The Colombian State possesses ownership of the subsoil, including hydrocarbons found both onshore and offshore. The management and regulatory oversight of these hydrocarbons are consolidated at the national level under the National Hydrocarbons Agency (ANH), which retains ownership and does not transfer it when issuing contracts.

The National Hydrocarbons Agency (ANH), established by Decree 1760 of 2003 (with amendments), oversees hydrocarbon resources by granting exploration and production rights to both domestic and foreign entities through various contracts, while also monitoring compliance. The Ministry of Mines and Energy, governed by multiple laws including Law 1530 of 2012, formulates and adopts national mining and energy policies, regulates the sector, and sets technical standards. The National Environmental Licensing Agency (ANLA), created by Decree 3573 of 2011, evaluates and monitors environmental compliance for projects, including those related to hydrocarbons. The Mining and Energy Planning Unit (UPME), established by Law 143 of 1994, handles comprehensive planning for the country's mining and energy sectors, focusing on infrastructure and energy supply. At state and local levels, environmental and economic development secretariats enforce national regulations and manage social and environmental impacts of hydrocarbon activities within their jurisdictions.

Ecopetrol S.A., as the national oil company (NOC), along with its subsidiaries, engages in the exploration, production, refining, and transportation of oil and natural gas.

Hydrocarbon laws are established at the state level to regulate the exploration, production, transportation, and commercialisation of hydrocarbons throughout the country.

Upstream Operations

Decree 1056 of 1953 (Petroleum Code)

Decree 1056 of 1953 (Petroleum Code) sets forth the legal framework for the exploration and extraction of hydrocarbons, delineates the roles and responsibilities of different stakeholders, and specifies the processes for securing exploration and production licences.

Decree 1760 of 2003

Decree 1760 of 2003 separates Ecopetrol, establishes ANH as the regulatory body for hydrocarbons, outlines guidelines for the management and distribution of hydrocarbon resources, and guarantees the effective and sustainable utilisation of these resources.

Decree 1073 of 2015

Decree 1073 of 2015 consolidates multiple regulations concerning the exploration, production, and commercialisation of hydrocarbons, with the goal of simplifying regulatory procedures and enhancing governance in the sector.

Midstream Operations

Law 142 of 1994

Law 142 of 1994 sets the guidelines for public utility services, delineating the responsibilities of both public and private sectors in the transportation and distribution of natural gas, while promoting equitable access and competitive practices in these services.

Decree 1760 of 2003

Decree 1760 of 2003 outlines the regulatory framework for midstream operations, encompassing pipeline transportation, and establishes provisions for the oversight and regulation of pipeline infrastructure.

Downstream Operations

Decree 1347 of 1970

Decree 1347 of 1970 sets forth the legal foundation for refining operations, specifies quality and distribution standards for petroleum products, and governs the marketing of refined products to maintain market stability.

Law 1819 of 2016

Law 1819 of 2016 updates tax regulations concerning hydrocarbon operations, establishes new tax responsibilities for companies involved in refining and distribution, and seeks to enhance government revenue from the hydrocarbons industry.

Pooling and Unitization Rules

Pooling and unitisation are concepts that involve consolidating small parcels of land or interests to facilitate more efficient and cost-effective hydrocarbon extraction. Pooling refers to the merging of mineral interests within a defined area to create a drilling unit, ensuring equitable sharing of production and expenses among interest owners. In contrast, unitisation pertains to the collaborative management of an entire oil or gas reservoir by various leaseholders, governed by specific regulations outlined in E&P Contracts to address these scenarios.

Local Regulation

Regulatory framework

Local regulations enhance national legislation by focusing on particular regional and local issues. Various departments frequently implement extra environmental rules to safeguard local ecosystems. Local authorities manage land use and zoning, influencing the locations and methods of hydrocarbon activities. Additionally, local governments may establish regulations aimed at reducing the effects of hydrocarbon operations on their communities.

The ANH Contracting Statute facilitates both private and public investment in upstream hydrocarbon activities through various contractual arrangements, primarily focusing on technical evaluation and exploration and production contracts. Additionally, Ecopetrol, Colombia's national oil company, has entered into special exploitation agreements with the National Hydrocarbon Agency (ANH) to enhance the exploration and production of hydrocarbons, thereby fostering the development of the oil and gas sector in the region.

Technical Evaluation Agreements (TEAs)

The technical evaluations and preliminary exploration activities (TEAs) granted by the ANH are essential for assessing the hydrocarbon potential of a designated area, although they do not confer production rights. These assessments involve conducting geological and geophysical studies to accurately identify potential hydrocarbon deposits, and successful findings from these evaluations can lead to the transformation of TEAs into exploration and production (E&P) rights.

Exploration and Production (E&P) Contracts

The rights for hydrocarbon exploration and production, averaging up to 45,000 hectares onshore, are granted by the ANH, where investors assume all exploration costs and associated risks. The government benefits through surface and technology transfer fees, along with royalties and taxes, along with any additional high prices as mutually agreed in the contract.

Association Contracts

The rights granted involved partnerships between Ecopetrol and private investors for E&P activities, with contracts issued by Ecopetrol valid until 31 December 2003. Although this model is no longer available for new agreements, existing contracts will remain in force until they are either relinquished or terminated.

Upstream licences for hydrocarbon exploration and production are granted by ANH. 

Process for Obtaining an Upstream Licence

Public bidding process

The licensing process initiated by ANH involves several key steps:

• Announcement: ANH holds regular announcements for bidding rounds on available evaluation, exploration, and production blocks.
• Bid submission: private investors who wish to participate must submit their bids, which must include legal, technical, financial, operational, ESG qualifications, and a bid bond. However, the top 100 companies are exempt from providing detailed proof of financial, technical, and operational qualifications and only need to submit a simplified documentation set.
• Evaluation: ANH assesses the bids according to the criteria outlined in the round's terms of reference, considering factors such as the minimum and additional exploration work programme and financial commitments, among others.
• Award: the winner receives a hydrocarbons evaluation or an exploration and production contract for the designated block.

Direct negotiation

In certain instances, particularly for regions not covered by the bid rounds, ANH would conduct direct negotiations with interested companies. These negotiations adhere to a comparable evaluation procedure as the public bidding rounds, but they are initiated by the investor.

Major Permits Required for Operations

Prior consultation

• Issuing authority: the Interior Ministry.
• Requirements: requesting certification confirming that there are no local ethnic, Afro, or indigenous communities in a specified exploration area.
• Key points: in case of declared existence, prior consultation with such communities is mandatory. 

Environmental licences

• Issuing authority: National Environmental Licensing Authority (ANLA).
• Requirements: an environmental impact assessment (EIA), and an environmental management plan (PMA) as applicable. Licence is granted after ANLA reviews and approves these documents.
• Key points: prior consultation with these communities is required if their existence is officially recognised.

Other permits

• Water use and waste disposal permits: these permits are necessary for utilising water resources and for the disposal of liquid and solid waste as permitted. The Environmental Licence encompasses these permits.
• Land use permits: easements on private roads and location; public roads (either managed by the government or under concession).
• Community agreements: ANH handles the procedure of co-ordination and a concurrence with local communities.

Significant Changes in Regulatory Approach

Streamlining processes

In recent years, Colombia has worked to simplify the licensing process to draw in more investment by minimising bureaucratic obstacles and enhancing the efficiency of permit issuance.

Enhanced environmental regulations

Improved environmental regulations have been reinforced, placing a stronger focus on environmental protection and community involvement, leading to more thorough environmental impact assessments and tighter monitoring of compliance. The ANLA has adopted a sole window approach.

Increased transparency

The bidding and licensing processes are now more transparent, featuring defined criteria and procedures that promote fairness and competition. Results of bids and evaluation criteria are publicly disclosed.

Suspension of hydrocarbon contracts

The current government has suspended new applications for technical evaluations and exploration and production contracts, while directing a review of existing contracts to either reactivate or terminate those under suspension, emphasising the procurement of performance for ongoing contracts. The primary focus is on renewable energy sources.

The government's share from E&P hydrocarbon contracts typically exceeds 70%, influenced by location. This "take" usually encompasses various economic rights, including surface and technology transfer fees, royalties, bonuses (often referred to as "X" factors), guarantees, insurance, social programmes (PBC), and income taxes. Specifics may vary based on the type of resource, such as crude oil or natural gas, and the details of individual contracts.

Royalties

Royalties are calculated on a sliding scale based on production levels, starting at 8% for the first 5,000 barrels per day (bpd) and increasing incrementally up to 25% for higher production levels.

Economic Rights

These include the following:

• Annual surface fee: payments based on the evaluated, explored, or production area, calculated per hectare and fixed annually by ANH.
• Technology transfer payments: contributions towards formation, institutional strengthening, and technology transfer, calculated annually and set by ANH.

High Prices

• Definition: payments that kick in when the project’s profitability exceeds a certain threshold of world’s WTI oil price.

Bonuses

• Production bonuses: payments triggered by achieving specific production milestones. 

Exploration Obligations

• Minimum work programmes: contractors must adhere to minimum work programmes, committing to specific investment levels in exploration and development activities.
• Additional work commitments: these can include seismic surveys, drilling exploratory wells, and other exploration activities.

Social Programmes

• Community investments: contractors are mandated to invest in local communities to meet their social responsibility obligations, which may encompass infrastructure projects, education, and health programmes. 
• Rates: the scale and scope of social programme commitments are included in the contract terms as PBC.

Recent Government Trends

• Environmental and social focus: There are stringent requirements for environmental protection and social investment, reflecting the growing public concern about the impact of hydrocarbon activities on local communities and ecosystems.
• Social licence to operate: the government obtained a social licence to operate the projects by adhering to the principles of concurrence and coordination, as mandated by a judicial order.

Upstream hydrocarbon operations are subject to a range of taxes at the national level, with limited state and local taxation. 

Corporate Income Tax

As of 2023, the rate is 35%, applicable to companies' net income, with deductions permitted for expenses related to exploration, development, and production activities.

Specific Hydrocarbon-Related Taxes

There is no separate hydrocarbon income tax; upstream operations are taxed under the standard corporate income tax regime.

Companies can deduct a percentage of costs related to the depletion of hydrocarbon resources, as specified by tax regulations.

Royalties

Rates are determined on a sliding scale according to production levels. As for deductibility, royalties are viewed as a production cost and can be deducted for corporate income tax purposes.

Value-Added Tax (VAT)

The tax rate is 19%. VAT is applicable to the sale of goods and services associated with upstream operations. Exports of oil and gas are typically zero-rated, enabling the recovery of input VAT. A special exemption exists for VAT and customs duties on imported goods used in basic industries, such as oil and gas.

State and Local Taxes

Property taxes

The application is relevant to land holdings involved in upstream operations.

Rates differ based on the municipality and the property's value.

Other Key Taxes

Withholding taxes

The application is relevant for payments directed to foreign entities.

Rates fluctuate based on the payment type and the recipient's country of residence (for instance, 15% on dividends and 20% on interest and royalties).

Import duties

This applies to duties on imported equipment and materials may apply, with exemptions possible based on HTSC.

Rates vary based on the type of goods being imported.

Environmental contributions

Fees associated with obtaining environmental licences and ensuring compliance are dictated by relevant environmental regulations and the degree of environmental impact.

Recent Trends

Increasing environmental and social taxes

The emphasis on environmental protection has resulted in increased taxes or fees associated with environmental compliance and community development. There have been modifications in royalty rates, with regular evaluations and adjustments intended to align government revenue requirements with the sector's appeal for investment.

Ecopetrol has the right to participate in upstream projects, either directly or through joint ventures with private companies. It participates as any other of the private or public competitors.

Local content requirements are governed by the E&P contract and labour regulations.

Private investors are required to prioritise the procurement of goods and services from local suppliers, including equipment, materials, and services; as well as employing local residents including skilled, semi-skilled, and unskilled labour via the Public Employment Service. Ecopetrol labour union and other unions cause adherence or higher salaries in certain zones. 

There are no local content rules at the time of incorporating a company or establishing a branch.

Development Plans

Submission of development plan

The licence holder must submit a detailed development plan to ANH, outlining the proposed methods for developing and producing the discovered hydrocarbons.

Content of the development plan

The development plan includes the following:

• Detailed description of the reservoir and production methods.
• Investment and operational costs.
• Production forecasts.
• Environmental impact assessment and management plan.
• Safety and risk management plans.
• Timelines and milestones for development activities.

Government Approval

Review and approval process

ANH reviews the development plan to ensure it meets all regulatory, technical, and environmental standards. The review process involves consultation with other relevant governmental agencies, such as the Ministry of Mines and Energy and ANLA.

Approval conditions

ANH may approve the development plan with specific conditions or modifications required to address any identified issues or concerns. The licence holder must comply with these conditions to proceed.

Local Requirements

Drilling permits and environmental licences

These licences consist of the following components:

• Drilling permits: Prior drilling permit from ANH is required to drill. This permit requires detailed information about the well design, location, depth, and drilling procedures.
• Environmental licences: The licence holder must apply for it at ANLA, ensuring that the proposed activities comply with environmental regulations and standards. 

Compliance and Monitoring

Ongoing compliance

The licence holder is required to adhere to all national and local regulations during both the development and production stages. They must also provide periodic updates to ANH and ANLA regarding progress, production metrics, and adherence to environmental and safety standards.

Inspections and audits

Regulatory bodies, including ANH and ANLA, conduct periodic inspections and audits to ensure compliance with approved development plans and licences. 

The regulatory framework for upstream licences (hydrocarbon exploration and production) is primarily governed by the National Hydrocarbons Agency (ANH). 

Exploration

Exploration lasts between six to nine years and may be extended depending on the company's interests and investments, after an initial two-year phase dedicated to preliminary consultations and the application for environmental permits. Companies are required to undertake at least the minimum exploration programme, with relinquishment permitted under specific conditions.

Production

After receiving approval for commercial production following a discovery, the production period can extend up to 30 years (offshore contracts may allow for additional time to build the necessary infrastructure). There may also be requirements to allocate a portion of the production for the domestic market, along with potential restrictions or quotas on exports.

Assignment of interests involves a process contained in the contract and ANH Contracting Statute. It normally requires ANH approval, replacing the guarantees initially filed by the assignor, submitting a formal application, detailing the terms of the proposed assignment and qualification of assignee. ANH evaluates the filing to ensure the assignee can meet the contractual obligations. Timing of the approval takes around six months. If approved, certain ancillary permits, such as the environmental licence, need to be transferred as well as the parent company guarantee, the standby letter of credit and contractual insurances.

In Colombia, there are generally no legal restrictions on production rates imposed by entities like OPEC or other multinational quotas. Colombia is not an OPEC member, so it is not subject to production quotas set by the organisation. However, there are certain domestic considerations that may influence purchase prices when the crude is required for domestic consumption.

Production rates may be influenced by environmental regulations, community agreements, and infrastructure limitations. Restrictions might be put in place to mitigate environmental impact, ensure community benefits, or align production with transportation and processing capacities.

Midstream and downstream sectors, including operations such as treatment facilities, pipelines, processing and fractionation systems, storage facilities, terminals, refineries, petrochemical facilities, and marketing, are open to private investment under certain regulatory frameworks. Ecopetrol, via its affiliate Cenit, holds the largest participation in the country.

Private investors can participate in the construction, ownership and operation of pipelines that transport crude oil and natural gas from production fields to processing plants or refineries. Transportation pipelines that carry products across regions or to export terminals are also areas where private investment is allowed. 

Colombia does not have a government or private monopoly in the midstream sector. The regulatory framework encourages competition and private sector participation. Private investors have rights to invest in midstream operations under the terms and approval issued by the Ministry of Mines and Energy. 

Private investment is allowed in the construction, upgrade and operation of refineries that process crude oil into refined products. Petrochemical facilities for the production of plastics, fertilisers, and other chemical products are also open to private investment, as well as engaging in wholesale marketing. Retail marketing, including operating service stations and selling directly to consumers, is another area where private investment is prevalent. 

Refineries, petrochemical facilities, and retail marketing, operate under the major participation of Ecopetrol, with its two refineries in Cartagena and Barrancabermeja. Private investment is permitted.

Access Rights and Terms in Downstream Operations (Private Investment)

Access priorities

Access to infrastructure and services in downstream operations is generally governed by contractual agreements between private investors and stakeholders, including suppliers, distributors and consumers.

Contracts may outline priority access for specific customers or stakeholders based on contractual commitments and operational needs.

Tariff nature and methodologies

Tariffs and pricing methodologies for downstream services are often determined through market-based mechanisms, competitive pricing strategies, and regulatory oversight.

Challenges to rates and terms of service

Stakeholders, including consumers and competitors, have the right to challenge tariff rates and terms of service through regulatory channels.

Regulatory bodies may conduct reviews or hearings to address disputes and ensure compliance with regulatory standards and consumer protection laws.

Obtaining a midstream or downstream licence involves several steps designed to ensure compliance with regulatory standards and to promote fair competition. Private investors must meet certain legal, technical and financial prerequisites qualifications to be eligible for a midstream or downstream licence. Additionally environmental, safety and construction permits are required to authorise building new infrastructure or modification of existing facilities.

Typical commercial arrangements for midstream and downstream operations vary depending on the specific type of operation and follow Ministry of Mines and Energy regulation. Long-term contracts with firm commitments for transporting crude oil or natural gas from production fields to processing facilities are used. Pricing in these contracts is often based on a fee-per-unit volume transported, and terms may include take-or-pay clauses ensuring that producers pay for a minimum volume regardless of actual usage.

In processing and fractionation, agreements often involve tolling arrangements where producers pay a fee for processing their raw materials into refined products or fractions. These contracts may include firm pricing, where the fee is fixed, or interruptible pricing, where the fee may vary based on availability and demand. Volume commitments are standard practice, as they guarantee the processor a specific level of output.

Transportation contracts for pipelines generally include firm and interruptible service options. Firm service guarantees capacity for the customer and typically comes at a higher cost, while interruptible service is cheaper but subject to availability. Take-or-pay clauses are also standard, requiring customers to pay for a certain volume even if it is not fully utilised.

Storage agreements involve leasing capacity in storage facilities, with terms that can be either firm or interruptible. Pricing is usually based on the volume of product stored and the duration of storage. It may involve minimum volume commitments and penalties for exceeding storage limits.

Refining contracts often involve processing agreements where crude oil suppliers pay refineries to convert crude into refined products. The terms of service in these agreements can include fixed or variable pricing based on market conditions, volume commitments, and quality specifications for the crude and refined products.

Wholesale marketing agreements involve the sale of refined products to distributors or large consumers. These contracts typically include pricing terms that may be fixed or indexed to market prices, volume commitments, and delivery schedules. Terms of service are subject to regulatory oversight to ensure fair trading practices.

Retail marketing contracts, including those for operating service stations, generally involve franchise or supply agreements between marketers and station operators. Pricing in these agreements can be fixed or variable, often influenced by market conditions. Terms may include volume commitments, branding requirements, and service standards.

Fiscal terms and terms of service in these commercial arrangements are subject to regulation and government approval to some extent, particularly in ensuring compliance with competition laws, environmental regulations, and consumer protection standards. Key terms in these agreements include pricing mechanisms, the distinction between firm versus interruptible service, and take-or-pay or volume commitments, which help manage risks and ensure steady revenue streams for infrastructure owners and marketers.

Midstream and downstream operations are subject to general income tax regime applicable to corporate entities. Current rate is 35%. Companies engaged in midstream and downstream operations must comply with filing annual tax returns and paying taxes on their profits.

Construction and operation of midstream and downstream infrastructure are subject also to value-added tax on goods and services used during the construction phase. The VAT rate is 19%, to procurement of equipment, materials and services. Property taxes on real estate and municipal industry and commerce taxes apply, which rate varies by locality. 

Tax exemptions and incentives are available. These may include exemptions from import duties on capital goods and equipment used in the construction of infrastructure; additionally, in specific regions or projects that are deemed to be of national interest. There are deductions for research and development expenses, training programmes, and other activities that enhance operational efficiency and compliance with regulatory standards. These deductions can reduce the overall tax burden and improve the financial viability of midstream and downstream projects.

Ecopetrol holds the majority participation and certain special rights in connection with midstream and downstream licences. It may be granted preferential rights in certain strategic projects, particularly those deemed crucial for national energy security and supply. 

While private investment is encouraged and permitted in the midstream and downstream sectors, Ecopetrol's special rights and its significant role in the industry ensure that it remains a central player in Colombia's oil and gas landscape. 

Midstream and downstream operations by private investors are subject to local content requirements designed to promote the use of local goods and services, local employment, and training programmes. They must adhere to local employment requirements, which mandate hiring via the Employment Public Service.

Midstream licences in Colombia include:

• Service obligations and classes of service: these define the scope of services such as transportation and storage of hydrocarbons or other resources.
• Domestic supply requirements: these ensure a portion of resources are allocated for domestic use before exports are permitted when applicable, promoting energy security.
• Export rights: these regulate conditions for exporting resources, including compliance with domestic supply commitments and regulatory approvals.
• Liability and risk regime: these establish frameworks for liability in case of accidents or environmental incidents during transportation or storage.
• Withdrawal, termination, and abandonment: these outline conditions for terminating the licence and responsibilities for decommissioning infrastructure. 

Downstream licences in Colombia include:

• Service obligations and classes of service: these specify activities allowed such as refining, distribution, and retailing of petroleum products, ensuring compliance with quality and safety standards.
• Domestic supply requirements: these set quotas for supplying refined products to the domestic market before allowing exports when applicable, supporting local demand.
• Export rights: these govern conditions for exporting refined products, balancing domestic consumption with international trade interests.
• Liability and risk regime: these define responsibilities for product quality, safety, and environmental impacts associated with downstream operations.
• Withdrawal, termination and abandonment: these detail conditions for finishing the licence and obligations for closing facilities and environmental rehabilitation.

Private investors constructing infrastructure generally do not have condemnation or eminent domain rights. Surface rights for infrastructure projects are typically obtained through negotiation with landowners or by leasing agreements. The process involves:

• Negotiation: investors negotiate with landowners or relevant authorities to obtain surface rights needed for the infrastructure project.
• Payments: compensation or lease payments are typically agreed upon between the investor and the landowner. These payments may vary based on factors such as the size of the land, its use and location, and the potential impact of the project on the land's use.
• Legal framework: this ensures that landowners are fairly compensated for the use of their land and may involve valuations based on market rates or other criteria set by local regulations.
• Environmental and social considerations: projects must also consider environmental and social impacts, ensuring compliance with regulations regarding land use and community welfare.

Hydrocarbon transportation is ruled by the Ministry of Mines and Energy, responsible for issuing licences, setting safety standards, and ensuring compliance with environmental regulations. Applicable laws establish guidelines for access to transportation infrastructure and regulate transportation costs to prevent monopolistic pricing practices, providing fair and equitable access to pipeline systems, while cost regulations aim to maintain affordability and competitiveness in the market.

Environmental and safety standards mandate comprehensive measures for spill prevention, emergency response planning, and regular inspections to maintain infrastructure integrity and minimise environmental impacts.

Regulations ensure that third parties have the right to access privately constructed infrastructure in both midstream and downstream sectors. This is intended to promote competition and fair market access.

Regarding midstream and downstream licences, provisions typically mandate open access to infrastructure for third-party users. This means that owners of infrastructure must provide non-discriminatory access to their facilities. Regulatory requirements specify:

• Terms of service: the conditions under which third parties can access the infrastructure, including pricing, technical specifications, and operational terms.
• Unbundling of services: there is often a requirement to separate different services (like transportation, storage, or processing), ensuring that each component is available independently for access. 
• Prohibitions on vertical integration: regulations may prohibit entities from simultaneously operating in multiple segments of the market. This restriction aims to prevent monopolistic practices and maintain a level playing field.

There are several restrictions on the sales of products into the local market to ensure market regulation, competition, and compliance with legal standards.

Regarding ownership, certain restrictions may apply to prevent monopolistic control over the market. 

Special licences are required for selling products within the country. These licences ensure that sellers comply with safety, environmental, and quality standards. The Ministry of Mines and Energy, along with the National Hydrocarbons Agency (ANH), oversees the issuance and regulation of these licences at a national level.

Limitations on concurrent ownership in different aspects of the value chain are imposed to prevent conflicts of interest and promote a competitive market structure. An entity involved in refining may face restrictions on owning retail distribution networks. State or local rules may add additional layers of regulation, such as zoning laws, local environmental standards, and community impact requirements. These local regulations ensure that sales activities align with regional development goals and environmental protection standards.

The export of crude oil, natural gas and petroleum products is governed by several laws and regulations that aim to control and manage the export process while ensuring compliance with international standards and domestic priorities.

Authorisations Required

Exporters must obtain authorisation from the Ministry of Mines and Energy and the National Hydrocarbons Agency (ANH). These bodies ensure that all regulatory requirements are met before granting export permits. Specific approvals are necessary for each shipment, and compliance with safety, environmental, and quality standards is mandatory.

Export Taxes or Duties

Exporters are subject to export taxes or duties, which vary depending on the product and current market conditions. 

Transfer of midstream and downstream operations and assets between private owners involves a detailed process to ensure compliance with regulatory requirements and smooth transition of operations. The parties negotiate the terms of the sale. The Ministry of Mines and Energy and ANH, when applicable, must approve the transfer of any permits or licences associated with the operations. This ensures that the new owner meets all regulatory standards and it is capable of maintaining compliance. Existing permits and licences must be formally transferred to the new owner. Some permits may have clauses that restrict transferability or require specific conditions to be met before they can be transferred. Regulatory bodies will review these conditions to ensure they are satisfied.

The acquiring party must demonstrate that they will maintain compliance with all environmental and safety regulations. This may involve updating safety plans, conducting environmental assessments, and ensuring that all operational standards are met.

Transfers may involve employees' substitution and contracts’ assignment. Ensuring that all employment laws are adhered to and that contracts with suppliers, customers and service providers are seamlessly transferred can be complex. Once all regulatory approvals and conditions are met, the transaction can be closed. Formal transfer of ownership and updating of all records to reflect the new ownership must take place.

Foreign investment in hydrocarbons is subject to specific rules issued by the Central Bank, under the so-called special exchange regime, according to which companies in the oil sector can trade in US dollars within the sector and are not obliged to repatriate sales derived from crude exportation. Other incentives include tax benefits, offshore trade free zones and custom duties exemptions to basic industry. Foreign investors can invoke international law and dispute resolution mechanisms, including international arbitration.

The approach to international sanctions primarily aligns with the policies set by the United Nations, the European Union and the United States of America. Colombia adheres to international sanctions regimes and enforces restrictions on investing in oil and gas assets or conducting business with certain foreign jurisdictions, counterparties, or governments that are subject to sanctions.

Principal Environmental Laws

• Law 99 of 1993 establishes the National Environmental System (SINA) and the Ministry of Environment and Sustainable Development, regulating environmental protection and resource management across all sectors. It encompasses comprehensive environmental regulations, including pollution control, natural resource management, and environmental licensing.
• Decree 1076 of 2015 consolidates various environmental regulations related to environmental licensing, the conservation of biodiversity, and sustainable development, including procedures for environmental licensing, management of protected areas, and the sustainable use of natural resources.
• Law 165 of 1994 ratifies the United Nations Framework Convention on Climate Change (UNFCCC), requiring Colombia to implement measures for climate change mitigation, emissions reduction, and environmental sustainability initiatives.

Major Environmental Regulators

• The Ministry of Environment and Sustainable Development (MinAmbiente) is the principal national authority tasked with formulating and implementing environmental policies, regulations, and standards. It oversees environmental licensing, climate change initiatives, and sustainable development efforts.
• The National Environmental Licensing Authority (ANLA) is a specialised agency under the Ministry of Environment tasked with issuing and monitoring environmental licences for projects with significant environmental impacts, including large-scale oil and gas operations.
• Regional Autonomous Corporations (CARs) are regional environmental authorities responsible for specific geographic areas. They implement national environmental policies locally, manage natural resources, and issue environmental permits for smaller projects.

Prior to starting a major hydrocarbon project, several environmental obligations must be satisfied to ensure compliance with national and regional regulations:

• Environmental Impact Assessment (EIA): to evaluate the potential environmental effects of the proposed project. 
• Conducting a detailed environmental survey to assess the current state of the environment and potential impacts.
• Preparing an Environmental Impact Study (EIS) that outlines the findings of the survey and proposes measures to mitigate negative impacts.
• Submitting the EIS to the National Environmental Licensing Authority (ANLA) for review and approval.
• Environmental Management Plan (EMP): detailing specific mitigation measures, monitoring plans, and contingency plans to manage identified environmental risks.

Approval Requirements and Timing

• Submission: EIS and EMP must be submitted to ANLA.
• Review process: the process involves a thorough evaluation of submitted documents to confirm compliance with regulatory standards, incorporating public consultations to gather community feedback. Depending on the complexity of the project and its potential environmental impact, this process can extend over several months, ensuring that all concerns are addressed and that the project adheres to environmental and legal guidelines before proceeding.
• Approval: the approval for the project hinges on the issuance of an environmental licence, which permits the initiative to move forward as long as it adheres to the EMP and any supplementary conditions set forth. As part of this approval process, there is an obligation to remit 1% of the project's total cost.

Social Survey and Community Actions

• Social Impact Assessment: SIA is a crucial process that systematically evaluates the potential positive and negative effects of a project on local communities. It involves identifying communities that may be affected, analysing social and economic implications - such as changes in livelihoods, community cohesion, and access to resources - and developing strategies to mitigate adverse impacts while enhancing benefits.
• Community consultations: this involves informing communities about the project, seeking their input, and addressing concerns.
• Prior consultation (consulta previa): For projects in the influence area of ethnic or Afro-Colombian communities, a formal prior consultation process is essential. This ensures these communities are informed, their concerns are addressed, and their consent is obtained before project implementation.

Other Obligations

• Biodiversity assessments: for projects located in or near protected areas or regions with high biodiversity, additional assessments and mitigation plans may be required.
• Water use permits: projects involving significant water use must obtain permits from relevant authorities, ensuring sustainable use and protection of water resources, included in the Environmental Licence.

Operations must adhere to specific Environmental, Health and Safety (EHS) regulations to ensure environmental protection and safety. A detailed Environmental Impact Assessment (EIA) is required to evaluate potential impacts, particularly on marine ecosystems, which includes baseline studies, impact predictions, and mitigation measures. Additionally, a comprehensive Health and Safety Risk Assessment must be conducted to identify and evaluate potential health and safety hazards associated with offshore operations, including risks related to drilling, production, transportation, and emergency response.

Operators must submit an EMP outlining specific measures to mitigate environmental impacts, monitoring plans, and emergency response strategies. A detailed Health and Safety Plan addressing worker safety, emergency response procedures, and measures to prevent accidents and health hazards is also required. 

Operators are subject to strict liability for any environmental damage caused by offshore activities, meaning they are responsible for damages regardless of fault. Operators are required to restore any environmental damage caused by their operations, including remediation of contaminated sites and restoration of affected ecosystems.

Operators must provide financial guarantees in the form of standby letter of credit and torts liability insurance, to cover potential environmental damages and ensure compliance with restoration obligations.

Decommissioning of oil and gas facilities, including plugging and abandoning wells, involves several regulatory requirements to ensure environmental protection and public safety. The process is governed by ANH.

Operators must submit a comprehensive plan to ANH well in advance of planned decommissioning activities. It must outline the timing, scope and methodology for decommissioning, including detailed procedures for plugging and abandoning wells, removing equipment and infrastructure, and restoring the site to its original condition or to a condition approved by the regulatory authorities. Approval must be obtained before any decommissioning activities can commence.

Operators are required to provide financial security in an abandonment fund to ensure that funds are available to cover the costs of decommissioning and site restoration.

Colombia has implemented several climate change laws and regulations to address environmental concerns, with specific provisions targeting the oil and gas industry.

The main legislative framework for climate change in Colombia is the National Climate Change Policy. This policy outlines the country's strategy for reducing greenhouse gas emissions and adapting to climate impacts. It includes commitments to reduce emissions in line with international agreements, such as the Paris Agreement.

A significant mandate is Colombia’s Climate Change Law (Law 1931 of 2018), which provides a comprehensive approach to managing climate change. It establishes guidelines for developing and implementing climate change mitigation and adaptation measures across various sectors, including energy, transportation, and industry. This law also emphasises the importance of integrating climate considerations into national planning and development processes.

Colombia has also introduced a carbon tax, established under Law 1819 of 2016. The carbon tax applies to the sale and importation of fossil fuels, including oil and gas. The tax rate is based on the carbon content of the fuel, incentivising companies to reduce their carbon footprint. Revenues from the carbon tax are directed towards environmental protection and climate change mitigation projects.

Specific to the oil and gas industry, Colombia has regulations that address methane emissions from oil and gas infrastructure. Resolution 2099 of 2016, issued by the Ministry of Environment and Sustainable Development, mandates the monitoring, reporting, and reduction of methane emissions from the oil and gas sector. Companies are required to implement best practices and technologies to minimise methane leaks and flaring.

In addition to these regulations, Colombia participates in the Regional Carbon Market, a cap-and-trade system aimed at reducing greenhouse gas emissions through market mechanisms. This system allows companies to trade emission allowances, providing financial incentives for reducing emissions.

Local governments have a degree of autonomy to limit mineral extraction within their jurisdictions, particularly for environmental and social reasons. This autonomy is rooted in the country's constitution, which grants municipalities the authority to manage land use and environmental protection. However, O& G policy is under the national government's regulation and control over the exploitation of natural resources, including hydrocarbons.

Local governments can impose restrictions through land-use plans (POTs) and other local regulations. These plans can designate specific areas as protected or restricted for oil and gas development to safeguard local forest reservations, ecosystems, water sources, and community interests. Municipalities can also enact local ordinances aimed at mitigating environmental impacts and ensuring that oil and gas activities comply with environmental standards.

Notwithstanding, ANH and the Ministry of Mines and Energy hold the primary authority over the allocation of oil and gas exploration and production rights. National regulations and policies often supersede local restrictions, particularly when it comes to resource development deemed in the national interest. This can lead to conflicts between local and national authorities when local governments seek to impose stricter limitations than those mandated by national regulations.

Recent court rulings have highlighted the delicate balance between local and national authority. The Constitutional Court of Colombia has affirmed the rights of local communities to participate in decisions regarding oil and gas development, emphasising the importance of prior consultation, particularly with ethnic and Afro-Colombian communities and the proceeding of concurrence and coordination to be handled by ANH prior awarding blocks. This underscores the need for oil and gas companies to engage with local governments and communities to obtain social licences to operate.

In practice, while local governments can influence and limit oil and gas activities through environmental regulations and land-use planning, their actions must align with national policies and regulations. Any significant local restrictions are subject to review and potential override by national authorities, particularly if they conflict with national economic and energy objectives.

Laws and government programmes focus on energy transition, aiming to promote renewable energy and reduce reliance on traditional fossil fuels. These initiatives are shaping the landscape of traditional energy development.

• Law 1715 of 2014: this initiative promotes the integration of non-conventional renewable energy sources (NCRE) into the national energy system. It provides incentives such as tax benefits, accelerated depreciation, and exemptions from import duties for renewable energy projects. This has encouraged investment in solar, wind, biomass, geothermal, and small hydroelectric projects.
• National Development Plan (Plan Nacional de Desarrollo): the current government plan includes specific targets for increasing the share of renewable energy in Colombia's energy mix. The plan sets ambitious goals for solar and wind energy, as well as measures to improve energy efficiency.
• Renewable Energy Auctions: the government has conducted several renewable energy auctions to award long-term contracts to renewable energy projects. These auctions have successfully attracted significant investments in solar and wind energy, contributing to a diversification of the energy matrix.
• Energy Transition Law (Law 2099 of 2021): this law further strengthens Colombia’s commitment to energy transition by promoting hydrogen production, energy storage, and electric mobility. It also expands the incentives for renewable energy projects and aims to improve the regulatory framework for integrating renewables into the grid.
• Carbon Tax (Law 1819 of 2016): as part of Colombia's strategy to reduce greenhouse gas emissions, the carbon tax on fossil fuels incentivises a shift towards cleaner energy sources. The revenue from this tax is directed towards environmental protection and climate change mitigation projects.

Ecopetrol and AES have significantly expanded their renewable energy initiatives in Colombia, inaugurating their first solar park in Castilla, Meta in 2018 with a capacity of 21 MWp, followed by a second park generating 61 MWp in 2022, and recently launching another facility in April 2024 at the Cartagena Refinery, which produces 22.1 MWp.

Early in 2022, Ecopetrol started its pilot to produce green hydrogen, with a proton exchange membrane electrolyser and 270 solar panels installed at the Cartagena Refinery to compile information on the operation, maintenance, reliability, and escalation of the technologies used. This entity also recently announced that it reduced more than 364 tons of CO2 with 385 vehicles in circulation. 

There are emerging efforts to utilise existing subsurface rights and wells for carbon capture, utilisation, and storage (CCUS) projects. These projects aim to capture CO2 emissions from industrial processes and store them underground, utilising depleted oil and gas reservoirs. However, the deployment of CCUS is still in the early stages and requires further development of regulatory frameworks and incentives.

Other initiatives are related to reducing greenhouse gas emissions during operations implementing best practices to minimise methane leaks, flaring, and venting. Many companies are investing in advanced monitoring technologies and infrastructure upgrades to detect and repair leaks promptly. Additionally, there is a push towards electrification of operations and the use of renewable energy sources to power oil and gas facilities, thereby reducing overall emissions.

Energy transition is materially affecting traditional oil and gas development in several ways. 

Investors are increasingly favouring renewable energy projects over traditional oil and gas ventures. This trend is driven by both regulatory incentives and market pressures for sustainability, as the oil and gas sector reallocates budgets and the ANH implements a policy of not issuing new exploration and production contracts, dramatically reducing the growth and expansion of conventional O&G operations.

ANH is concentrating on the offshore wind energy round initiated at the end of last year, currently progressing with plans to allocate temporary occupation permits for maritime areas in the central Caribbean, near onshore grid connection transmission lines. The timeline has experienced delays since the launch, with the latest schedule set for bid submissions on 24 April 2025.

Development of infrastructure such as pipelines is also being affected. There is a growing emphasis on ensuring that new infrastructure can accommodate both traditional natural gas, LNG and other renewable gases. Additionally, midstream operators are investing in technologies to reduce methane emissions and improve the efficiency of gas transportation and storage. These investments are essential for aligning with national and international climate goals.

Over the next five to ten years, these impacts are expected to intensify. The government’s commitment to its climate goals and international agreements will likely lead to additional regulations and higher expectations for sustainability in the oil and gas sector on which the country heavily relies, and which will be difficult to replace.

The development of unconventional hydrocarbons, such as shale gas, heavy oil, and coal-bed methane, is subject to specific laws and regulations aimed at addressing the unique challenges and environmental impacts associated with these resources. 

Regulation of shale gas exploration and hydraulic fracturing (fracking) in Colombia is a contentious issue. While the legal and environmental frame and potential for shale gas exploration exists, it has been met with significant public and environmental concerns. In 2021, Ecopetrol started a pilot project to assess the feasibility and environmental impacts of fracking. Environmental licence was suspended and the project stalled. The Congress recently dismissed a law bill prohibiting fracking so there is no legal prohibition to carry on this exploration, but this will require governmental willingness and social licence.

Coal-bed methane is another unconventional resource with potential in Colombia; however, it has been banned by the ANH for nearly 15 years.

Development of Liquefied Natural Gas (LNG) projects is supported by a regulatory framework designed to encourage investment and ensure compliance with environmental and safety standards. Several special laws, regulations, and incentives apply to LNG projects.

Such projects are governed by general hydrocarbon laws, as well as specific regulations tailored to the LNG industry. The Ministry of Mines and Energy, along with the Mining Energy Planning Unit (UPME) oversee the regulatory framework for LNG projects. These regulations cover the entire LNG value chain, from the development of upstream gas reserves to liquefaction, transportation, and export.

Exporting and importing LNG from Colombia requires several approvals and permits by the Ministry of Mines and Energy. There is currently one LNG plant operating in Cartagena, which gas importation helped to reduce the power generation shortage during “el Niño” phenomenon early this year. Meanwhile the project to construct a new LNG plant in the Pacific closed without awards last year and there are no current plans to reopen a new bid. 

The Colombian government offers various incentives to promote LNG project development, including:

• Tax benefits: companies involved in LNG projects may qualify for tax deductions, accelerated depreciation of assets, and exemptions from import duties on equipment and technology used in LNG facilities.
• Fiscal incentives: flexible royalty rates and favourable fiscal terms may be applied to upstream gas reserves developed specifically for LNG projects. These incentives are designed to reduce the financial burden and enhance the economic viability of LNG investments.
• Public-private partnerships (PPPs): there is the possibility of PPPs for LNG infrastructure development, providing a framework for collaboration between public and private sectors to share risks and benefits.

Colombia's strategic geographical location is particularly noteworthy. Situated at the crossroads between North and South America, and with access to both the Pacific and Atlantic Oceans, Colombia offers logistical advantages for hydrocarbon export. This geographic positioning is beneficial for international trade.

Additionally, Colombia has a rich history of oil and gas production dating back over a century, contributing to a well-established industry infrastructure. This includes a network of pipelines, refineries, and ports that facilitate the efficient transport and processing of hydrocarbons. The presence of this infrastructure reduces the initial capital expenditure for new projects and enhances the overall investment climate.

In November 2023, Colombia's Constitutional Court issued Judgment C-489/2023, declaring unconstitutional the amendment introduced by Law 2277 of 2022 that prohibited the deduction of royalty payments in the income tax, specifically for the production of oil, gas, and mining. The Court argued that this prohibition created an unjustified distinction between companies paying royalties in kind versus those paying in cash, without a reasonable basis related to the taxpayers' ability to contribute.

Subsequently, the Ministry of Finance and Public Credit requested the opening of a Fiscal Impact Incident (IIF) to assess the financial effects of the Court's decision.

Legal certainty regarding the deductibility of royalties for the 2023 tax year were maintained when the IIF was resolved against the Ministry's request, ensuring that affected companies can calculate their taxes with clarity and certainty.