Global Legal Group Questions For The International Comparative Legal Guide To: Oil & Gas Regulation 2015
By Gabriela Mancero
- A brief outline of Colombia’s natural gas sector, including a general description of: natural gas reserves; natural gas production including the extent to which production is associated or non-associated natural gas; import and export of natural gas, including liquefied natural gas (LNG) liquefaction and export facilities, and/or receiving and re-gasification facilities (“LNG facilities”); natural gas pipeline transportation and distribution/transmission network; natural gas storage; and commodity sales and trading.
Natural gas in Colombia was only properly regulated in the nineties. Thanks to such regulation and to a successful mass consumption policy, the number of natural gas users grows year after year. It is considered an environmentally friendly fuel, which is welcome in industrial processes given Colombia’s position as one of the most bio-diverse countries in the world. In the mid-nineties, a so-called “Gas Plan” was enforced in order to ensure: natural gas supply by means of the continuity of exploration activities and exportation of new reservoirs; the construction of a main gas pipeline network; the development of the transportation system; and the shaping of a market in the industrial, residential and thermoelectric sectors.
In the development of the above-mentioned Governmental instructions, ECOPETROL, the then State-owned oil and gas corporation, hired and financed the construction of gas pipelines which constitute the backbone of inland gas transportation in Colombia.
In 1994, a public utilities law was passed which separated gas marketing and transportation activities at ECOPETROL, ending with Law 401 of 1997 that separated gas transportation and the property of the corresponding assets from ECOPETROL and created ECOGAS (later transformed to Transportadora de Gas del Interior – TGI S.A. E.S.P.) as an independent company.
Together with the above, and although most of the developed economies around the world present signs of recession, the main macroeconomic indicators of Colombia evidence stability. A controlled inflation, a relatively stable exchange rate vis-à-vis the US dollar, a lower unemployment rate, the improvement in the country’s Standards & Poors’ investment rate and an important number of free trade agreements, double taxation treaties and foreign-investor-friendly regulation recently passed, have all made the country on target for many investment projects in all sectors of the economy.
In Colombia, there are two regions where 85 per cent of the Natural Gas reserves are located; the first is in the north of the Caribbean Coast in the fields of Ballena and Chuchupa, and the second region is located in the region of the Llanos Orientales (eastern lowlands) and Piedemonte llanero in the fields of Apiay, Cusiana and Cupiagua. According to official figures, as of December 2012, natural gas reserves in Colombia amounted to seven (7) trillion cubic feet (TCF), an increase of 5.7 per cent with respect to the year 2011. In fact, the National Hydrocarbons Agency (ANH from its Spanish name) has informed that, in the last five years, natural gas proven reserves increased by an average of 9.18 per cent per year.
As far as production is concerned, the total estimated production of natural gas between January and May 2014 amounted to 204.5 billion cubic feet (GCF) per year with major production concentration in the Guajira fields, amounting to 46.4 per cent of the nation’s total production, followed by the Cusiana-Cupiagua fields, which contributed 37.5 per cent. It is expected that, in the period ending in the year 2022, the Guajira fields will constitute 18.5 per cent of total production whereas the Cusiana and Cupiagua fields will constitute 59.5 per cent of the total.
Currently, Colombia is self-sufficient in natural gas and recently began exporting to neighbouring Venezuela. Natural gas in Colombia is both associated (Cusiana fields) and non-associated (Guajira fields). There are no liquefaction or re-gasification facilities. Neither are there storage facilities in the country.
The first natural gas liquefaction project is currently under construction by PROMIGÁS, with an investment of 134 million US dollars and a capacity of 78,000 gallons. Construction is expected to start at the end of 2014.
The National Transportation System of Colombian natural gas links the gas production centres with the consumption centres, excluding dedicated connections and gas pipelines, distribution systems, non-regulated users, international interconnections and storage systems. The National Gas Pipeline Network comprises two subsystems that are clearly defined by their property and operation, as well as their functioning. First, there is the Atlantic Coast subsystem with the Ballena-Barranquilla-Cartagena-Cerromatoso line, which belongs to PROMIGÁS, a private company with foreign capital shares through ENRON from the United States.
Secondly, there is the subsystem that mainly comprises: the Ballena-Barrancabermeja- Vasconia-Cali, Cusiana-Apiay-Bogotá and Cusiana-La Belleza-Vasconia-Cali lines, which belong to Transportadora de Gas del Interior (TGI S.A. E.S.P. – formerly ECOGAS), plus the Sebastopol-Medellín lines that belong to the company TRANSMETANO; the Payoa-Provincia-Bucaramanga line belonging to TRANSORIENTE; the Yumbo-Cali delivery station belonging to TRANSOCCIDENTE; the Hobo-Neiva production field belonging to PROGASUR; the Cogua-Bogotá station that belongs to TRANSCOGÁS; and the Tolima Gas Pipeline, which comprises two small lines, is known as the inland transportation subsystem. This situation makes the Colombian market behave like two segmented submarkets, which are independent from one another.
The eight natural gas transportation companies that currently operate in the country are: PROMIGÁS; TGI; TRANSMETANO; TRANSCOGÁS; TRANSOCCIDENTE; TRANSORIENTE; GASODUCTO DEL TOLIMA; and PROGASUR.
Sales and trading of natural gas in Colombia were recently restructured as a result of CREG Resolution No. 089 of 2013. CREG is the Gas and Energy Regulation Commission, in charge of issuing the sector rules. Pursuant to Resolution 089, there is a wholesale primary and secondary market where all natural gas transactions take place (including the sale of natural gas and/or transport capacity). It also comprises commercial intermediation transactions such as the purchase, transport, distribution and sale to final users.
Trading in the primary market may be done either: (i) through direct negotiation at any time of the year; (ii) through direct negotiation at a defined time of the year; or (iii) at auction.
Through direct negotiation at any time of the year. Trading by producers-traders may be carried out: (i) when natural gas comes from fields that are under extensive tests; (ii) for fields the marketability of which has not been declared yet; (iii) for minor fields; (iv) for non-conventional deposits; (v) for isolated fields; (vi) for new fields; (vii) when offered through the form of a contingency supply contract; or (viii) with regard to purchase option agreement against exports, provided the amount to be traded does not exceed the amount sold or to be sold by the corresponding producer-trader for exporting purposes. Trading by traders of imported natural gas may be carried out: when it is destined to cover demand by the thermal electricity sector; or when offered through a contingency supply contract.
Through direct negotiation at a defined time of the year. Applies to sellers and buyers authorised to participate in the primary market who may agree directly on the supply of natural gas during the period established by CREG, not exceeding ten business days. Contracts deriving from such negotiations must be executed during the period established by CREG. Contracts under this category may only be firm sale contracts, conditioned firm sale contracts and purchase option contracts, with a term of one (1), five (5) or over five (5) years. Contracts shall have as a starting date of the supply, 1 December of the year of direct negotiation, and as a termination date of the supply, 30 November of the corresponding year.
Auction. Within the first ten (10) business days of June every year, CREG shall issue a resolution establishing the applicable trading mechanism pursuant to the Mining and Energy Policy Unit’s (UPME) analysis which evidences that natural gas production is lower than, or the same as, natural gas demand, in at least three (3) of the five (5) years following the moment of analysis, in which natural gas must be traded through an auction.
In auction negotiations, only natural gas firm sale contracts, conditioned firm sale contracts and/or purchase option purchase contracts may be agreed upon with a term of one (1) or five (5) years for supply during the period between 1 December of the first year of gas supply and 30 November from the first or fifth following calendar year.
In the secondary market, where participants holding gas supply or capacity rights may negotiate their contractual rights, trading may be done either through: (i) direct negotiation; or (ii) take or pay agreements.
Direct negotiation. With the exception of non-regulated users, sellers and buyers of the secondary market may negotiate directly the sale of natural gas. The parties may freely agree the price of natural gas traded through direct negotiations.
Sellers and buyers must be registered with the central electronic bulleting board (BEC from its Spanish name).
Take or Sell Negotiation Process. Natural gas contracted and nominated for the next day shall be available to buyers through this procedure. In the take or sell process the following stages shall apply:
- Declaration of available amounts.
- Definition of the offer price.
- Publication of the available amount.
- Receipt of purchase applications.
- Available amount auction.
- Information of the auction results.
- Contract execution.
- To what extent are Colombia’s energy requirements met using natural gas (including LNG)?
Approximately 70 per cent of electricity consumed in Colombia derives from hydraulic sources. The remaining 30 per cent comes from thermal generation (both coal- and natural gas-based), liquid fuels and sugar cane pulp.
Electric generation based on natural gas is expected to decrease within the next few years. Decrease rates indicate a 14.7 per cent average per year in the period between 2013 and 2022.
In the period ending in the year 2023, UPME considers that electricity generation will amount to 12,204 megawatts (MW) out of which 4,923 MW will correspond to hydro power, 3,259 MW from coal-based thermal generation, 1,099 MW from natural gas-based generation, and 121 MW will come from liquid fuels and sugar cane pulp.
- To what extent are Colombia’s natural gas requirements met through domestic natural gas production?
Currently, Colombia is a self-sufficient natural gas producer. According to official data published by UPME (the Government agency in charge of sector statistics and projections), the natural gas production projection for the coming years indicates that domestic production will supply domestic demand until April 2018.
- To what extent is Colombia’s natural gas production exported (pipeline or LNG)?
Colombia exports natural gas to Venezuela, under sale contracts that will continue to be in force until July 2015.
2 Overview of Oil Sector
2.1 Please provide a brief outline of Colombia’s oil sector.
The Colombian oil industry is currently one of the country’s main areas of production. By 2013, Colombia had proven reserves equivalent to 2,445 million barrels, the sixth largest in South America, and the 35th largest in the world.
Until June 2014, Colombia reached a production of 981,000 barrels per day (bbl/d).
During 2014, crude oil production in the country fell when compared with production in 2013. Production has been affected both by corrective and planned maintenance to various camps and by a number of community obstructions blocking oil transport as well as guerilla attacks.
2.2 To what extent are Colombia’s energy requirements met using oil?
Approximately 70 per cent of electricity consumed in Colombia derives from hydraulic sources. The remaining 30 per cent comes from thermal generation (both coal- and natural gas-based), liquid fuels and sugar cane pulp.
In the period ending in 2023, UPME considers that electricity generation will amount to 12,204 megawatts (MW) out of which 4,923 MW will correspond to hydro power, 3,259 MW from coal-based thermal generation, 1,099 MW from natural gas-based generation, and 121 MW will come from liquid fuels and sugar cane pulp.
2.3 To what extent are Colombia’s oil requirements met through domestic oil production?
Colombia is a net oil exporter. Nevertheless, some refined products must be imported as domestic demand surpasses production capacity. The country is currently focusing efforts on the expansion of the refinery located in Cartagena in order to increase its capacity and improve the quality of refined products.
2.4 To what extent is Colombia’s oil production exported?
As of June 2014, oil exports amounted to USD$ 15,670,000 FOB.
3 Development of Oil and Natural Gas
3.1 Outline broadly the legal/statutory and organisational framework for the exploration and production (“development”) of oil and natural gas reserves including: principal legislation; in whom the State’s mineral rights to oil and natural gas are vested; Government authority or authorities responsible for the regulation of oil and natural gas development; and current major initiatives or policies of the Government (if any) in relation to oil and natural gas development.
In Colombia, any business entity, including joint ventures such as consortia or temporary unions, and local or foreign companies whose business includes oil-related activities, may perform exploration and production activities. These companies must be registered before the Ministry of Mines as exploration and production companies.
The following is the main legal/statutory framework for the exploration and production of oil and natural gas reserves:
|National Constitution Arts. 101, 102, 332, 360||1991||General ownership of land rights and royalty payment obligations|
|Oil Statute (Legislative Decree 1056 of 1953) and its amendments||1953||Framework law regarding the oil industry|
|Law 812||2003||Fostering investment in the oil sector|
|Law 1118||2006||Restructuring of Ecopetrol|
|Decree 1760||2003||Restructuring of Ecopetrol and oil blocks administration powers to NHA|
|Law 21||1991||Approves Convention No. 169 concerning Indigenous and Tribal Peoples in Independent Countries, adopted by the 76th ILO General Conference, Geneva 1989|
|Decree 1320||1998||Compulsory consultation to indigenous communities|
|Law 70||1993||Recognises the rights of black communities on their territory|
|Decree 1320||1998||Regulates prior consultation with indigenous and black communities for the exploitation of natural resources within their territory|
|ANH Agreement 08 and 35||2004||Regulation regarding contracts for new areas|
|Resolution 18-1258 by the Ministry of Mines||2010||Oil transport activity through oil pipelines|
|Resolution 12-4386||2010||Schedule of charges for oil transport|
|Decree 727||2007||Rules for the valuation and accounting of oil reserves|
|ANH Resolution 181495||2009||Establishes rules for exploration and exploitation of oil and gas|
|Decree 3229||2003||Criteria for royalty distribution when a block is located in more than one municipality|
|Decree 625||1996||Provisional liquidation and set-off of royalties|
|Decree 3176||2002||Royalty regulation|
|Decree 1747||1995||Distribution of resources deriving from royalties|
|Decree 620||1995||Control and monitoring of the resources from royalties and compensation for the exploitation of natural resources|
|Decree 3274 of 2009 and Resolution 181495 of 2009 by the Ministry of Mines||2009||Measurement standards for the oil industry|
|Decree 2100||2011||Mechanisms to promote assurance of natural gas supply nationwide|
|Agreement 004||2012||Management and assignment of areas, contracts regulation and control of contracts enforcement|
|Law 1530||2012||Regulates the general royalties system|
|Resolution 180742||2012||Process for exploration and exploitation of unconventional hydrocarbons|
|Decree 1077||2012||Royalty functioning and collection|
Economic rights for high prices and subsoil use update
|Decree 3004||2013||Process for exploration and exploitation of unconventional hydrocarbons|
|Resolutions 350 and 351 by the ANH||2014||Royalty functioning and collection|
|Agreement No. 3||2014||Non-conventional fields E&P contracts regulation.|
Measures to stimulate the creation of new natural gas markets.
|Law 39||1987||Oil and derived products distribution|
|Law 26||1989||Distribution of liquid fuel|
|Decree 283||1990||Partially amended by Decree 1521 of 1998 regulates: the storage, handling, transport and distribution of liquid fuels; and the tank-transportation of crude oil|
|Decree 1521||1998||(Partially abolished): regulates the storage; handling; transportation; and distribution of liquid fuel for petrol stations|
|Decree 2195||2001||Fuel distribution in border areas|
|Decree 1503||2002||Marking-up of liquid fuel|
|Decree 1609||2002||Land transport and handling of hazardous substances|
|Law 693||2001||Use of fuel grade alcohol|
|Decree 4299||2005||Requirements, obligations and sanctioning regime applicable to agents in the liquid fuel distribution chain|
|Code of Commerce||Supply and commercial agency agreements chapters|
|Law 393||2004||Biofuels trade|
|Decree 1333||2007||Adds new provisions to Decree 4299 of 2005|
|Law 1717||2008||Adds new provision to Decree 4299 of 2005|
|Decree 2090||2003||Regulates high health-risk activities in the industry|
|Decree 806||1998||Affiliation to the social security system|
|Decree 1220||2005||Environmental licences|
|Law 1333||2009||Environmental sanctioning regime|
|Decree 3678||2010||Regulates Law 1333|
|Decree 70||2001||Modifying the structure of the Ministry of Mines and Energy|
|Decree 2100||2011||Introduces the first regulation about unconventional hydrocarbons|
|Legislative Act 05||2011||Reform to the distribution of royalties and establishes the General Royalties System (SGRfrom its Spanish abbreviation)|
|Decree 4950||2011||Royalties General Budget for the year 2012|
The Government authority or authorities responsible for the regulation of oil and natural gas development in Colombia are:
- Ministry of Mines and Energy: Administers non-renewable natural resources; guides the use and regulation of such resources guaranteeing its supply and ensuring their protection.
- Mining and Energy Planning Unit (UPME): Is a technical authority, in charge of planning the development and use of all Colombia’s mining and energy resources, including oil. It is also responsible for the organisation and management of the energy and mining information system.
- National Hydrocarbons Agency (ANH): Is the authority responsible for the promotion of the resource, to promote the investment in the oil and gas industry, the management and control over the E&P Contracts and the development of studies about areas with potential for oil exploration.
- Gas and Energy Regulation Commission (CREG): Is the sector regulator.
Current major initiatives and policies of the Government in relation to oil and natural gas development include: the expansion of refining facilities’ capacity to avoid the need to import refined products; the passing of new regulation to structure the natural gas market in a way that ensures supply shortages; new regulatory framework to foster the construction of LNG facilities; and new regulatory framework for the development of non-conventional hydrocarbons.
3.2 How are the State’s mineral rights to develop oil and natural gas reserves transferred to investors or companies (“participants”) (e.g. licence, concession, service contract, contractual rights under Production Sharing Agreement?) and what is the legal status of those rights or interests under domestic law?
Procedures and criteria applicable in selecting participants in the oil and gas industry vary depending on the annual selection procedure called the ‘Round’. Since 2007 and as a general rule, the National Hydrocarbons Agency carries out an annual bidding process to award oil and gas areas. Each Round has its own terms of reference including the bidding process schedule, the bidders’ participation requirements and the awarding criteria.
Once awarded, the participant enters into an exploration and production contract with the National Hydrocarbons Agency. E&P contracts are six years in length for exploration, and 24 years for production, plus a conditional extension of 10 years until the economic limit of the commercial field is reached. In non-conventional E&P contracts the production stage is of 30 years counted from the date when the ANH receives the marketability declaration of the field. Such contracts are deemed public procurement contracts subject to administrative law and granting the participants contractual rights and obligations.
3.3 If different authorisations are issued in respect of different stages of development (e.g., exploration appraisal or production arrangements), please specify those authorisations and briefly summarise the most important (standard) terms (such as term/duration, scope of rights, expenditure obligations).
E&P contracts cover the different stages of development and, therefore, no independent authorisations are required.
3.4 To what extent, if any, does the State have an ownership interest, or seek to participate, in the development of oil and natural gas reserves (whether as a matter of law or policy)?
Under E&P contracts, the Government is entitled to receive a royalty and an additional compensation for high prices, but it does not directly participate in the development of the block. Nevertheless, there are still some association contracts, which were in force prior to 2004 whereby the then State-owned oil and gas corporation – Ecopetrol – participated in the development. Currently, Ecopetrol is a mixed-economy corporation with public and private ownership and it remains a partner in certain association contracts that were entered into before 2004.
3.5 How does the State derive value from oil and natural gas development (e.g. royalty, share of production, taxes)?
The State derives value from oil and natural gas developments mainly in two ways: through royalties; and through special bonuses or premiums applicable to high prices. For contracts signed before 1994, royalties are 20 per cent. For discoveries made after such date, royalties vary from 8 to 25 per cent, depending on the size of each oilfield, as follows: for production equal or greater than 5,000 bbl/d, royalties are 8 per cent; and for production greater than 600,000 bbl/d they are 25 per cent. For production of unconventional hydrocarbons (offshore or onshore) there is a special discount of 40 per cent in the payment of royalties.
Besides the royalties, the E&P Contract requires the contractor to pay economic rights to the ANH for the subsoil use, for high prices and a percentage of the total production after royalties.
3.6 Are there any restrictions on the export of production?
In general terms, there are no restrictions to the export of oil production. In fact, Colombia is a net oil exporter. On the contrary, there are restrictions to the export of gas because of the need to ensure sufficiency in the supply of natural gas, particularly to residential and vehicle users. Pursuant to Decrees 2100 of 2011 and Decree 1372 of 2014, the exportation of natural gas is not subject to any restriction. Nevertheless, the same statute indicates that the Ministry of Mines and Energy may limit such freedom when supply for internal consumption is affected. On 30 July every year, the Ministry shall publish indicators for this purpose.
3.7 Are there any currency exchange restrictions, or restrictions on the transfer of funds derived from production out of the jurisdiction?
Colombia has a strict exchange control regulation. Transfer of funds derived from production out of the jurisdiction will require channelling through local financial intermediaries or through Central Bank-registered bank accounts abroad, if they derive from a transaction deemed as an exchange market transaction. Exchange market transactions are mainly: foreign investment and the corresponding transfer abroad of dividends deriving from such investment; imports and exports; and foreign indebtedness.
3.8 What restrictions (if any) apply to the transfer or disposal of oil and natural gas development rights or interests?
Government consent is required for a participant to transfer its rights and obligations under the E&P contract. According to the current E&P contract (article 65) and ANH Accord No. 004/2012, the contractor is allowed to transfer (totally or partially) its rights in the contract upon prior authorisation by the ANH. This request must inform about the identity of the assignee, its technical, legal, environmental and financial capacity, the rights which are going to be transferred and the details of the transaction. Within the next 60 business days, the ANH will decide upon the transfer. This authority may approve the transfer or deny it. If the transfer is the result of a merger, spin-off or transformation of the entity, it is also mandatory to request prior approval from the ANH. Accord No. 04 of 2012, published in May 2012, establishes stricter rules whereby any total or partial assignment of any right, obligation, participation interest or any other working interest in an E&P contract shall require prior authorisation by the ANH. Likewise, it includes specific provisions regarding change of control and beneficial ownership mainly establishing the need for prior written approval by the ANH for any such situation.
3.9 Are participants obliged to provide any security or guarantees in relation to oil and natural gas development?
Yes. The E&P Contract model regulates the granting of guarantees by the contracting party. The following is a summary of standard guarantees that participants must grant in relation to oil and natural gas development:
- Performance Bond: A guarantee to ensure the fulfilment and correct performance of all the obligations of each phase of the Exploration Period and the Subsequent Exploration Programme, if any, and other activities inherent to such obligations, as well as to guarantee the payment of the penalties imposed for the breach of the contract. The enforcement of the guarantee shall not exonerate the contractor from the payment of all the damages caused by the breach or the incorrect performance of the contract, and, therefore, such payments can be cumulative. Pursuant to section 39 of the E&P Contract, the guarantee must take the form of one or more standby letters of credit, which shall be unconditional, irrevocable and payable at sight, issued by a bank or financial institution legally established in Colombia.
Under section 39 of the E&P Contract model, the guarantee must remain in effect for the duration of the term (total or partial) of the phase of which obligations are being guaranteed, and, as a minimum, six (6) months more. In the event of extensions of the contract terms, or to complete the remaining term of a phase, the guarantees shall also be equally extended or replaced by others of the same amount, with a minimum term equal to the term of the extension or to the remaining term of the phase in progress and six (6) months more.
- Labour-Related Insurance: Under Section 40 of the E&P Contract model, and within fifteen (15) days from the start of the first phase, the contractor must establish an insurance policy guaranteeing the payment of salaries, benefits and indemnities and other labour obligations resulting from possible judgments derived from claims filed by the workers hired by the contractor in its capacity as sole and true employer of such workers, for the performance of the activities directly derived from this contract. Eight (8) days prior to the start of each subsequent phase of the Exploration Period, and of each calendar year during the Production Period, the contractor must renew the policy or present a new one to replace it. The term of duration of this policy shall not be less than the term of the corresponding phase and three (3) additional years, during the Exploration Period, and of four (4) years for each annual renewal during the Production Period and, in any event, up to three (3) years counted from the estimated date of termination of the contract. The insured amount shall be at least five per cent (5%) of the amount of the annual investment for each exploration phase, or ten per cent (10%) of the total estimated annual costs for each calendar year, at the election of the contractor, during the exploration period, or ten per cent (10%) of the total annual costs of the personnel directly allocated to the Production Area, during the Production Period, for the first year of effectiveness of the policy or for each subsequent year, to be adjusted in each renewal.
- Extracontractual Civil Liability: Within ten (10) days following the effective date, the Contractor must create and submit to the ANH an insurance policy to cover extracontractual civil liability, including protection against eventual sanctions, losses, claims, remedies or lawsuits by individuals or business entities, originated in extracontractual liability deriving from its acts, events or omissions, or those of its employees, agents, sub-contractors and representatives, as well as of the latter’s employees. This in order to keep the ANH harmless against any damages caused to the life or integrity of individuals, as well as against goods or public use property, of the State, of the Entity or of third parties, including those of any employee, agent, representative or sub-contractor of the ANH, third parties or business entities or of the Contractor. The term of such policy shall be equal to the term of the E&P Contract and three (3) additional years.
- Offer Compliance Bond: Covers compliance with the offer presented by the bidder during the Round that awarded the corresponding block.
3.10 Can rights to develop oil and natural gas reserves granted to a participant be pledged for security, or booked for accounting purposes under domestic law?
Yes, they can.
3.11 In addition to those rights/authorisations required to explore for and produce oil and natural gas, what other principal Government authorisations are required to develop oil and natural gas reserves (e.g. environmental, occupational health and safety) and from whom are these authorisations to be obtained?
The following authorisations are required to develop oil and natural gas reserves:
- Environmental Permits. The need to obtain an environmental permit is determined by the activities to be carried out, and by the possible impact on a specific renewable resource. The National Code of Natural Renewable Resources or Decree 2811 of 1974 provides that anyone willing to use natural resources must obtain an environmental permit, according to the resource to be used. Various environmental permits are listed as follows:
|Water Concession Permit||Water|
|Flow Occupation Permit||Water|
|Water Discharge Permit||Water|
|Forestry Permit||Forest Resource|
|Ban Lifting over Protected Species||Biodiversity|
Environmental Licence. The environmental licence is regulated by Act of Congress 1993 – 99, and Decree 2820 of 2010. It is defined as the authorisation granted by the State to develop an activity that according to the regulation might cause deterioration of natural renewable resources and the environment. Although it is called environmental licence, it must cover social and economic aspects as well.
The main instrument to evaluate whether an environmental licence may be granted is the Environmental Impact Analysis, defined as the technical document containing information on the project location, the biotic and abiotic elements, and the impact assessment.
The environmental licence comprises the terms and conditions to be attended in relation with the management and use of natural resources through the development of the activity. It also includes the obligations with regard to the prevention, mitigation, and compensation of the effects that the activity may involve.
According to the current regulation, the environmental licence is only required to develop the activities listed in Decree 2820 of 2010. In this case, the Project must have an environmental licence, given that article 8° from the aforementioned Decree states the following:
“Article 8°. Competence of the Ministry of Environment. The Ministry of Environment will grant or deny the environmental license for the following projects:
- In the hydrocarbon sector. (…)The production of hydrocarbons, included the perforation of any kind of well, the construction of facilities related to the activity, the complementary works, such as the internal fluid transportation through ducts, the internal storage, internal ways, and other associated infrastructure.”
The development requires an environmental licence for the production phase, in which case Decree 2820 of 2010 establishes that all permits, concessions and authorisations for the management and use of natural renewable resources will be included in the licence.
The obtaining of the environmental licence for all hydrocarbon activities determined in Decree 2820 of 2010 must nowadays be carried out before the National Authority for Environmental Licences.
In this sense, the development will not require an environmental licence for the exploration phase. This does not mean that the corresponding environmental permits, concessions and authorisations need not be obtained. Quite the opposite, the operator of the development is in charge of obtaining the corresponding permits according to their specific regulations. The procedure to be granted a permit must be carried out before the environmental authority with jurisdiction over the specific area.
(b) Occupational Health and Safety. HSE regulation for oil and gas-related facility operations is not compiled into one set of provisions but dispersed throughout a number of provisions in different laws, decrees and regulations.
Apart from the environmental regulations already mentioned in section (a) above, health and safety regulations are mainly enforced by the Ministry of Labour. There is a special regulation (Decree 2090 of 2003 and Decree 806 of 1998) protecting workers in the oil and gas industry. Such regulation includes rules on health and safety protection.
The bodies responsible for regulating HSE are the Ministry of the Environment and the Ministry of Mines and Energy.
Decree 4299 of 2005 and Decree 1333 of 2007 establish the requirements, obligations and penalties applicable to agents from the distribution chain of petroleum-derived liquid fuels (except LPG) in order to protect people and property and preserve the environment. The Decree, established through chapter 7, includes everything related to the overall penalties that may arise for agents in the chain, in case they violate its provisions. Penalties include warnings, fines, suspension of the service, permit cancellation and closure.
Also, Decree 4741/2005 aims to prevent the generation of hazardous waste, and regulate the management of generated waste, in order to protect human health and the environment. The Decree sets out the responsibilities and obligations to be met by natural or legal persons handling such substances, who should prepare a comprehensive management plan for hazardous waste.
All labour regulation established in Colombia’s Labour Code and related legislation also applies to the oil and gas industry. In summary, according to the referenced regulation, all employees must be registered in the national security system for mandatory health contributions and pension payments. They must also earn at least the minimum legal wage, be entitled to paid holiday, maternity and sick leave, extra payment for night shifts and work undertaken (between 10pm and 6am on weekdays and on Sunday and national holidays), and in case of work contract termination without just cause, all employees are entitled to an indemnification or severance payment according to their seniority as workers.
For the oil industry, there is a special regulation that has been valid for over 50 years. It requires oil companies with over 10 employees to hire foreign personnel in the following percentages: 10 per cent for their overall payroll; and up to 20 per cent for the executive or specialised and qualified personnel quotient. This information must be submitted to the Ministry of Mines and Energy. Should these limits be exceeded, employers must request a special authorisation from the Ministry of Social Protection, otherwise these companies may be subject to fines.
For operations that take place in secluded places, away from urban centres and devoid of facilities, such as oilfields, companies must cover their workers’ food, housing and sanitation needs, as well as provide medical assistance and hygiene measures.
Pursuant to article 8 of the Oil Statute, Colombian citizens shall have preference over foreign employees of the same category to be employed as superior employees in all the areas of oil companies, in the same conditions and with the same salaries as foreign employees, provided their competence is not inferior. Whenever technical competence is not necessary or if such competence is the same between a Colombian worker and a foreign worker, Colombian workers shall be preferred over foreign workers.
Likewise, pursuant to article 18 of Law 10/1961, employers in the oil industry must pay their Colombian labour force at least 70 per cent of the total amount of their qualified or executive payroll and at least 80 per cent of the payroll value of ordinary workers.
(c) Community Consultation. Colombia is the home of approximately 1,063,448 indigenous people living in 15 ethnic reserves. Reserves are legal, socio-political compounds formed by indigenous territories owned by the community and governed by special autonomous statutes.
Article 330 of the Colombian Constitution and article 6 of the International Labour Organization Convention 169 of 1989, establish a compulsory prior consultation with ethnic communities concerning any decision-making process for the exploitation of natural resources in their territories or any other measure that may affect them.
Article 15 (2) of Law 21 of 1991 states that:
“In case the State is the owner of the minerals or resources in the subsoil, or if it has any rights over existing resources in the ground, the government must establish or maintain procedures for consultation to interested people, in order to determine if the interests of such people may be jeopardized and to what extent, before carrying out or authorizing any prospection or production program concerning such resources.”
The prior consultation procedure requires a certificate issued by the Interior Ministry on whether ethnic communities exist within the project area or its influence area prior to the environmental licence application, and article 3 of Decree 1320 of 1998 that refers to the identification of ethnic communities.
The Government has drafted a new bill to introduce a new prior consultation procedure. The draft bill includes the following main changes:
- It regulates prior consultation with ethnic communities but makes it clear that an agreement is not necessarily required and that such consultation does not grant communities a veto right. When an agreement is not reached, the authority shall decide without any arbitrariness or authoritarianism. There is however a veto right in the following cases:
- When the administrative or legal act or project (“the Project”) would result in the loss of their traditional land, the eviction, migration or termination of resources required for their physical and cultural subsistence.
- When the Project involves the destruction or contamination of their traditional environment thus generating a high social and cultural impact putting at risk their existence.
- The consultation four-stage procedure shall include: (i) the call stage; (ii) opening and official starting of the consultation procedure; (iii) impact workshop and adoption of measures to handle such impact; and (iv) prior consultation definitive minutes. The parties involved may not make any payment or compensation during prior consultation.
- The process shall take three (3) months extendible for a further two-month period.
3.12 Is there any legislation or framework relating to the abandonment or decommissioning of physical structures used in oil and natural gas development? If so, what are the principal features/requirements of the legislation?
Abandonment and decommissioning is regulated by articles 19, 56 and 61 of the model E&P contract. Abandonment consists of the closing of wells, removal of structures and the cleaning of all areas where works of exploration, evaluation and production took place according to Colombian law. One of the main obligations of the contractor is to constitute a fund to guarantee the financial obligations related to all decommissioning works. Legally, decommissioning implies the restitution to the ANH of all E&P areas when the production period is over. The amount of this guarantee is defined under the E&P contract according to a formula that integrates the cumulative production, the volume of proved reserves and the estimated costs of all decommissioning works.
3.13 Is there any legislation or framework relating to gas storage? If so, what are the principle features/requirements of the legislation?
Yes. Decree 2100 was passed on 15 June 2011 to regulate trading of natural gas with the object of ensuring long-term supply. Pursuant to article 19 of Decree 2100, the Ministry of Mines and Energy and the National Hydrocarbons Agency have the duty to jointly evaluate the possibility of using hydrocarbon fields for the purposes of underground storage of natural gas. So far this is still being studied and no specific regulatory framework exists for the operation of such facilities. The Gas Transport Regulation (CREG Resolution 071 of 1999 as amended by CREG Resolution 102 of 2001, CREG Resolution 014 of 2003, CREG Resolution 084 de 2000 and CREG Resolution 054 de 2007) also included parties carrying out storage activities as agents in the system.
Storage services may be rendered both by transport agents and third parties, based on the principles of free access and non-discrimination. However, transport agents may not store gas for trading purposes.
4 Import / Export of Natural Gas (including LNG)
4.1 Outline any regulatory requirements, or specific terms, limitations or rules applying in respect of cross-border sales or deliveries of natural gas (including LNG).
In June 2013, CREG passed Resolution 062 of 2013 (as amended by Resolution 152-2013) establishing new regulations regarding cross-border sales of natural gas used for electricity generation. The aim of the regulation is to ensure supply in that sector.
In this sense, the general rule is that cross-border sales or deliveries of natural gas are not restricted and are subject to bilateral negotiations by the parties involved. Nevertheless, restrictions may apply to the importation or exportation of natural gas when such a resource is required to supply local demand and avoid an eventual suspension of electricity generation due to drought periods. The reason for this is that Colombia is highly dependent on hydraulic resources for energy generation.
5 Import / Export of Oil
5.1 Outline any regulatory requirements, or specific terms, limitations or rules applying in respect of cross-border sales or deliveries of oil and oil products.
Regulatory requirements for cross-border sales or deliveries of oil and oil products are established by the Ministry of Mines and Energy. Exports require a permit by the entity and imports require a permit from the Ministry of Commerce, Industry and Tourism.
6.1 Outline broadly the ownership, organisational and regulatory framework in relation to transportation pipelines and associated infrastructure (such as natural gas processing and storage facilities).
CREG Resolution 071 of 1999 (as amended) dictates the technical regulation for transport, while the general regulatory framework for the activity in Colombia is found in CREG Resolution 057 of 1996. The transportation pipelines and associated infrastructure may be private or public. The National Transport System has been defined as the group of gas pipelines located in the national territory that link gas production facilities around the country with city gates, distribution systems, non-regulated users, international interconnections and storage systems.
The Government agencies involved are: the Ministry of Mines and Energy establishes policies and guidelines concerning the energy policy; the Mining and Energy Planning Unit (UPME from its Spanish name) is in charge of planning the use of resources; the Energy and Gas Regulation Commission (CREG) is the regulator; the National Environmental Licences Authority (ANLA) is in charge of granting environmental licences for projects; the Superintendence of Public Utilities (SSPD from its Spanish name) is in charge of monitoring the behaviour of corporations vis-à-vis users; and the Superintendence of Industry and Commerce (SIC) is the national antitrust authority.
6.2 What Governmental authorisations (including any applicable environmental authorisations) are required to construct and operate oil and natural gas transportation pipelines and associated infrastructure?
Two thousand (2,000) km of natural gas transportation pipelines were built in 1993 by Ecopetrol in the areas of Guajira, the centre and southwest areas of the country and the eastern basins. In 1997, Ecopetrol was divided into two entities thus forming ECOGAS (the national gas corporation), which was transformed in the year 2006 into Transportadora de Gas del Interior (TGI S.A. E.S.P.)
Concession for exclusive distribution zones were granted between 1997 and 1998 to expand service coverage in the states of Quindío, Caldas, Risaralda, Valle and Tolima, which in 2011 amounted to 17 per cent of the total number of users connected to the natural gas distribution network.
For the operation of natural gas transportation pipelines, requirements are defined in article 1 of CREG Resolution 041 of 1998, which amended article 29 of Resolution 057-1996.
6.3 In general, how does an entity obtain the necessary land (or other) rights to construct oil and natural gas transportation pipelines or associated infrastructure? Do Government authorities have any powers of compulsory acquisition to facilitate land access?
Companies obtain a permit to build transport infrastructure through easements regulated by Law 1274 of 2009. Pursuant to Law 1274, the oil and gas industry is deemed of a public utility nature and, therefore, land must bear legal easements that are necessary to access them and to carry out oil and gas exploration, production and transportation activities.
Easements comprise the right to build the necessary infrastructure and to install all the works and services required to carry out the activity.
Initially, easements are negotiated and agreed upon between the relevant parties involved (oil and gas company with land owner). If such agreement is not possible, the easement is declared and imposed by a local municipality judge of the area where the land is located.
6.4 How is access to oil and natural gas transportation pipelines and associated infrastructure organised?
Pursuant to the transport regulation (CREG Resolution 071 of 1999), transport agents must guarantee access to producers and traders, to distributors, to non-regulated and regulated users, and in general, to any agent requesting access to the Transport System and to transport services, in a non-discriminatory manner, allowing access to gas pipelines, either of their own or under their control.
If after 15 days counted as from the date of receipt of an access application, the transport agent has not replied or if, after a month has lapsed from the same date, no agreement has been reached between the transport agent and the party requesting access, CREG may order such access.
6.5 To what degree are oil and natural gas transportation pipelines integrated or interconnected, and how is co-operation between different transportation systems established and regulated?
There are nine natural gas transport systems operating in coordination. Such systems form the National Transport System (SNT from its Spanish name). Upon CREG’s request, the Natural Gas Operation National Council (CNOG from its Spanish name), may issue Operative Agreements and Protocols required to establish the procedures, definitions and basic parameters that shall govern: (i) the STN operation; (ii) maintenance programmes and/or natural gas supply and transport infrastructure intervention, when they entail the suspension or put at risk the continuity of the service provision; and (iii) coordination of agents using the SNT whenever severe supply restrictions or emergency situations arise.
The companies that currently operate such systems are: Transportadora de Gas Internacional – TGI; Promigas; Promotora de Gases del Sur – Progasur; Transportadora de Metano – Transmetano; Transportadora Colombiana de Gas – Transcogas; Sociedad Transportadora de Gas del Oriente – Transoriente; and Transportadora Gasoducto del Tolima – Transgastol; Transoccidente; Coinobras.
Most of the systems are connected to the interior central system operated by Transportadora de Gas Internacional.
6.6 Outline any third-party access regime/rights in respect of oil and natural gas transportation and associated infrastructure. For example, can the regulator or a new customer wishing to transport oil or natural gas compel or require the operator/owner of an oil or natural gas transportation pipeline or associated infrastructure to grant capacity or expand its facilities in order to accommodate the new customer? If so, how are the costs (including costs of interconnection, capacity reservation or facility expansions) allocated?
Pursuant to the transport regulation (CREG Resolution 071 of 1999), transport agents must guarantee access to producers and traders, to distributors, to non-regulated and regulated users, and in general, to any agent requesting access to the Transport System and to transport services, in a non-discriminatory manner, allowing access to gas pipelines, either of their own or under their control.
If, after 15 days counted from the date of receipt of an access application, the transport agent has not replied or if, after a month has lapsed from the same date, no agreement has been reached between the transport agent and the party requesting access, CREG may order such access.
To guarantee access to all users, transport agents must offer different types of contracts. The transport agent may not discriminate between clients having similar contractual terms and conditions.
6.7 Are parties free to agree the terms upon which oil or natural gas is to be transported or are the terms (including costs/tariffs which may be charged) regulated?
Transport charges are regulated. CREG establishes formulas both for charging for transport and network interconnection. CREG may impose caps and minimum charges. Currently, CREG Resolution 79 of 2011 establishes the general criteria to determine the natural gas transport service compensation, the National Transport System general charges scheme and the criteria for network expansion. It applies to all agents rendering transport services and to users of the National Transport System.
7 Gas Transmission / Distribution
7.1 Outline broadly the ownership, organisational and regulatory framework in relation to the natural gas transmission/distribution network.
The regulatory framework is found in CREG Resolution 057 of 1996. The technical code for gas distribution is governed by CREG Resolution 067 of 1995, and the transport regulation by CREG resolution 071 of 1999. Ownership of distribution and transportation networks may be public or private. The Ministry of Mines and Energy formulates the sector policy while the Energy and Regulation Commission (CREG) is the regulator and the Mining and Energy Planning Unit (UPME) is the body in charge of sector planning. The Public Utilities Superintendence monitors the relations between users and the Superintendence of Industry and Commerce (SIC) is the antitrust agency.
7.2 What Governmental authorisations (including any applicable environmental authorisations) are required to operate a distribution network?
Pursuant to Law 142 of 1994, the following agents may be natural gas distributors:
- Public utility corporations.
- Individuals or business entities who, directly or as a supplement to their main activity, produce goods or services of a public utility corporation.
- Municipalities when they render public utility services, either directly or through their central administration.
Pursuant to CREG Resolution 57 of 1996, distribution does not require a licence but any party intending to distribute natural gas must inform CREG about the start of its activities together with the filing of the following information:
- Entity’s by-laws.
- Names of the shareholders of over 10 per cent of the stock.
- Financial statements.
- Description of their target market, main assets and permits that it has or is in process of acquiring and, in the case of distributors, the model contract that they pretend to use.
The construction of gas distribution pipelines requires an environmental licence and must follow the guidelines defined by the Environmental Ministry (“Environmental Guide for Natural Gas Distribution”).
7.3 How is access to the natural gas distribution network organised?
One of the main principles of the Colombian regulatory framework is free access to the network. Therefore, the regulation covers any network capacity, access or coverage expansion increase. For example, CREG Resolution 57 of 1996 indicates that existing or future pipeline network transport agents must allow new connections and the construction or operation of new gas pipelines, provided the technical codes and other CREG regulation is complied with. The transport agent also has the right to inspect whether the connection complies with such requirements.
Regarding distribution, CREG Resolution 57 of 1996 states that distributors must allow access to their network, to any producer, trader or major consumer in exchange for payment of the corresponding charges, provided they comply with the same applicable legal conditions and codes.
7.4 Can the regulator require a distributor to grant capacity or expand its system in order to accommodate new customers?
Yes. Distributors are required to expand their system provided they do so in competitive conditions and with a minimum cost, pursuant to the five-year costs and plans defined by article 14, sections 3 and 12 of Law 142 of 1994.
For the purposes of system expansion, distributors shall agree with CREG five-year plans concerning the envisaged investment, so that they are accounted for at the time of defining regulation formulas for the corresponding distributor – thus making sure that such investment is recouped through charges. Likewise, they must inform UPME about such plans.
Distributors who have contracted with the National Ministry of Energy and Mines shall keep the obligations agreed in such contracts to carry out expansion plans, subject to the agreed schedule and to the regulation formulas issued by the CREG.
7.5 What fees are charged for accessing the distribution network, and are these fees regulated?
Average distribution charges are regulated by CREG, through analysis involving distribution charges, investment and administration, operation and maintenance expenses. CREG Resolution 011 of 2003 defines the general criteria to remunerate the distribution and trading activity and the general calculation formulas.
7.6 Are there any restrictions or limitations in relation to acquiring an interest in a gas utility, or the transfer of assets forming part of the distribution network (whether directly or indirectly)?
There are limits and restrictions to horizontal and vertical participation in the natural gas market. Pursuant to CREG Resolution 057 of 1996, natural gas transport agents may not directly produce, trade or distribute natural gas or have any economic interest in companies that have as their object the performance of such activities.
Likewise, companies selling, trading or distributing natural gas may not transport or have any economic interest in a transport company. Producers and/or transport agents may not directly generate electricity from natural gas but may own up to 25 per cent of the stock of a corporation developing such activity. There is an exception to this rule for transport agents who participate in electricity generation from natural gas, in facilities located outside their operation zone.
A natural gas transport agent may not have an economic interest in natural gas-based electricity generation companies.
Producers and distributors may also be traders.
Pursuant to CREG Resolution 071 of 1998, as from 1 January 2015, distribution agents may not service, either directly or indirectly, over 30 per cent of market users. Regarding trade, no one may have over 25 per cent of the volume traded in the final users’ market, whether regulated or non-regulated, excluding natural gas traded for electricity generation, for raw material for the petrochemical industry, and for the producer’s own consumption.
Natural gas transportation is independent from the production, trading and distribution activities. Therefore, transport contracts and their prices, charges and tariffs are established independently from purchase or distribution terms and conditions.
8 Natural Gas Trading
8.1 Outline broadly the ownership, organisational and regulatory framework in relation to natural gas trading. Please include details of current major initiatives or policies of the Government or regulator (if any) relating to natural gas trading.
Natural gas trading is organised as follows:
The National Hydrocarbons Agency (ANH from its Spanish name) is in charge of contracting exploration and production; the Ministry of Mines and Energy establishes policies and guidelines concerning the energy policy; the Mining and Energy Planning Unit (UPME from its Spanish name) is in charge of planning the use of resources; the Energy and Gas Regulation Commission (CREG) is the regulator; the National Environmental Licences Authority (ANLA) is in charge of granting environmental licences for projects; the Superintendence of Public Utilities (SSPD from its Spanish name) is in charge of monitoring the behaviour of corporations vis-à-vis users; and the Superintendence of Industry and Commerce (SIC) is the national antitrust authority.
The following is the main regulatory framework regarding the natural gas sector in Colombia:
- CREG Resolution 067 of 1995 – established the distribution code.
- CREG Resolution 108 of 1997 – established users’ rights regarding gas distribution networks.
- CREG Resolution 41 of 1998 – amended article 29 Resolution 057 of 1996.
- CREG Resolution 071 of 1999 – gas transport regulation.
- CREG Resolution 123 of 2013 – gas trading regulation.
- CREG Resolution 152 of 2013 – new regulation regarding cross-border sales of natural gas used for electricity generation.
- CREG Resolutions 057 of 1996, 071 of 1998, 112 of 2007 and 089 of 2013 regarding vertical and horizontal integration limits. CREG Resolution 123 de 2013. New requirements were introduced to be a natural gas trader. Traders do not require a licence to operate but they must inform the following entities about the start of their activity: SSPD; CREG; and the Ministry of Energy and Mines’ Solidarity Fund for Subsidies and Income Re-distribution.
8.2 What range of natural gas commodities can be traded? For example, can only “bundled” products (i.e., the natural gas commodity and the distribution thereof) be traded?
Natural gas commodities can be freely traded without needing to be bundled. Currently, Colombia commercialises natural gas for domestic and industrial use, and natural gas for vehicles (compressed).
9 Liquefied Natural Gas
9.1 Outline broadly the ownership, organisational and regulatory framework in relation to LNG facilities.
So far, the country does not have any operating LNG facility. In March 2011, the Energy and Gas Commission (CREG) commissioned an international consultant to carry out a study to examine the potential for imports of LNG into the country. The study examined the infrastructure requirements, possible commercial structures for the infrastructure required for LNG imports and purchasing of LNG during the period of El Niño (a period of particular drought in Colombia).
Pacific Stratus Energy (PSE) Colombia has contracted Exmar to build, operate, and maintain a floating liquefaction regasification and storage unit (FLRSU) for the Colombian Caribbean coast. EXMAR has recently signed a Floating Liquefaction Regasification and Storage (FLSRU) contract for 15 years with Pacific Rubiales in Colombia. It is anticipated that the FLRSU will be delivered in Colombia at the end of 2015. According to Exmar, this will be the world’s first of such unit, with a storage capacity of 14,000 cubic metres of LNG.
9.2 What Governmental authorisations are required to construct and operate LNG facilities?
CREG is, therefore, examining the possibility of LNG imports so imported gas can be supplied to the power generators in place of them having to enter, take or pay commitments with the gas producers. As part of this initiative, CREG issued a Resolution to the industry in December 2010, seeking the industry’s views on the possibility of LNG imports to support the Firm Energy Obligation Reliability Charge. The Resolution proposes a four-stage response, so that by June 2012 an investment decision can be made to proceed with the necessary infrastructure and firm LNG supply contracts. In parallel to this market approach, CREG has commissioned a study to give information to the industry in Colombia on how LNG can be imported and possible industry structures (i.e. the way that industry can be set up).
9.3 Is there any regulation of the price or terms of service in the LNG sector?
CREG Resolution 180 of 2009 establishes the pricing formula to be applied by the companies rendering the service in order to determine the price.
CREG has established a “surveilled freedom” regime, as envisaged in article 88 of Law 142 of 1994. Through such regime, agents are free to determine the prices that they shall apply for their services, but must fully inform not only final users but also control authorities, before they become effective. This is the reason why pricing may vary monthly, pursuant to each company’s criteria, given that they will need to fix efficient prices in order to be competitive in the market.
9.4 Outline any third-party access regime/rights in respect of LNG Facilities.
This is still not regulated in Colombia.
10 Downstream Oil
10.1 Outline broadly the regulatory framework in relation to the downstream oil sector.
The regulatory framework in relation to the downstream oil sector can be found in Decree 4299 of 2005 and Decree 1717 of 2008. The decrees establish the requirements, obligations and sanctioning regime, applicable to all agents of the downstream oil sector. Such agents include players who refine, import, store, distribute and transport oil downstream as well as major consumers.
The above-mentioned activities are deemed public utilities and, therefore, the downstream oil agents must render services in a regular and efficient manner.
10.2 Outline broadly the ownership, organisation and regulatory framework in relation to oil trading.
Pursuant to Decree 4299 of 2005 (article 3) the Ministry of Mines and Energy has the power to regulate, control and monitor activities regarding oil trading, and in particular, refining, imports, storage, distribution and transport of any oil-derived fuel.
Therefore, each of the above-mentioned activities must be previously authorised by the Ministry of Mines and Energy.
There are no restrictions to ownership by private parties involved in oil trading.
11.1 Which Governmental authority or authorities are responsible for the regulation of competition aspects, or anti-competitive practices, in the oil and natural gas sector?
The Superintendence of Industry and Commerce (SIC) is the only national competition authority in Colombia.
11.2 To what criteria does the regulator have regard in determining whether conduct is anti-competitive?
Article 52 of Decree 2153/92 (as amended by article155 of Decree 019/2012) establishes the way the SIC determines whether there has been a violation of the rules to promote competition or restrict trade practices. Pursuant to this, the SIC shall start an action or follow a request from a third party and forward a preliminary inquiry. Its outcome shall determine the need for an investigation.
The basic legal standard in determining whether a conduct is anti-competitive consists of the prohibition of “agreements or understandings that have as their object the limitation of production, supply, distribution, or consumption of primary resources, products, merchandises, or services of domestic or foreign origin, and in general all types of practices, procedures or systems tending to limit open competition and to maintain or determine unfair prices”.
An agreement may be ruled illegal only upon verification of anticompetitive effects, regardless of the intent of the violators. In this case the defence will rely on denying the anticompetitive effects of the agreement on free competition, consumer welfare, and economic efficiency. In short, the prohibition in the 1992 Decree of cartels that “have as their object or effect” the fixing of prices, the sharing of markets, the subordination of supply to acceptance of additional obligations, etc., not only makes it unlawful to attempt restrictive practices but also punishes conduct for its anticompetitive effects, regardless of the motives or interests underlying that conduct.
The law does not explicitly spell out the criteria for illegality per se or the rule of reason. There is some dispute over this point between local practitioners, since the traditional concepts of per se versus the rule of reason are not sufficient under the administrative responsibility regime in Colombian law.
While the Colombian legislation sets no thresholds for market shares or thresholds of any other kind for the purposes of enforcing competition rules, the SIC may abstain from taking action in cases deemed insignificant, pursuant to the 1992 Decree, whereby the SIC is only required to pursue antitrust complaints that are “significant” or “important”. This rule may, in effect, involve a de minimis criterion that avoids extending the presumption of articles 47 and 48 (amended by article 16 of Law 590 of 2000), to cases that have no significant impact on market competition because of low market shares, for example.
Finally, it should be noted that in the Colombian antitrust regime, in line with international practice, an investigation could be cut short if the offender and the competition authority reach a settlement. Under Colombian law, the settlement procedure is known as an “offer of guarantees”. The authority may order an investigation to be closed “when in its judgment the presumed offender offers sufficient guarantees that it will suspend or modify the conduct for which it is being investigated”. This does not imply that the defendant is entering a confession or admitting that its conduct was illegal. For its part, the authority takes no position on the substance of the case and imposes no penalties.
The Public Utilities Statute (Law 142 of 1994) has also granted certain powers to the sector regulator to promote competition. Such powers include (Law 142 of 1994, articles 73.13, 73.14, 73.21, 73.25 and 74.1):
- Ordering that a public utility corporation carries out a spin-off procedure in the following cases:
- Abuse of dominant position to restrict competition in the market when such competition should be possible.
- Granting subsidies in the provision of services that have high levels of competition by using the product of other services that lack competition.
- In general, any restrictive trade practice.
- Ordering the merger of corporations when studies demonstrate that such course of action is necessary to extend coverage and reduce costs to users.
11.3 What power or authority does the regulator have to preclude or take action in relation to anti-competitive practices?
The regulator does not have any power or authority to preclude or take action in relation to anti-competitive practices. Such power is vested only on the national competition authority, the Superintendence of Industry and Commerce (SIC).
11.4 Does the regulator (or any other Government authority) have the power to approve/disapprove mergers or other changes in control over businesses in the oil and natural gas sector, or proposed acquisitions of development assets, transportation or associated infrastructure or distribution assets? If so, what criteria and procedures are applied? How long does it typically take to obtain a decision approving or disapproving the transaction?
Colombia has a central antitrust authority, the Superintendence of Industry and Commerce (SIC), in charge of approving/disapproving mergers or other changes in control over businesses or proposed acquisitions in practically all sectors of the economy, including the oil and natural gas sector. Merger control is carried out ex ante and applicable criteria and procedures vary depending on whether the corresponding thresholds are met. For instance, only the transactions meeting the following thresholds are subject to clearance by the SIC:
- the parties involved do business in the same activity or in different levels of the same distribution chain; or
- jointly or individually considered, they report operating income or assets totalling over 100,000 times the monthly legal minimum wage (year 2014 figure equivalent to COP$ 61,600,000,000 – approx. USD$ 30,800,000).
Parties meeting the above thresholds but having a market share of less than 20 per cent do not require clearance by the SIC, but must inform the agency of the proposed transaction.
If the parties’ market share exceeds 20 per cent, the procedure includes a pre-evaluation stage where the SIC studies the transaction and determines whether to continue with its analysis. If so, an evaluation period starts including a newspaper publication of the transaction summary and the right that the sector agency (in the case of the natural gas and oil sector, the Ministry of Mines and Energy or the Energy and Gas Regulation Commission – CREG) has to provide its opinion on the transaction.
The SIC should not object to a merger or acquisition if the parties demonstrate that the beneficial effects of the transaction exceed the potential negative impact on competition and that such effects cannot be achieved by other means.
Efficiency is not one of the criteria to decide whether to object to the operation or not. This is an exception. This implies the knowledge that the transaction will generate an undue restriction of competition.
12 Foreign Investment and International Obligations
12.1 Are there any special requirements or limitations on acquisitions of interests in the natural gas sector (whether development, transportation or associated infrastructure, distribution or other) by foreign companies?
Foreign companies must meet the same legal requirements as domestic companies and they are treated equally under the national treatment principle. Nevertheless, when acquiring interests in the natural gas and in general in any natural resources-related sector, foreign companies must establish a local vehicle. Such requirement allows the State to make sure that the foreign company has a physical domicile in Colombia and a local representative to be held liable in case of default or damages.
12.2 To what extent is regulatory policy in respect of the oil and natural gas sector influenced or affected by international treaties or other multinational arrangements?
The Colombian oil and gas regulation is highly influenced by best international practices, especially concerning technical regulation. For example, the technical regulation passed by the Ministry of Mines and Energy (Resolution 180742 of 2012 and Decree 3004 of 2013) regarding exploration and production in non-conventional fields.
Pursuant to article 3 of the Resolution 180742 of 2012, all sector activities must be carried out under national and international standards and rules and, in particular, those recommended by the AGA, API, ASTM, NFPA, NTC, Icontec, RETIE or any other used in the oil industry.
Also, pursuant to Article 3 of Decree 3004 of 2013, in order to issue regulation on non-conventional fields, the Ministry of Mines and Energy must first give notice to the World Trade Organization – WTO – as established in the Agreement on Technical Obstacles to Trade – TOT.
The oil sector is also influenced by international contract models and practices such as the joint operating agreement published by the Association of International Petroleum Negotiators (AIPN), which is broadly used among industry players in Colombia.
13 Dispute Resolution
13.1 Provide a brief overview of compulsory dispute resolution procedures (statutory or otherwise) applying to the oil and natural gas sector (if any), including procedures applying in the context of disputes between the applicable Government authority/regulator and: participants in relation to oil and natural gas development; transportation pipeline and associated infrastructure owners or users in relation to the transportation, processing or storage of natural gas; downstream oil infrastructure owners or users; and distribution network owners or users in relation to the distribution/transmission of natural gas.
In general terms, the natural gas and oil sector does not have special dispute resolution procedures but is governed by the dispute resolution statutes applicable to all sectors of the economy. The Civil Procedure Statute governs dispute resolution at the judicial level while the Contentious Administrative Code refers to disputes involving Government agencies and State-owned entities. The Colombian constitution and legal mechanisms recognise domestic and international arbitration. Arbitrators are considered to be temporary judges, arbitration proceedings are seen as a method of justice administration and awards are deemed to be judicial decisions. Arbitration is commonly used to resolve disputes in the natural gas and oil sector, particularly those related to international business transactions. While local players tend to prefer arbitration by the Conciliation and Arbitration Centre of the Chamber of Commerce of Bogotá, international arbitration shaped under international contract forms (such as the AIPN JOA model contract) is common when involving international parties.
Other forms of dispute resolution include mediation and conciliation, which are forms of settlement negotiation facilitated by a neutral third party, and non-binding resolution by experts, among others.
13.2 Is Colombia a signatory to, and has it duly ratified into domestic legislation: the New York Convention on the Recognition and Enforcement of Foreign Arbitral Awards; and/or the Convention on the Settlement of Investment Disputes between States and Nationals of Other States (“ICSID”)?
Colombia is a signatory to, and has duly ratified into domestic legislation, the New York Convention on the Recognition and Enforcement of Foreign Arbitral awards, and the Convention on the Settlement of Investment Disputes between States and Nationals of Other States (ICSID). So far, Colombia has never been a party to an ICSID dispute.
13.3 Is there any special difficulty (whether as a matter of law or practice) in litigating, or seeking to enforce judgments or awards, against Government authorities or State organs (including any immunity)?
Not particularly. The Contentious-Administrative Statute and the Statute of Contentious-Administrative Proceedings establish the mechanisms to litigate with Government authorities and State organs.
13.4 Have there been instances in the oil and natural gas sector when foreign corporations have successfully obtained judgments or awards against Government authorities or State organs pursuant to litigation before domestic courts?
In the oil sector, a number of lawsuits have been presented against the former State-owned oil corporation, Ecopetrol, as a party to a number of association agreements with private parties.
Both in the gas and oil sectors, it is frequent to see lawsuits concerning land easements in the construction of transport infrastructure.
14.1 Please provide, in no more than 300 words, a summary of any new cases, trends and developments in Oil and Gas Regulation Law in Colombia.
Currently, one of the main challenges of the Colombian oil and gas sector is shaping its regulation for the exploration and production of non-conventional hydrocarbons. In late 2013 and 2014, new regulations have been issued (Decree 3004 of 2013 and Agreement No. 3 of March 26, 2014 issued by the ANH) to cover matters such as: well integrity; hydraulic stimulation; water injection; technical matters associated to exploration and production, among other technical specifications; and terms and conditions for non-conventional hydrocarbons’ E&P contracts.
In December 2013, the ANH launched its 2014 Round, offering not only conventional blocks but also 18 non-conventional blocks.
As far as the gas sector is concerned, new regulation continues to be passed in order to adjust it to the changing market circumstances. The latest regulation, Decree 1372 of 2014, takes measures to foster production and exports of natural gas through the creation of new markets.
* Global Legal Group, Questions For the International Comparative Legal Guide To: Oil & Gas Regulation 2015.