore programme offers a minimum of CAD 100 000 and a maximum of CAD 50 million per company. Successful applicants will be subject to the following requirements:

• up to 75% of total project cost with the option to stack with funding up to 90% from other sources, such as provincial programmes

• repayable and partially repayable contributions

• a five-year payback period after project completion

• expenses must be related to the project, such as Baseline Opportunity Assessment, salaries and benefits related to the project, capital expenses, and equipment rental.

Source: (Natural Resources Canada, 2020[2]).

However, public financing does not represent a feasible option for oil and gas developing producing countries as most of them are already fiscally constrained and highly indebted. In addition, governments would find it difficult to justify the subsidisation of methane abatement measures, given the pressing need to deliver on other development priorities, unless tangible benefits in terms of improved energy access, pollution reduction and improved public health can be demonstrated.

Making costs of compliance with methane abatement requirements cost-recoverable

The costs associated with the deployment of methane abatement technologies and compliance with MRV requirements can increase the operating costs of oil and gas projects and make them less profitable. In line with the recommendations contained in Guiding Principle VII of the 2020 OECD Development Centre’s Guiding Principles for Durable Extractive Contracts, when changes in law entail costs of compliance, these costs should be treated as any other operational costs for the purposes of tax deductibility. In oil and gas production sharing agreements, these additional costs would be recoverable from the allocation of “cost oil” or “cost gas” (OECD, 2020[3]).

In jurisdictions where responsive fiscal terms are contemplated in contracts and/or law, lower project profitability resulting from increased costs of compliance with regulations on methane emissions abatement would automatically result in an equitable sharing of the financial benefits between the government and the investor. Governments should note that the application of cost-recovery measures may reduce governments revenue as the absorption of the costs of methane reduction technology cost may reduce the “profit oil” share for the state. This may be of particular concern for governments that take their allocation of profit oil “in kind” to meet domestic energy requirements. However, a lower share of profit oil could be compensated by volumes of captured associated gas, which could then be used for domestic power generation or other domestic needs, thus contributing to enhanced energy security. Furthermore, there is growing evidence from North America that regulations can lead to methane emissions reduction without significantly impacting production – see Introduction.

Treating the costs of compliance with methane abatement requirements as cost-recoverable can create value for the country when the methane can be captured and used productively. However, an equitable sharing of such costs also requires that, wherever necessary, financial support for investments in midstream and downstream segments of the gas value to capture, transport and process associated gas is available, with due consideration given to risks of asset stranding, lock-in and delayed transition plans – see Building block: Financing methane emissions abatement. In addition, many developing oil and gas producing countries are already largely indebted or fiscally constrained and may not prioritise this expenditure beyond what is required by the IOCs, whereas the availability of finance could lead to improved sustainable development outcomes when providing the means of implementation for LT-LEDS supporting broader systemic transformation toward net-zero energy systems.

Market-based mechanisms for methane abatement

Market-based incentives for methane abatement may include mechanisms that seek to attract third-party investors to participate in methane reduction, for example through clustering opportunities for flaring reduction and the allocation of rights to third parties to monetise associated gas at specific flaring sites through a competitive bidding process.

Market-based mechanisms can also induce companies to comply with methane abatement requirements. For example, in Canada, the Alberta Emission Offset System (AEOS) allows companies to generate credits if they can demonstrate emissions reduction beyond the targets set out in regulations, which can then be sold on the open market. Since its induction, operators have replaced existing pneumatic equipment with technology to reduce methane emission in 560 projects and have captured or reduced vented gas in 230 projects. Collectively these projects have avoided around 9 Mt CO₂-equivalent methane emissions (IEA, 2023[4]).

Enabling and incentivising the capture and utilisation of associated gas

Box 8.3. Enablers and incentives for the capture and utilisation of associated gas

Enablers

• Clear ownership allocation of associated gas and understanding of implications associated with different ownership structures

• Accurate MMRV to quantify volumes of associated gas at stake

• Required gas transmission infrastructure in place.

Incentives

• Capital expenditures borne by the operator for the storage and delivery of gas are cost-recoverable

• Fiscal incentives to encourage methane abatement

• Associated gas clustering opportunities based on transparent information on flaring profiles

• Preferential access for associated gas into the gas network

• International schemes signalling demand for methane abated associated gas.

Source: Based on (OECD, 2022[1]).

Clear ownership allocation of associated gas and understanding of implications associated with different ownership structures

Turning associated gas into an asset, rather than an unwanted by-product of oil production, requires that regulations, licences and production sharing contracts clearly determine who is entitled to use this resource. In addition, different ownership structures provide varying degrees of incentives for oil and gas companies or third-party investors to capture associated gas. There are two standard approaches to allocating ownership of associated gas.

Ownership of associated gas is vested in the operator. In this model, the operator that is producing oil from the underlying oil field also has the rights to extract, sell and utilise any associated gas. This option provides the operator with a direct financial incentive to capture the associated gas (the right to sell or use on-site). In addition, operators are well placed to monetise a deposit of associated gas due to their technical expertise and proximity to the resource. For example, in Angola, the model production-sharing agreement of the NOC Sonangol grants the operator the right to use any associated gas produced in their oil activities and separate any liquids from it. All capital expenditures borne by the operators for the storage and delivery of surplus gas to Sonangol are cost-recoverable against oil revenues (World Bank, 2022[5]).

Ownership of associated gas is reserved to the state. In this model, the operator has the right to produce oil only, and the right to capture and use any associated gas is reserved to the state. Governments should note that this option is unlikely to incentivise an operator to take steps to capture any associated gas. In jurisdictions where the associated gas ownership is reserved to the state, governments should take proactive steps to ensure that third parties are able to secure access to these resources. For example, in 2018, Nigeria enacted the Flare Gas (Prevention and Pollution) Regulations to empower the government to issue permits to access flare sites and take associated gas. The Nigerian Gas Flare Commercialisation Programme (NGFCP) was developed to tackle small flaring sites that proved more difficult to monetise. For each flare site included in an auction, the relevant oil producer is required to provide the annual amounts of flare gas that it expects to have available – either for a minimum of 15 years, or the expected life of the oil field. The Nigerian Upstream Petroleum Regulatory Commission (NUPRC) allocates rights to monetise associated gas at specific flaring sites through a competitive bidding process.

This market-based solution can be used to attract third-party investors to participate in associated gas monetisation to avoid wasteful gas flaring. Although the NGFCP is aimed at third-party investors, oil companies that exploit non-associated gas may also participate in this bidding process, but only through a midstream corporate entity incorporated in Nigeria. Successful bidders will need to enter into a series of commercial agreements with both the government and the relevant operator (oil producer), after which they will be granted permits to access the gas (World Bank, 2022[6]; NUPRC, 2023[7]):

• Gas sales agreement – the bidder and the government enter into a gas supply agreement under which the bidder buys gas from the government at the price contained in the bid. The operator is not a party to this agreement.

• Milestone development agreement – the bidder agrees to a milestone development agreement where they provide a financial guarantee to the government to underpin their commitment to project milestones; and

• Connection agreement – the bidder and the operator enter into a connection agreement. This lays out their arrangement of infrastructure and authorises the bidder to engineer, procure, and construct the gas connection infrastructure under terms acceptable to the operator. The infrastructure is then turned over to the operator who operates and maintains it.

Addressing the infrastructure deficit

Commercial viability is a significant barrier to the utilisation of associated gas, as additional investments may be required to develop the transport infrastructure that is necessary to bring the gas to market or the energy infrastructure to put gas to productive use (e.g. gas fired power plants). Where sufficient infrastructure is not in place to capture and utilise associated gas, governments will need to consider whether gas can have a role in a country’s overall energy mix – see Box 8.4. For example, governments will need to consider what mechanisms should be applied to gas projects to mitigate risks of gas lock-in, with the exact nature of requirements determined by country-level circumstances. This can include system flanking measures (i.e. requirements for investors to invest in parallel in research and development and innovation or targets for renewable expansion) as well as project level requirements for future proofing gas infrastructure (for example, gas transport or distribution networks to accommodate low carbon fuels, or gas-to-power plants to switch to low carbon fuels by a certain date, sunset clauses after which a project should be decommissioned) (see, OECD forthcoming, Gas Use Decision Tree Tool and Scorecard, OECD Development Policy Tools, OECD Publishing, Paris).

Box 8.4. Assessing gas utilisation options: Infrastructure requirements

The commercial viability of the use of associated gas often depends on infrastructure considerations. Governments will need to assess whether adequate infrastructure is in place to evacuate gas, including processing and transport facilities (pipelines or LNG platforms) and distribution networks. Governments should note infrastructure CAPEX costs tend to be far higher when gas production is offshore, given additional costs associated with bringing gas onshore, unless exported in LNG form.

Above all, when considering gas utilisation options, governments should take steps to mitigate risks of stranded assets and gas and emissions lock-in.

• Gas for export – the commercialisation of gas resources for export may be achieved through LNG or cross-border pipelines. Infrastructure requirements include the LNG liquefaction facility and associated pipelines between the gas production site and the liquefaction facility. Floating LNG projects can mitigate to a degree risks of stranded assets given the CAPEX requirements are lower. For example, a recent Perenco and SNH project in Cameroon was able to greatly reduce CAPEX costs by reusing and recycling parts and through the use of a small-scale and modular design.

• Gas-to-power – investments in gas-fired-power generation can displace more carbon emitting energy sources such as heavy fuel oil and coal. Infrastructure requirements include the construction of new gas-fired power plants or the retrofit of coal-fired power plants (where applicable). Transmission infrastructure and interconnectors will also be required.

• Industrial use – the use of gas in industry (for example, fertiliser, steel, and cement production) can displace more expensive and polluting fuels such as heavy fuel oil (HFO) and residual fuel oil (RFO). Infrastructure requirements include the configuration of industrial facilities to accommodate gas as well as associated pipelines to supply gas to industrial clusters.

• Transport and residential – the use of gas as an alternative transport fuel may help reduce emissions, particularly in shipping and long-distance heavy goods transportation. Infrastructure requirements include converting ships/trucks with diesel compression ignition engines to run on natural gas (e.g. CNG, LNG etc.) and the construction/modification of refuelling and bunkering stations. The use of gas for residential purposes will require distribution networks to transport natural gas from production sites to the end consumer. Infrastructure requirements include transmission pipelines, compressor and pressure reduction stations.

Source: (OECD, forthcoming[8]).

Encouraging associated gas clustering opportunities

The often small and geographically dispersed nature of flare and venting sites may deter investments in gas utilisation. In addition, third-party investors may not have access to those sites or to venting and flare site data to take informed investment decisions. Even when oil companies are permitted to use associated gas, the rules regarding the transport and monetisation of associated gas may not be clear (World Bank, 2022[6]). Operators may also struggle to secure off-take agreements with buyers where the volumes are too small and associated gas production is inconsistent. Production facilities/sites that flare less than 1 mmscf/d are generally very challenging to monetise and therefore, a portfolio approach may be necessary to build minimum of economies of scale, and to hedge against the uncertainty and unpredictability of flare profiles by substituting any shortfall from a specific flare with gas from another one (World Bank, 2022[6]). Consequently, governments should consider the feasibility of spreading costs across a number of market participants by requiring operators on adjacent fields to collaborate to capture associated gas. Enabling factors include the collection and provision of transparent data on venting and flaring profiles, third-party access to existing gas networks, preferential market access for associated gas to the gas network and wholesale market and cooperative trade frameworks that signal demand for associated gas.

Providing transparent data on flaring and venting profiles

The first step toward capturing associated gas through clustering opportunities is for governments to provide clear information around flaring and venting profiles (e.g. average volume, flow rate etc.) to market operators. For example, in Trinidad and Tobago, a public registry of approved MRV data is managed by the Environmental Management Authority. The registry is broad in scope but includes information regarding GHG emissions sources from the upstream oil and gas sector (MPD, 2021[9]). In Guyana, the Ministry of Natural Resources’ Petroleum Management Programme regularly publishes consolidated data on gas injected, flared and used as fuel online (Ministry of Natural Resources, 2023[10]). In Alberta, the Albert Energy Regulator provides information on flaring and venting emissions to licensees and operators in order to encourage and facilitate associated gas clustering opportunities (Alberta Energy Regulator, 2022[11]).

Ensuring third-party access to the gas network

In jurisdictions with existing gas networks, government should ensure that barriers do not prevent the sale of associated gas into the domestic gas network. The presence of a local monopolist may also result in market barriers to the transportation and sale of gas. In this regard, open access rules to gas networks can foster competition and provide opportunities to market associated gas downstream. For example, in Argentina, Law No. 26.197, 2006, provides that midstream and downstream operators of pipelines and other transport and distribution infrastructure are required to provide open access to third parties if they have available capacity (World Bank, 2022[12]).

A similar approach is taken in Norway, where section 59 of the 1997 Regulations to Act relating to petroleum activities sets out the principles for access to upstream pipeline networks. The upstream gas transport infrastructure on the Norwegian continental shelf is subject to regulated third-party access. An independent system operator, Gassco, grants access to the upstream pipeline network to users on objective and non-discriminatory terms to users with a duly substantiated reasonable need for transportation and/or processing capacity. The Ministry of Petroleum and Energy (MPE) determines the tariffs for regulated access to gas infrastructure and the tariff consists of a capital element and an operating element. The capital element promotes resource management and gives the owners a reasonable investment return. The operating element is set to cover all operating costs of the system. The Norwegian regulator retains an oversight of these activities and the MPE must approve any access agreements (Norwegian Offshore Directorate, 1997[13]; Holmen Brown, 2022[14]).

Granting preferential market access for associated gas

Governments may also consider granting preferential access for associated gas into the national gas pipeline system and preferential access for electricity produced from associated gas to the wholesale market. For example, in Russia, 2012 amendments to Federal Law No. 241-FZ, requires owners and operators of gas transmission and distribution infrastructure to give preferential access to associated gas in the “Unified Gas Supply System”. In accordance with Federal Law No. 35-FZ on the Electric Power Industry, 2003, electricity produced from associated gas has priority access to the wholesale market (Lorenzato et al., 2022[15]).

Capitalising on international frameworks signalling demand for associated gas

Governments should also consider capitalising on emerging specific international demand for associated gas. For example, in its 2022 REPowerEU toolbox, the European Commission announced the creation of “You collect/ we buy” scheme to incentivise the capture of gas that is currently wasted (through flaring, venting, or fugitive leaks) in gas producing countries (Piebalgs and Olczak, 2023[16]; IEA, 2022[17]).

The scheme will be launched at COP29 in Baku as the Methane Abatement Partnership Roadmap with an additional emphasis on partnerships between importers and exporters. The Roadmap provides a globally adaptable, step-by step blueprint for the implementation of importer-exporter partnerships, and sets out several pillars for a co-operation framework, including a robust MRV system built on the OGMP 2.0 framework, complemented by other relevant measures and policies, as well a project plan on the timeline, abatement targets, expenditure, investments and available tools in co-operation with organisations, such as the IEA, IMEO, OECD and CCAC. The Roadmap aims to mobilise efforts under the Global Methane Pledge, incentivise importer-exporter co-operation in support of companies improving their MMRV abilities to mitigate methane emissions, and attract private investments – all while contributing to both decarbonising energy systems but also ensuring security of supply.

The penalty component

To incentivise compliance, the incentives discussed above should be combined with financial charges, such as fees or taxes, to penalise companies that fail to comply with regulations on methane emissions abatement. For fees and taxes to be effective in encouraging compliance, the cost of compliance with emissions regulations should be lower than any imposed charges.

Several jurisdictions impose a financial charge or tax on flaring and venting in order to encourage cost-effective methane emission reduction. This approach is taken in Brazil, Guyana, Nigeria and Norway (see Box 8.5 below). For example, in Brazil, the regulatory agency outlines annual and monthly limits for flaring and venting. If operators exceed these limits, they are obligated to pay royalties on the methane that is unnecessarily flared or vented. In Guyana, the government introduced a specific tax on flaring in 2022 in order to dis-incentivise flaring. The amount was set at USD 45 per tonne of CO₂ before being raised to USD 50. Notably, in addition to this (environmental) tax on flaring, operators who flare gas must also make (economic) payments to the Guyanese state for their share of the gas that was flared. In 2022, Exxon paid some USD 9 million in flaring fees to Guyana’s Environmental Protection Agency (Government of Guyana, 2022[18]; Kaieteur News, 2024[19]). In Nigeria, the Flare Gas (Prevention of Waste and Pollution) Regulations 2018 imposes taxes on flared gas. Operators that produce more than 10 000 barrels of oil per day, must pay USD 2.00 for each 28.317 m³ of gas flared. Smaller facilities pay USD 0.50 per 28.317 m³ methane flared (IEA, 2021[20]).

Box 8.5. GHG taxation in Norway: Incentivising the deployment of methane mitigation technologies

Norway was one of the first countries to introduce an offshore carbon tax in 1990 through the adoption of the Act 21 December 1990 no 72 relating to tax on discharge of CO₂ in the petroleum activities on the continental shelf (hereafter “the Act”). Although the primary target of this tax was CO₂ due to the high CO₂ content in the Sleipner field, the tax also applies to methane emissions resulting from offshore oil and gas production. Sections 1, 2, and 4 of the CO₂ Tax Act, 1990, require operators to pay on behalf of all licensees a carbon dioxide tax payment for flared or vented natural gas and any other carbon dioxide discharged to the atmosphere during the production and transport of oil and gas unless otherwise exempted by the parliament. Section 3 of the Norwegian Petroleum Act, 1996 coherently allocates to the licensees the ownership of all oil and gas produced, including gas that is flared or vented. Under the Norwegian Petroleum Act, 1996, flaring in excess of what is needed for safe operations is prohibited and subject to a fine, as is the wilful or negligent submission of incorrect or incomplete documentation or any other breach of provisions or decisions contained in or issued by virtue of the CO₂ Tax Act, 1990.

Several factors were influential in the implementation of this tax, including:

• Upstream operations on the Norwegian Continental shelf account for about 95% of the total methane emissions from the oil and gas sector.

• Operators use similar equipment which facilitates procedures for consistently calculating emissions across companies. The Act requires oil and gas companies to install metering systems to obtain methane measurements for tax purposes. Direct measurements (such as flow meters on vent heads) account for around two-thirds of emissions, while operators must follow recognised quantification models and methods to compute emissions for the remaining one-third.

• Norwegian regulators held extensive consultations with industry, research institutions, and other actors during the development of guidelines for emission data collection and reporting.

Since 1991, the CO₂ tax level has been increased and extended from offshore to other onshore industry sectors. The tax rate in 2021 was NOK 8.76 per standard cubic metre of emissions of natural gas, which is equivalent to approximately USD 1 600 or EUR 1 500 per tonne of methane.

The imposition of the CO₂ tax has encouraged investment in CO₂ and methane mitigation technologies, specifically the deployment of carbon capture and storage in natural gas production. The CO₂ tax was one of the main business drivers for Equinor to separate CO₂ offshore and inject it into deeper geological layers. Due to the Norwegian CO₂ emissions tax, it was more economical to store the CO₂, once captured, than venting it. Had this process not been adopted and the CO₂ produced been allowed to escape to the atmosphere the licensees of the Sleipner West field would have had to pay around NOK 1 million/day in Norwegian CO₂ taxes.

Source: (OECD, 2022[1]); (IEA, 2021[20]); (Mohlin et al., 2022[21]); (Vernon et al., 2022[22]); (World Bank, 2024[23]).

In the United States, the Inflation Reduction Act 2022 introduced a methane fee on methane emissions from oil and gas operations. Section 60113 establishes the Methane Emissions Reduction Program that introduces a charge on methane emissions by oil and gas companies who report emissions under the Clean Air Act. This charge applies to facilities that emit over 25 000 metric tons of CO₂ equivalent per year, and starts at USD 900 per metric ton of methane in 2024, ramping up to USD 1 500 over a three-year period. However, the application of the charge is subject to statutory exemptions, including: where there is an unreasonable delay in permitting infrastructure to capture methane releases; when wells have been plugged in accordance with applicable requirements; and where methane releases occur at equipment that is in compliance with regulatory standards. The Inflation Reduction Act also imposes a royalty obligation on all gas produced, including gas that is consumed or lost by flaring, venting, or fugitive releases during upstream operations on federal lands and waters (IEA, 2023[24]).

Governments should ensure that regulators are empowered to enforce regulations and properly resourced to monitor compliance. Regulators will need a system to receive, process and interpret large volumes of data provided by oil and gas companies that are subject to MRV requirements. In some jurisdictions, regulators may rely on third party verifiers rather than developing the requisite in-house audit resources. Third-party verifiers may carry out similar activities as government auditors, including inspections, analysis of reports or undertaking specific monitoring/measurements campaigns. In all cases, regulators will need the technical ability to detect non-compliance as well as the political authority to bring enforcement actions for non-compliance, including monetary penalties, removal of privileges or other sanctions (IEA, 2021[20]).

References

[11] Alberta Energy Regulator (2022), Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, Alberta Energy Regulator, https://www.aer.ca/regulating-development/rules-and-directives/directives/directive-060.

[18] Government of Guyana (2022), Guyana’s Low Carbon Development Strategy 2030, Government of Guyana, https://lcds.gov.gy/wp-content/uploads/2022/08/Guyanas-Low-Carbon-Development-Strategy-2030.pdf.

[14] Holmen Brown, H. (2022), Legal framework of petroleum activity on the Norwegian Continental Shelf, Thommessen, https://www.thommessen.no/en/news/legal-framework-of-petroleum-activity-on-the-norwegian-continental-shelf.

[4] IEA (2023), Financing reductions in oil and gas methane emissions, International Energy Agency, Paris, https://www.iea.org/reports/financing-reductions-in-oil-and-gas-methane-emissions.

[24] IEA (2023), Inflation Reduction Act of 2022, International Energy Agency, https://www.iea.org/policies/16156-inflation-reduction-act-of-2022.

[17] IEA (2022), How to Avoid Gas Shortages in the European Union in 2023, International Energy Agency, Paris, https://www.iea.org/reports/how-to-avoid-gas-shortages-in-the-european-union-in-2023.

[20] IEA (2021), Driving Down Methane Leaks from the Oil and Gas Industry, International Energy Agency, Paris, https://www.iea.org/reports/driving-down-methane-leaks-from-the-oil-and-gas-industry.

[19] Kaieteur News (2024), World Bank highlights need to reduce emissions as carbon tax payments increased in 2023, Kaieteur News, https://www.kaieteurnewsonline.com/2024/05/25/world-bank-highlights-need-to-reduce-emissions-as-carbon-tax-payments-increased-in-2023/#:~:text=In%20Guyana%2C%20the%20government%20instituted,gas%20during%20oil%20production%20activities.

[15] Lorenzato, G. et al. (2022), Financing Solutions to Reduce Natural Gas Flaring and Methane Emissions, World Bank, https://www.worldbank.org/en/programs/gasflaringreduction/publication/financing-solutions-to-reduce-natural-gas-flaring-and-methane-emissions.

[10] Ministry of Natural Resources (2023), Data Visualization, Petroleum Management Programme, https://petroleum.gov.gy/data-visualization?tid=All&tid_1=All.

[21] Mohlin, K. et al. (2022), Policy instrument options for addressing methane emissions from the oil and gas sector, Environmental Defense Fund, https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4136535.

[9] MPD (2021), Trinidad and Tobago’s First Biennial Update Report, Ministry of Planning and Development, https://unfccc.int/sites/default/files/resource/FIRST_%20BUR_TRINIDAD_AND_TOBAGO.pdf.

[2] Natural Resources Canada (2020), Emissions Reduction Fund (ERF), Natural Resources Canada, https://natural-resources.canada.ca/science-and-data/funding-partnerships/opportunities/current-funding-opportunities/emissions-reduction-fund/onshore-program-emissions-reduction-fund/erf-faq/23827.

[13] Norwegian Offshore Directorate (1997), “Last amended 23 December 2022”, in Regulations to Act relating to petroleum activities, Norwegian Offshore Directorate, https://www.sodir.no/en/regulations/regulations/petroleum-activities/.

[7] NUPRC (2023), Nigerian Gas Flare Commercialisation Programme (NGFCP), Nigerian Upstream Petroleum Regulatory Commission (NUPRC), https://ngfcp.nuprc.gov.ng/.

[1] OECD (2022), Equitable Framework and Finance for Extractive-based Countries in Transition (EFFECT), OECD Development Policy Tools, OECD Publishing, Paris, https://doi.org/10.1787/7871c0ad-en.

[3] OECD (2020), Guiding Principles for Durable Extractive Contracts, OECD Development Policy Tools, OECD Publishing, Paris, https://doi.org/10.1787/55c19888-en.

[8] OECD (forthcoming), Gas Use Decision Tree Tool (GUDTT) and Scorecard, OECD Publishing, Paris.

[16] Piebalgs, A. and M. Olczak (2023), Policy Brief: The EU can reduce global methane emissions by jointly purchasing gas, Florence School of Regulation (FSR), https://cadmus.eui.eu/bitstream/handle/1814/75327/QM-AX-23-001-EN-N.pdf?sequence=1&isAllowed=y.

[22] Vernon, N. et al. (2022), How to Cut Methane Emissions, International Monetary Fund, https://www.elibrary.imf.org/view/journals/066/2022/008/066.2022.issue-008-en.xml.

[23] World Bank (2024), Global Flaring and Venting Regulations Database - Norway, World Bank, https://flaringventingregulations.worldbank.org/norway.

[6] World Bank (2022), Financing Solutions to Reduce Natural Gas Flaring and Methane Emissions, World Bank, http://hdl.handle.net/10986/37177.

[12] World Bank (2022), Global Flaring and Venting Regulations: 28 Case Studies from Around the World, World Bank, https://thedocs.worldbank.org/en/doc/fd5b55e045a373821f2e67d81e2c53b1-0400072022/related/Global-Flaring-and-Venting-Regulations-28-Case-Studies-from-Around-the-World.pdf.

[5] World Bank (2022), Global Flaring and Venting Regulations: A Comparative Review of Policies, World Bank, https://thedocs.worldbank.org/en/doc/fd5b55e045a373821f2e67d81e2c53b1-0400072022/global-flaring-and-venting-regulations-a-comparative-review-of-policies.

Note

← 1. Alongside financial rewards for oil & gas companies that take action to reduce their emissions, the Inflation Reduction Act 2022 also sets out provisions to penalise those that do not comply with methane abatement regulations – see sub-section below – “penalty component”.