In 2008, the Colombian government made the decision to pursue the development of unconventional hydrocarbons and, in 2011, it ordered production of technical regulations, formulation of incentives for exploration and production, and creation of rules for the award of areas for exploration and production.
Shale play details and status of play
The publication, Hart Energy, included the unconventional reservoir, La Luna Shale, in the top 20 unconventional plays in the world1.
Colombia has three basins with representative prospectivity: Middle Magdalena Valley, Cordillera, and Cesar Rancheria. The potential is estimated at about 32 TCF of recoverable volumes (Arthur D. Little Analysis).
Comparisons have already been drawn between the La Luna field in the Middle Magdalena basin and the US’s giant Eagle Ford shale. Further shale oil and gas deposits lie in the Cesar basin to the north, Catatumbo, near the Venezuelan border, and the Boyacá province to the north of Bogota.
IHS estimates Colombia’s shale could hold over 3,000 Tcf of gas, and the country’s oil industry association pegs its unconventional resources at 92 billion boe on a P50 proven and probable basis. On 2012, consultancy Arthur D Little ignited interest in the Andean country after putting recoverable shale and tight gas reserves at 35 Tcf and shale oil potential as high as 14 billion boe.
Finally, the ANH, according to numerous studies and publications has claimed that Colombia is the third country in South America with the greatest potential for shale gas and shale oil deposits after Argentina and Brazil.
Ownership of land and mineral rights
Under the Colombian Constitution, all natural hydrocarbons reservoirs in existence within the Colombian territory, whatever their nature, belong exclusively to the Republic. Therefore, the ownership of the land is different from the ownership of the subsoil and the natural resources located therein.
Holders of exploration and production (E&P) rights may use the land required for exploration and exploitation activities, even if it is privately owned by third parties. If no agreement can be reached with the land owner, Colombian law provides for mandatory servitudes and easements, and even the possibility of expropriation.
Additionally in the Llanos Basin is the Gacheta formation close to the border with Venezuela with 2 TCF of technically recoverable gas reserves.
In 2008, the Colombian government made the decision to pursue the development of unconventional hydrocarbons with policy document No. 3517, issued by the Council for Economic and Social Policy (CONPES). In 2011, the government ordered:
- The Ministry of Mines and Energy (MME) to issue technical regulations for unconventional hydrocarbons
- The National Hydrocarbons Agency (ANH) to create rules for the award of areas for the exploration and production of unconventional hydrocarbons
- The MME, the ANH and the Gas Regulatory Entity (CREG) to jointly develop and create incentives for the exploration and production of unconventional hydrocarbons.
Accordingly, MME issued Resolution 180742 of 2012, establishing the procedures for the exploration and exploitation of hydrocarbons in unconventional deposits. Its objective is to ensure that the conduct of these activities guarantees the sustainable development of natural resources in compliance with good industry practices.
Resolution 180742 defines a conventional deposit as a rock formation where hydrocarbon accumulations occur in stratigraphic and/or structural traps. It is characterised by a unique natural pressure system, so that the production of hydrocarbons from part of the field affects the pressure of the reservoir’s whole extension. The resolution defines an unconventional deposit as a rock formation with low primary permeability to which stimulation has to be performed to improve the mobility conditions and hydrocarbons recovery.
ANH issued Accord 004 of 2012, which establishes the main terms and conditions required to award hydrocarbons exploration and production areas, and Accord 003 of March 26, 2014, which builds upon Accord 004 of 2012 to include the terms and conditions required to award exploration and production contracts over unconventional resources. These regulations apply both to existing blocks with potential for unconventional resources and to new blocks that have yet to be awarded. For those blocks awarded prior to 2012, contractors are required to request the ANH to enter into an additional contract for exploiting and exploring unconventional resources. Companies already holding areas with potential for shale gas resources (as mentioned above) will have three years to convert their existing concession to the new regime for the exploration and production of unconventional resources.
Conventional v unconventional hydrocarbons
Table 1 illustrates the main differences between conventional and unconventional hydrocarbons regulation.
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Table 1: Regulation – differences between conventional and unconventional hydrocarbons regulation
Ministry of Mines and Energy
MME is responsible for the overall regulation of the energy sector, including any policies relating to hydrocarbon exploration and production activities. It is responsible for overseeing upstream activities, such as drilling of exploration wells and payment of the corresponding royalties to the nation.
National Hydrocarbons Agency
ANH is responsible for managing hydrocarbons and defining the contracting policies and regulations for their exploration and exploitation. ANH is in charge of administering oil and gas reserves in Colombia.
State oil company
The Empresa Colombiana de Petróleos (Ecopetrol) was created in 1951 as a wholly State-owned public entity whose main corporate purpose was to carry out all the activities related to the oil and gas industry in Colombia.
The transformation of Ecopetrol in 2003 released it from State functions as the sole administrator of the oil source and, in 2004, ANH was created to perform this role and manage the hydrocarbon reserves in Colombia.
The Colombian Commission for the Regulation of Energy and Gas (CREG) is responsible for regulating the electricity and gas public services as provided by law 142 and 143 of 1994. Regulatory commissions have the task of regulating monopolies in the provision of utilities, when competition is not actually possible and, in other cases, to promote competition between utilities providers, in order for the operations of the monopolists or competitors be economically efficient.
Decree 1760 of 2003 created ANH as a special administrative unit assuming the administration of the hydrocarbons resources. ANH grants E&P rights to private entities by means of E&P contracts and technical evaluation agreements (TEA).
Through a TEA, contractors may conduct exploration activities within the granted area and obtain exclusivity and conversion rights. By means of these rights, no third party may be granted an E&P contract overlapping with the TEA areas during the term of the contract and two additional months, or until the contractor selects an area for conversion to an E&P contract, whichever occurs first. E&P contracts grant to the contractor the exclusive right to explore for and produce conventional and unconventional hydrocarbons within a limited area.
For E&P rights granted from 2004 to 2014, there are two main regulatory sub-regimes. Table 2 presents their main features.
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Table 2: Main features of the contractual sub-regimes
Under the rules established in Acuerdo 004 of 2012, areas for exploration and exploitation of hydrocarbons will be awarded through bidding processes and, exceptionally, through direct award processes.
The terms of reference prepared by the ANH will have to follow certain parameters defined in the Acuerdo 004 of 2012, as follows.
- Only legal entities may present a bid for an area. They can be national or foreign entities.
- Bids may be presented individually by an entity or collectively by means of a consortium, temporary union or promise to incorporate a company.
- In order to be qualified as operator, the bidder must prove that its corporate purpose expressly includes exploration and production activities of hydrocarbons.
- The operator must have been incorporated at least five years prior to presenting the bid. Non-operator bidders must have been incorporated at least one year prior to presenting the bid.
- The company must have a duration term equivalent to the term of the E&P contract plus three additional years.
- Bidders cannot: (i) have any incompatibilities, inabilities or conflict of interest; (ii) be in status of liquidation or have any pending litigation; (iii) permit any of its activities to be related to or made in connection with illegal activities, or made to finance illegal activities or to enable money laundering; and (iv) be a party to a contract with the State whereby unilateral termination due to breach of its obligations has been declared within the past five years.
- In case the bidder is a foreign entity, it has to commit itself to: (i) create a company or a branch in Colombia; and (ii) appoint a legal representative in the country upon award of the area by the ANH.
- The legal representative of the company shall have full authority to present the bid and comply with its obligations on behalf of the company.
- The operator must maintain at least a 30 per cent participation in the contract.
To determine the financial capacity, the bidder must provide:
- financial statements for the periods requested by the ANH in the terms of reference
- projected cash flow for the following years as required by the ANH in the terms of reference.
The terms of reference will establish the minimum requirements for the patrimony and the mechanism and criteria to be used for the evaluation of the financial capacity.
The ANH may request the granting of additional security by the bidder, such as letters of credit and escrow accounts.
Some companies are not subject to the financial evaluation process. They are:
- Companies listed as an upstream company in the latest edition of The Energy Intelligence Top 100: Ranking the World’s Top Oil Companies, issued by Petroleum Intelligence Weekly.
- Companies that show they have been ranked with a ‘BBB’ by Standard & Poor’s, ‘Baa’ by Moody’s or ‘BBB’ by Fitch Ratings.
The bidder must demonstrate that it has the operational experience required in the terms of reference to undertake the activities under the E&P contract in terms of production levels and reserves volume. ANH may also request previous experience in terms of the number of wells drilled, E&P contracts previously executed or in place, and quality certificates to prove technical and operational capacity.
Companies listed as an upstream company in the latest edition of The Energy Intelligence Top 100: Ranking the World’s Top Oil Companies, issued by Petroleum Intelligence Weekly, are not subject to the operational evaluation process.
The bidder must prove that it has implemented and executed a system for the environmental management, measure and follow-up of the operations and activities causing an impact on the environment and natural resources.
ANH may require the contractor to obtain the certificate ISO14001, or any other equivalent certificate, within the three years following the execution of the E&P contract.
The bidder must prove that it has implemented and executed rules, practices and goals in terms of corporate social responsibility.
Rights, licenses and approvals
The scope of the TEA is limited to exploration activities to evaluate the potentiality of an area and to identify specific areas in order to enter into an E&P contract.
Within the first 90 days following the execution of the contract, the contractor must confirm the presence of indigenous or Afro-Colombian communities in the area. It must request a certification from the Colombian Institute of Rural Development and the Ministry of Justice. The contractor must inform the ANH during Phase 0 if minority communities are present or not. Once Phase 0 has elapsed, the TEA has a 36-month term.
The E&P contract gives the contractor the right to perform exploratory activities in an assigned area and to produce the hydrocarbons owned by the State that are discovered in said area, based on specific programs. This is in exchange for the payment of government take, consisting of royalties, economic rights and contributions for the training, institutional strengthening and technology transfer.
Exploration period – for conventional fields, upon completion of Phase 0, the exploration period begins and has a duration of six years, divided in phases, each with a minimum work programme. For unconventional fields, the exploration term is nine years from the date of award.
Production period – for conventional fields, the duration of the production period is 24 years as of the commercial discovery notice for conventional hydrocarbons and 30 years for unconventional hydrocarbons.
Exploitation term – for unconventional fields, the exploitation term runs for a maximum of 30 years from the declaration of commerciality.
Contractors under the current E&P contracts are entitled to exclusivity in the area of the contract. However, under TEAs, ANH has the power to conduct or authorise the conducting of any type of geophysical, geochemical, geological, cartographic or photo-geological studies and works within the area assigned for technical evaluation.
The contractor may enter into subcontracts for petroleum services in order to develop activities. However, in no case may the holder subcontract the operation of activities under the E&P contract without obtaining the prior approval of the ANH.
Assignment and change in control requirements
Assignment authorisation – the contractor may assign or transfer, in whole or in part, its interests, rights and obligations thereunder, only with the prior written authorisation of the ANH.
Change in control authorisation – any transaction that implies a change of the beneficiary or the controlling party of the contractor or of any of the members of the contractor, will be understood as a form of assignment and will require prior ANH authorisation.
Corporate reorganisation – any merger or spin-off of the contractor will require prior authorisation from the ANH.
Parent company guarantee – when a controlling company accredits any capacity during any bidding process of any of its subsidiaries, through which it assumes joint and several liability for the commitments and obligations undertaken by its subsidiary, a joint and several debtor guarantee is required. The other applicable guarantees are:
- ‘Stand-by’ letter of credit for 50 per cent of the total cost set for the minimum exploration program and 50 per cent of the additional exploration program
- Third-party liability insurance, for which the validity will be equal to the term of duration of the contract, from the effective date and three additional years. The amount of the insurance shall be: US$10 million for conventional onshore fields; US$50 million for offshore fields; and US$30 million for unconventional fields
- Insurance policy for labour obligations – the amount of the insurance will be:
- For the exploration period: 5 per cent of the annual investment for each phase or 10 per cent of the total annual costs of the personnel designated to work in the exploration area for each calendar year.
- For the evaluation and production period: 10 per cent of the total annual costs of the personnel designated to work in the production areas for each calendar year.
If during the performance of an E&P contract there is any default of an obligation by the contractor, the ANH may impose fines.
Fines will be 1 per cent of the value of the activity that was not performed, per day of breach, up to 10 per cent of the value of the activity, regarding obligations having a determined value. Regarding obligations with an indefinite value, fines will be imposed for up to US$100,000.
The contractor shall indemnify, defend and hold the nation, the ANH and its employees and properties, or any third parties, harmless from any claim or action arising from actions or omissions in the development or performance of the agreement.
E&P contracts will terminate in any of the following situations: the contractor’s resignation; the expiration of the exploration period without filing a notice of discovery; failure to submit an evaluation programme upon expiration of the exploration period; expiration of the production period; and by mutual consent of the parties.
Also, the contractor may unilaterally terminate the agreement as long as it has complied with the corresponding obligations in the contract and gives written notice to the ANH one year in advance.
Establishment of the local entity
Under Colombian corporate law, a corporate vehicle must be incorporated in order to operate any kind of trade or business in the country. Said vehicle may be either a local branch of a foreign company or a local Colombian company. The most common and suggested vehicles used by foreign oil and gas companies are simplified stock companies and branches of foreign companies.
For foreign company branches, the foreign investor must file certain documents before the Chamber of Commerce related to the creation of the foreign company. The assigned capital for the branch must be registered as foreign investment before the Central Bank.
These branches may not acquire foreign currency in the exchange market by any means, and must fund their local expenses in Colombian currency. They may rely on the exchange market to transfer abroad the foreign currency received from: internal sales derived from the exploitation/ sale of products or the rendering of their services; profits; and the foreign investment in case of the liquidation of the branch.
Branches of foreign companies that are part of the oil and gas industry must be registered at the MME.
Simplified stock companies require at least one shareholder. The corporate purpose can be any legal business activity without having to refer to a specific business activity. There is no minimum capital, and simplified stock companies are not required to have a Board of Directors.
During the exploration period, the subsoil rights are as shown in Table 3.
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Table 3: Subsoil fees
For areas assigned for evaluation or for production, the contractor must pay to the ANH a fee in US dollars, which is the result of multiplying the hydrocarbons production by 13 cents of a dollar, plus US$0.1356, per barrel of liquid hydrocarbons. For natural gas, this amount is US$0.01356 per 1,000 cubic feet.
The values set in table 3 above must be updated each year according to the variation percentage of the Producer Price Index (PPI) published by the Department of Labor of the United States of America.
Royalties are calculated as a proportion (between 8 per cent and 25 per cent) of the daily gross production based on the monthly average production per field, as illustrated in Table 1.
A royalty of 60 per cent of the participating percentage of the royalties applicable to the exploitation of conventional light oil fields will be applied to unconventional resources.
Royalties paid are considered as a deductible expense in the income tax.
This contribution is paid to the ANH for the professional and specialised formation related to the oil and gas sector. The amount of the contribution will not exceed US$127,112.
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Table 4: Base referential prices
High prices fee
The contractor pays to the ANH a fee for ‘high prices’ (which is similar to windfall profits tax) on the production it owns, either in kind or in cash, at the ANH’s election, in the following cases:
- Liquid hydrocarbons (except for extra-heavy hydrocarbons) – as of the moment at which the accumulated production of the assigned area, including the volume pertaining to royalties and tests, exceeds 5 million barrels, and the price of the marker crude ‘West Texas Intermediate’ (WTI) exceeds the base price Po
- Natural gas – after the lapsing of five years from the startup of production of natural gas and when the average sales price thereof exceeds the base price Po.
The value of the fees for high prices will be determined using the following formula: Q = [(P – Po)/P] x S
Q = Economic right (fee) to be delivered to the ANH
P = Marker price (WTI for crude oil or average sales price of natural gas)
Po = Base referential price according to Table 4
S = Participation percentage according to Table 5
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Table 5: Participation percentage
In E&P contracts resulting from a bid process, ANH will receive the ‘X-factor’, which is the percentage of gross production after royalty offered by the contractor during the bidding process.
Taxes, duties, royalties and incentives
Corporate income tax
The current applicable income tax rate on net taxable income is 39 per cent. This tax is slated to be temporarily increased to 40 per cent in 2016, 42 per cent in 2017 and 43 per cent in 2018. Congress might extend the temporary increase or make it permanent. In the absence of the extension, the rate will be 39 per cent from 2019 onwards.
Capital gains tax is an additional tax on specific income with its own taxable base. It taxes the profits on the sale of assets (other than inventory) held by the taxpayer for more than two years. Law 1607 of 2012 lowered the capital gains tax rate from 33 per cent to 10 per cent.
Activities related to hydrocarbons are subject to the general corporate tax regime. There is no special tax for hydrocarbons.
Taxes paid abroad on foreign source income will be considered as a deduction of tax payable in Colombia up to an amount that does not exceed the tax payable on the corresponding income in Colombia./p>
There is no remittance tax applicable in Colombia.
Taxes on financial transactions
The Colombian Bank debit tax is 0.4 per cent of the withdrawal amount from savings and checking accounts, credit card transactions, loan disbursements and certain other transactions.
The most important indirect taxes affecting hydrocarbonrelated activities are VAT and financial transactions tax.
The national stamp tax is currently 0 per cent. However, certain departments in Colombia, especially those in the Caribbean Region, may have a local stamp tax that is triggered in certain cases. The amount is up to 1 per cent of the gross income set forth in the document or taxed activity.
The import of oil and gas assets is, in general, subject to customs duties (that is, VAT of 16 per cent on Cost Insurance and Freight (CIF) value plus tariff between 0 per cent and 20 per cent on CIF plus VAT). Under the various free trade agreements and other international agreements on trade, tariffs may be reduced to 0 per cent, depending on the good, its origin and the terms agreed therein.
Tariffs on imports in Colombia range from 0 per cent to 20 per cent, depending on the imported goods, their origin and the application of international agreements with preferential rates. If a duty-free zone is established in an offshore area, such tariffs will not apply.
VAT is triggered on the sale of goods in Colombia, the rendering of services within Colombian territory and the import of taxed goods. For hydrocarbon activities:
- oil sold in Colombia to be refined is VAT excluded
- oil exported is VAT exempt
- oil sold in Colombia not to be refined is taxed at 16 per cent
- gas sold in Colombia is VAT excluded
- gas exported is VAT exempt.
As a general rule, expenses incurred during the tax year that are not recorded as assets (and therefore will not be amortised) are deductible.
In the case of acquisition or exploration and exploitation costs related to non-renewable natural resources, the amortisation can be calculated using either the special system of technical estimation of the operating units cost, or the straight line method. In both cases, the amortisation term cannot be lower than five years. If the exploration investments do not succeed, the amount invested can be amortised in the year in which it is declared as unsuccessful or within the following two years.
Please refer to the section on royalties under ‘State participation’ above.
Foreign currency and Central Bank requirements
The ordinary exchange control regime applies to Colombian individuals, legal entities and branches of foreign companies not subject to the special regime. Pursuant to this regime, all transactions between residents must be paid in Colombian currency. Currency for transactions subject to the mandatory use of the exchange market must be sent abroad or brought to Colombia using the authorised entities and/or mechanisms.
The special exchange control regime is applicable only to branches of foreign entities engaged in oil and gas activities that are not subject to the obligation of reimbursing currency obtained from their exports. Under the special exchange regime, imports are non-reimbursable. That is, the importer does not have to pay them using the exchange market, and entering into foreign indebtedness or international lease agreements is not allowed. The reason for this is that, in these types of activities, resources are usually provided by the same entity engaged in doing business in Colombia, via capital investments or supplemental investments to the assigned capital.
Environmental protection and socio-economic development
The Ministry of Environment and Sustainable Development (MADS) is in charge of managing environment and renewable natural resources. It is responsible for guiding and issuing the environmental planning and development policies and regulations to secure the recovery, conservation, protection, management and sustainable use of renewable natural resources and the environment of the nation.
Regional environmental corporations (CARs) also issue regional permits for the use of natural resources.
The National Authority of Environmental Licensing (ANLA), a specialised administrative unit, is the public entity in charge of granting the corresponding environmental licenses in the oil and gas sector.
The environmental authority may impose penalties arising from the breach of the enforceable environmental regulations.
The holder of the E&P rights to carry out activities under the granting instrument is exclusively responsible for any environmental liabilities.
Environmental impact assessments, reporting rules and audits
Environmental diagnostic of alternatives
Prior to requesting an environmental license, the contractor must request from the environmental authority its opinion on whether or not an environmental diagnostic of alternatives (EDA) is needed for the upcoming project.
The ANLA has responsibility for supervising environmental matters and granting the corresponding licenses in the hydrocarbon sector in the following cases:
- Seismic shooting that requires the construction of roads and offshore exploration in depths up to 200m.
- Drilling activities that are not within the hydrocarbon production fields of the contractor.
- Exploitation of hydrocarbons, which includes drilling, construction of facilities for development of the project, internal transportation of fluids within the same field, and any other related infrastructure part of the exploitation activity.
- Transportation of liquids outside of the fields and the construction of storage facilities.
- Points of delivery and transfer stations of liquid hydrocarbons.
- Construction of refineries and facilities used during this process.
The environmental impact assessment (EIA) is the basic instrument used for the execution of projects and activities that require an environmental license. The EIA must include the following information:
- Project location and activities to be carried out
- Use of natural resources during the project
- An environmental impact study and risk assessment
- Economic analysis of the positive and negative impacts of the project
- An abandonment plan upon termination of the project.
The environmental license is granted by the environmental authority, ANLA, and can be understood as the authorisation granted by such competent authority for the execution of the determined activity or project.
Other types of permit, concession and authorisation may be needed to carry out certain activities that require the use of specific natural resources and that may cause an environmental impact.
Once the exploration period is completed, the contractor must obtain a global environmental licence (GEL), which is required for the development of works and activities related to hydrocarbons exploitation.
Prior consultation process
E&P activities in the area of influence of defined indigenous or African-Colombian territories or communities of the project are subject to a prior consultation process with such communities (consulta previa). The purpose of this consultation is to include mitigating measures for the negative impacts while maximising positive impacts.
If the affected communities still resist supporting the project after such a consultation process, the final decision will be made by the MME.
New license regime (Decree 2041 of 2014)
According to this new regime, a developer that has an existing license for exploitation of conventional hydrocarbons, and intends to explore or exploit unconventional hydrocarbons in the same area, will have to apply for a modification of the existing license.
Environmental sanctionatory regime (Law 1333 of 2009)
The purpose of the sanctionatory regime is to protect natural resources and the environment. In the regime, the negligence or misconduct of the offender is presumed. If the presumed offender does not overcome the presumption of negligence or misconduct, it will be subject to sanctions.
The only available defences against environmental responsibility are: act of God, force majeure, sabotage, act of third party or terrorism.
Contractual environmental liabilities
Duty of information
The contractor must keep the ANH informed, on a timely and permanent basis, about the progress of compliance with environmental and social formalities. It must give timely notice to ANH of any difficulty that may arise in the course of the foregoing formalities and that may affect the terms agreed in the E&P contract.
Term to commence actions to obtain environmental permits and licenses
In order to carry out activities that require licenses or any other environmental authorisations, the contractor must start all required actions with the competent authorities no later than 90 calendar days prior to the scheduled date of commencement of the activity.
If the contractor does not meet these terms or fails to exercise due diligence regarding compliance with the required formalities, this will give rise to the declaration of default by the ANH.
Nonetheless, delays resulting from the previous consultation process are very common. If the contractor handles the processes diligently, there will be grounds for requesting a suspension of obligations under the E&P contract or an extension of the contractual terms.
Nonetheless, delays resulting from the previous consultation hydrocarbons
Pursuant to Colombian law, oil may be freely exported. However, according to the Petroleum Code, hydrocarbon producers may first be required to satisfy the internal necessities of the country and sell their production to supply the domestic demand. In this case, hydrocarbons will be paid for at international prices.
Gas may also be freely exported, and exports may be limited if the gas is needed to satisfy domestic supply.
Enforcement regime, in judicial and arbitral alternatives
Under Colombian constitutional law, first instance (Lower Court) judicial and/or administrative decisions may be challenged through recourses/appeals. In addition, the nature of the dispute and the circumstances surrounding the case may grant extraordinary recourses to plaintiffs and/or defendants which are to be decided by the Colombian Higher Courts.
As Colombia is not a common law jurisdiction, courts are not compelled to follow judicial precedents.
Decisions from foreign jurisdictions
Foreign court judgments and arbitration awards are enforced in Colombia through an exequatur procedure. The procedure consists of presenting the decision or award before the Supreme Court of Justice for it to consider whether to issue the exequatur or deny it.
Foreign court judgments and arbitration awards are enforced
The latest changes to the regulatory regime applicable to the oil and gas industry includes the issuance by the MME of Resolution 90341 of 2014 and the Acuerdo 003 of 2014 issued by the ANH. This regulation specifically excludes the exploration of coal-bed methane.
The latest bidding competitive process took place during 2014. There will be further investment opportunities in the sector through new bidding processes to be opened by the ANH in the future. Farm-ins or similar arrangements may also be implemented or opportunities may arise via the assignment of participations in the E&P contracts already executed by the ANH or the contracts entered into by Ecopetrol.