During the past 10 years, Colombia has emerged as one of Latin America’s leading hydrocarbons producers. With just over 1m barrels per day (bpd) of production in 2013, Colombia trailed only Mexico, Venezuela and Brazil in the region. On a relative basis, natural gas production, at 1.2bn cu feet (bcf) per day, is more modest, but has grown every year but one since 2003. The primary problem the industry faces is limited reserves. The modern Colombian oil industry got its start in the 1970s following the discovery of one of the country’s biggest oil and gas fields, Chuchupa, in the shallow waters off the Guajira Peninsula. A decade later, the Rubiales and Caño Limón fields were also discovered.
But since then few important discoveries have been made. The result is that today Colombia has one of the lowest reserves-to-production ratios (R/P) among the world’s major oil producers. To address low reserves, the industry has begun exploring new unconventional hydrocarbons resources such as shale oil and gas, offshore oil and gas, and coal-bed methane (CBM), all of which have the potential to become significant sources of new revenue for the industry. Other challenges faced by the industry include security risks posed by guerrilla groups and inadequate transport infrastructure for oil and gas.
On balance, oil companies find Colombia to be an attractive target for investment and a desirable place to conduct business. Successive governments, including that of recently re-elected President Juan Manuel Santos, have regarded the extractive industries as essential to the economy and have courted investment. Royalties are competitive with regional and global peers, although industry executives voice some complaints about aspects of the regulatory regime, in general they agree that conditions are favourable and that regulations are clear and consistently applied. Perhaps to an even greater extent than the oil and gas sector, Colombia’s electricity industry has become a point of reference in Latin America. Its power plants supply virtually all of the country’s electricity needs and even create a surplus that can be exported to neighbouring countries.
All in-ground oil and gas is the property of the state, which, until recently, maintained a monopoly on the exploitation of these resources. Until 2003, state-owned oil and gas company Ecopetrol controlled all exploration and production (E&P) of hydrocarbon resources. This arrangement was functional for Colombia for decades, as yields at Rubiales, Caño Limón and other fields remained high. But, after Ecopetrol’s production reached 830,000 bpd in 1999, it began falling as the output of these fields and others naturally declined. Exploration had also been less successful than desired, as no major discoveries of reserves had been made since the early 1980s.
In 2003 the government of former President Álvaro Uribe Vélez, an advocate of free markets, implemented reforms that opened up the hydrocarbons sector. Ecopetrol, which had previously acted as an operator and a government agency, was relieved of its administrative and regulatory responsibilities. The government also allowed it to operate more like a private hydrocarbons major, permitting the company to borrow money and increase its exposure to capital markets. Furthermore, private companies, both domestic and foreign, were for the first time allowed to own up to 100% stakes in oil and gas ventures and compete with Ecopetrol. In the past, private companies had been obliged to form partnerships with Ecopetrol in order to operate.
More recently, privatisation has taken another major step forward. Beginning with an initial public offering in 2007, the state has sold slightly more than 10% of its stake in Ecopetrol to private investors to boost capital expenditures. The results of the opening up of the market and the restructuring of the state oil firm have been favourable. Between 2003 and 2013 Colombia’s oil production nearly doubled from 541,000 bpd to 1m bpd.
Opening Up To New Players
Remarkably, the vast majority of this growth has come from increases in Ecopetrol’s production, not only from the added production of newly arrived private companies. Today, Ecopetrol remains the dominant player in the Colombian market, typically accounting for almost 80% of oil production. In 2013 the figure stood at 78% with 788,000 bpd of production, a marked increased from the roughly half a million barrels it produced daily the year before liberalisation.
The opening up of Colombia’s hydrocarbons industry has broadly been considered a success and a model of liberalisation for other countries. It may be noted that the energy reforms being implemented in Mexico in 2014 and 2015, which will substantially open up that country’s hydrocarbons sector, are aimed at effecting changes similar to those Colombia has experienced. They should lead to an increase in production due to the investment of private companies and growth in the state-owned oil company – Pemex in Mexico’s case – owing to increased competition and fewer bureaucratic and fiscal burdens.
As Ecopetrol increased its production by double digits annually, it became a darling among investors. Its shares are listed on the New York Stock Exchange and rocketed from $18.40 at the end of 2008 to $62.18 at the end of 2012, an increase of 238% during a period when the Dow Jones Industrial Average (DJIA) gained 49%. In January 2013 Ecopetrol’s market capitalisation surpassed that of Petróle Brasileiro, the Brazilian state oil company that produces three times as much oil as its Colombian counterpart.
However, since then the stock has suffered significantly, falling to $36.51 at the end of May 2014, while the DJIA has continued to increase. Poor stock performance has been explained by a shift in focus among investors away from Ecopetrol’s impressive production growth and toward Colombia’s dwindling oil and gas reserves. Chris Spaulding, the CEO of Talisman Energy, told OBG, “The major issues hindering exploration are the delays in receiving permits and a drop in the success ratios. Consequently, the financial markets have shown concern and have reduced their confidence in companies operating in Colombia. However, the national efforts to increase exploration, starting with the 2014 oil round, should help to improve this situation.”
While the 2003 reforms have succeeded in boosting production, ushering in a period that many have referred to as a Colombian oil boom, they have so far done little to address the lack of significant hydrocarbons discoveries. In a January 2014 note to investors, commercial bank Bancolombia wrote, “Since 2012, the market has begun to question the sustainability of Ecopetrol due to the poor growth in its reserves. This is coupled with an ambitious goal of growth in production (1m bpd by 2015 and 1.3m bpd by 2020) which requires an addition to reserves higher than what the company has historically achieved and which has resulted in a decrease in reserve life for the company that today stands at 8.1 years.” Other sources, including BP’s “Statistical Review of World Energy 2014”, put R/P at 6.5 years.
Oil & Gas Reserves
At the end of 2013 Colombia had proven oil reserves of 2.4bn barrels. This is a fraction of the reserves of other countries with similar levels of production. India, Azerbaijan and Libya, which each produced around 1m bpd in 2013, have reserves of 5.7bn, 7bn and 48.5bn barrels, respectively. Colombia also has the lowest R/P ratio of any country that produces at least half a million barrels per day. Crude oil E&P is focused in the foothills of the Andes, particularly the Upper Magdalena Valley, and the Llanos basin in the east, bordering Venezuela. These areas have been exploited for decades without new exploration adequately compensating for the increases in the rate of production.
Reserves throughout the country are certainly low, which will necessitate sustained investment in exploration on the part of both Ecopetrol and private companies. However, the significance of the stated life of reserves should not be overstated either. Colombia’s R/P ratio, as is the case in all countries, is a moving target, adjusted as production changes and new discoveries are made. Some dismiss the gravity of the low R/P ratio, as it always seems to be six or seven years. Indeed, at the end of 2003 it was 7.3, by the end of 2008 it was 6, but by the end of 2013 R/P stood at 6.5 years.
Natural gas reserves are also low. At the end of 2013 Colombia had proven reserves of 5.7 trn cu feet (tcf) of natural gas and an R/P ratio of 12.8. Most of these reserves are located in the Llanos basin. The Guajira Peninsula also holds sizeable resources.
Oil production in 2013 was slightly over 1m bpd, up 6.3% from the year before. This figure represents a tapering off of production growth after annual expansion of between 10% and 17% from 2008 to 2011. Production grew 3.2% in 2012. Projections indicate that production will continue to rise. In its November 2013 “Short-Term Energy Outlook”, the US Energy Information Administration (EIA) predicted that 2014 production would exceed 1m bpd. The Ministry of Mines and Energy (Ministerio de Minas y Energía, MME) projects production of 1.3m bpd by 2020. Much of this growth has come from applying new technologies to boost the yields of existing fields and improving infrastructure rather than from the discovery and exploitation of new resources. For example, production at the Rubiales field, one of the country’s biggest producers, increased from 37,000 bpd in 2008 to 177,000 bpd in 2012 thanks to investments in technology and the construction of a pipeline.
Oil production is carried out by a range of firms, including Ecopetrol, foreign majors, and both foreign and Colombian juniors. Firms of each type are involved in conventional onshore production, while, with a few exceptions, shale and offshore drilling is the exclusive purview of majors. Many of the juniors are Canadian-listed E&P companies that explore new fields and then sell their interests in them to bigger companies or partner with majors to exploit them.
Such is the case in the nascent shale oil industry, in which the Canadian-listed Canacol Energy has partnered with ConocoPhillips, ExxonMobil and Royal Dutch Shell in order to further explore and exploit its shale plays (see analysis).
In 2013 Colombia consumed 297,000 bpd of oil, leaving a significant surplus for export. Traditionally, the US has been Colombia’s primary oil export market, followed by Panama, China and Spain. The US is still expected to remain the most important customer, at least in the medium term, but the market is changing, owing in part to the current US shale boom, leading to an adjustment of priorities in Colombia. “There’s a re-figuration of the international energy market, especially with what is happening in the US,” Amylkar Acosta, the minister of mines and energy, said in a November 2013 interview. “Colombia is almost the only country in Latin America where oil exports to the US haven’t declined. But it is foreseeable that it will happen in the future.” To date, the majority of oil exports have left through the Caribbean port of Coveñas, giving quick access to ports in the Gulf of Mexico and on the east coast of the US. Now investments are being made in pipelines that will transport oil to the country’s Pacific coast, as Colombia looks to Asia for new growth opportunities (see analysis).
In particular, the Chinese and Indian markets represent important new markets for export growth. John Gerez, vice-president for Latin America at Enbridge, the Canadian contractor responsible for building the pipeline to the Pacific, told OBG, “As the country prepares to increase heavy production and Asian markets demand more oil, the development of the Oleoducto del Pacífico would mean a significant investment and saving in the long run.”
Since 2011 the MME has made the expansion of natural gas production a priority. The primary goal is to increase exports, which today sometimes must be curtailed to meet the growing needs of domestic industry and electricity generation. The MME intends to promote the growth of conventional natural gas production through incentives such as royalty discounts, and to encourage the continuing development of shale gas and CBM through royalty incentives and by offering blocks, with such resources in 2014’s contract auction.
In 2008 Colombia produced a significant surplus of natural gas for the first time, thus prompting the development of an export industry. Production that year reached 321.36 bcf and consumption was 268.39 bcf. In 2013 production totalled 444.96 bcf and consumption had risen to 377.86 bcf. Since the surplus emerged, exports have been sent to Venezuela at a rate of 250m cu feet per day along a pipeline built by Venezuela. However, because the gap between natural gas production and consumption remains relatively tight, the government closely monitors the rate of exports and sometimes halts them. In May 2014 natural gas exports to Venezuela were halted indefinitely in anticipation of increased demand for natural gas from electricity plants in the second half of the year. An expected El Niño weather event may also cause droughts, decreasing hydro-electric production (see analysis). Today natural gas production takes place mostly on the Guajira Peninsula and in its surrounding waters, even though the majority of reserves are found in the Llanos basin. There, Chevron, the biggest natural gas producer in the country, operates the Chuchupa offshore field in partnership with Ecopetrol. Chevron also operates the Ballena and Rio- hacha fields on the peninsula. In the Llanos basin Ecopetrol and Talisman operate the Cupiaga and Cusiana fields, which produce natural gas that is used almost exclusively for re-injection. REFINERIES: Despite being a net oil exporter, Colombia must import some refined products, notably diesel fuel, because of limited refining capacity. Currently several projects are under way to boost capacity in order to reach Ecopetrol’s refining goal of 650,000 bpd. The firm said it will invest $3bn in the country’s largest facility, the Barrancabermeja-Santander refinery, to expand capacity from 250,000 bpd to 300,000 bpd by 2016. The department of Meta has also announced plans for a new refinery with capacity of 40,000 bpd to open in 2015. The biggest ongoing project is the expansion of the Ecopetrol-owned Cartagena refinery known as Reficar. With a $6.5bn investment, Reficar’s current capacity of 80,000 bpd is expected to more than double by the completion of the project in 2015. Juan José de la Roche, CEO of local firm Casamotor, told OBG, “Colombia does not have the capacity to refine the nearly 1m bpd extracted. Even if the current refineries were expanded, the country has an obso- lete technology. The ideal scenario is to boost refining through private initiative, but there needs to be help from the government, not financial help, but in transport, infrastructure etc.” PIPELINES: The weak link in Colombia’s energy industry is oil and gas transport infrastructure. Colombia’s roads, which must wind through remote parts of the Andes Mountains to traverse the country, are notoriously slow and decrepit. Travellers to the country will have learned this after consulting options for travel between Bogotá and the coastline. The 1000-km trip between the capital and the city of Cartagena on the Caribbean coast, for example, is a 20-hour drive, frequently along two-lane mountain roads, while the flight takes only 90 minutes.
Because of a lack of pipelines, much of the oil produced in Colombia must travel along these same roads, adding significant costs. Several pipelines are currently in development to remedy the situation (see analysis), including the Bicentennial Pipeline, connecting the Llanos basin to the Caribbean, and a pipeline linking Llanos to the Pacific coast. The government hopes that increased pipeline capacity will ease the burden of transport costs and possibly nudge some development projects across the threshold of commercial viability.
The current oil and gas regulatory framework entered into force following the extensive reforms of 2003. Prior to that point, all hydrocarbons contracts in the country were associated with Ecopetrol as an operating partner. Once private companies were granted the right to explore and produce on their own, it was no longer necessary nor desirable for Ecopetrol to continue as the arbiter of contracts. So, beginning in 2004 this responsibility was transferred to the National Hydrocarbon Agency (Agencia Nacional de Hidrocarburos, ANH). Today the ANH oversees all hydrocarbons resources and sets and carries out the policies by which E&P contracts are awarded.
It should be noted that the new regime did not end Ecopetrol’s associations with private companies. At the time of the regulatory change, Ecopetrol was granted several direct operation zones, and since then it has acquired additional concessions through competitive bidding. To exploit some of these areas, Ecopetrol has continued to enter into service contracts and production-sharing agreements with private oil and gas companies. While the ANH maintains direct control over contract policies and resource management, the MME, under which the ANH operates, handles overall regulation of the oil and gas sector, as it did before the reforms of 2003. The ministry sets the rules for and oversees all exploration, production and transport, among other things, in all of the extractive industries.
Colombia’s royalties regime is considered competitive with regional and global oil producers. Although the Colombian state is the sole owner of all hydrocarbons resources, as stipulated in the constitution, private companies holding E&P contracts earn the right to oil and gas by extracting it and paying the corresponding taxes.
The baseline royalties for crude oil range from 8% for fields that produce up to 5000 bpd to 25% for the production of more than 600,000 bpd. Fields producing between 125,000 bpd and 400,000 bpd pay 20%. The formula by which natural gas royalties are calculated was recently updated and published in the ANH’s Resolution No. 877 in September 2013. Numerous incentives and royalty discounts exist to promote certain types of production, including natural gas, heavy crude, shale oil and gas, and offshore oil and gas (see analysis).
In addition to royalties, operators pay subsurface fees. As summarised by Norton Rose Fulbright, a global law firm with a commodities practice, the fee is paid “during each phase of the exploration period after the first phase, which on average amounts to $0.75/ha, depending on the phase, the size and location of the area, and $0.10/barrel (liquids) or $0.01/m cu foot (gas) during the exploitation period.” Additional “high prices” fees come into play when commodities prices rise above a baseline level specified in the E&P contract. The last important aspect of the royalty regime is the “x-factor”, which is the cut of production after royalties offered by an operator in its bid for a contract.
Since 2008 the ANH has awarded E&P contracts in auctions, known as rondas, or rounds, held every two years. Occasionally, the agency also directly assigns contracts. The first three auctions – in 2008, 2010 and 2012 – were successful in attracting bids from both majors and juniors who competed for concessions alongside Ecopetrol. In 2012 the ANH auctioned 109 blocks of varying types, including concessions in mature, onshore fields, and blocks with shale potential, as well as a small number of deepwater prospects.
The 2014 round will take place in two stages: one that took place in late July and included 95 blocks of various types, and a second later in the year, that will include eight CBM blocks. Of the 95 blocks offered in the first stage, 18 are primarily shale and 19 are offshore. Only majors will be invited to bid on these types of blocks. The government has offered special incentives in the form of breaks on royalties to entice firms to bid on shale and offshore offerings. Juniors and majors may bid on the remainder of blocks, which are conventional, onshore fields. As of mid-May 2014, 46 firms had bought information packages from the ANH to study the available blocks.
As Colombia seeks to increase its reserves and production of natural gas, CBM promises to offer part of the solution. The country’s substantial coal resources and extensive coal mining infrastructure make this type of natural gas an attractive target for the industry. Although exploration of CBM has not yet been extensive, there are early signals that resources could be plentiful. According to the EIA, CBM “has the potential to dramatically increase Colombia’s proven natural gas reserves”. US coal miner Drummond, for its part, has said that its mines in Colombia could contain up to 2.2 tcf of CBM and it has already initiated efforts to extract it.
As of mid-2014 Drummond has signed contracts with Ecopetrol to exploit CBM resources at the La Loma and El Descanso mines. Drummond has also entered into a joint venture with Cerrejón, the country’s biggest coal producer, to develop a CBM project on the Guajira Peninsula. The auction of the eight CBM blocks included in Ronda 2014 should also spur the development of the sector.
Once a company wins a concession at auction, it must obtain environmental licences and, in some cases, consult with local and indigenous communities before beginning exploration. In recent years, these processes have sometimes become points of contention between the government and industry in both the mining and oil and gas sectors. A plurality of executives have called out the government for causing undue delays in development projects and complained that consultations with local communities, which are known in Spanish as “consultas previas”, have become forums where citizens hold projects hostage until private companies provide infrastructure and services. Daniel Marcano, the Colombia country manager for energy firm Saxon, told OBG, “The unwise regulatory treatment of dialogues with local communities is the main issue of the hydrocarbons industry and needs to be urgently tackled.”
On the other side of the coin, recent Colombian governments, which have track records of effectively promoting and protecting investment, claim that the bureaucracy in place is sufficiently accommodating, as well as necessary to protect the environment and private citizens. The OECD, which has been working with Colombia on its bid for membership, studied the regulations as part of an environmental performance review and did not find that they were overly burdensome. To the contrary, the report published in the first quarter of 2014 highlighted Colombia’s “need to do more to steer economic development in an environmentally sustainable and socially equitable direction”.
Oil and gas companies, as well as miners, deal primarily with two organisations when securing permission to begin exploration: the National Authority of Environmental Licences (Autoridad Nacional de Licencias Ambientales, ANLA) and the relevant, local regional autonomous corporation (corporación autónoma regional, CAR). The ANLA, an agency under the Ministry of Environment and Sustainable Development, is responsible for granting environmental licences for energy, mining and infrastructure projects, such as pipelines, at the national level.
Working With Locals
Once ANLA signs off on a project, the relevant CARs must grant their own environmental licences. This two-tiered system can lead to redundant paperwork and holdups. Next, companies must engage in consultations with any local communities that might be affected by the project. These consultations are designed to facilitate a discussion of how the project can most effectively spur local development and create goodwill within the community toward the project.
In the best of cases, these consultations serve the purpose they are intended to. They have sometimes lead companies to reshape plans, such as local employment programmes, to better suit the needs and preferences of a community, leading to better development outcomes and improved community-company relations. But, in other cases, projects have ground to a halt over failed consultations.
When no agreement can be reached, communities often resort to stalling projects with roadblocks. It is the responsibility of the Ministry of the Interior to intervene and mediate such disputes, but this process can lead to years-long delays. César Ortega, the Verano Energy’s chief operating officer and country manager for Colombia, told OBG, “Working with local communities is quite simple when the government is present to negotiate settlements, but when there is no local government to mediate disputes, local communities have all the power to extort and blackmail companies.”
Executives in both the mining and oil and gas industries suggest that part of the difficulty in negotiating with local communities is that the government has done too little to provide services and infrastructure in remote areas. The natural result is that the communities look to the companies to meet their needs. Humberto Calderón Berti, president of Vetra, a Colombian E&P firm, told OBG, “Local communities tend to think that oil companies are responsible for everything bad that happens to them. These are remote areas where the state has a limited presence and it needs to make a major effort to increase its relationships with these communities.”
Such problems are hardly unique to Colombia, but they have had a material impact on business interests in the country. Some projects have been delayed so long that they are, today, effectively scuttled. However, despite the challenges, the extractive industries continue to grow and Colombia is perennially considered one of the most attractive targets for investment in the region. Additionally, not all executives find the environmental licensing process to be as burdensome as many make it out to be. Gerez said, “While the majority of the sector say that one of the major burdens to building up a pipeline in Colombia is the environmental licensing process, I do not see standards as being too onerous or processes too long. Investors just need to comply with the requirements and be patient while waiting for the environmental agency’s resolution.”
Between 2001 and 2008 Colombia passed four laws promoting the development of a local biofuels industry. The first law, passed in 2001, laid out guidelines and incentives for the production and purchase of ethanol-gasoline mixes. A 2004 law did the same for biodiesel-diesel mixes. A third law in 2005 mandated that cities with populations greater than 500,000 had to offer to consumers a gasoline-ethanol blend with at least 10% ethanol content. A similar law for biodiesel passed in 2008.
Aside from the environmental benefits of biofuel, economic and social factors have influenced the government to promote the production of ethanol and biodiesel. Colombia’s biofuels sector relies on domestically produced palm oil and sugarcane, so the promotion of the industry has benefitted agriculture. Supporting local farmers is an ongoing concern of Colombian governments, as agriculture is one of the most effective drivers of rural development, and creating demand for legitimate crops eliminates some of the incentives to cultivate coca.
Since the implementation of the 2005 law, ethanol production increased from 24m litres per year to 380m litres per year in 2013. Since 2008, annual biofuels production has grown from 143,000 tonnes of oil equivalent (toe) to 634,000 toe in 2013. Plans are in place to continue expanding production. Ecopetrol is developing an ethanol plant in the Llanos basin called Bioenergy that will have a production capacity of 480,000 litres per day, making it the biggest ethanol plant in the country. After it comes on-line, which is planned for 2016, the share of ethanol in ethanol-gasoline blends may increase to 15%, according to the Federación Nacional de Biocombustibles. In order to produce adequate inputs for Bioenergy, an additional 14,400 ha of sugarcane will have to be planted. In 2013 of the total 220,000 ha of Colombian sugarcane fields, 40,000 ha has supplied the inputs for ethanol plants.
Colombia’s modern and clearly regulated electricity sector is a boon to industry and to the country’s balance of trade. Hydroelectric plants, as well as an increasing number of coal- and gasfired plants, produce enough electricity to meet 100% of the country’s needs and even create a surplus that is exported to Ecuador, Venezuela and, perhaps soon, Panama (see analysis). The national grid is efficient and reaches 95% of the population, despite Colombia’s challenging topography.
At the end of 2013 Colombia had 14.4 GW of installed generating capacity, with the plants producing a total of more than 60 TWh the same year. About 70% of electricity comes from hydroelectric plants, which are relatively clean but can be subject to fluctuations in production due to droughts. As a result, Colombia’s electricity regulator, the Regulatory Commission of Energy and Gas, has made a push to develop gas-powered plants, which today account for less than 20% of production, and coal-powered plants, which count for even less at 10%.
While other sources of electricity have hardly been developed, in the past few years some have begun to attract attention from investors and the government. Wind is foremost among these. Several projects are under way on the Guajira Peninsula in the north where class-seven winds (the highest rating of wind energy potential) come off the Caribbean Sea (see analysis). Plans are also in place to begin developing geothermal resources. In 2011 Colombia and Ecuador announced a joint venture, known as the Binacional Tufiño-Chiles-Cerro Negro project, to develop a 138-MW geothermal plant on the border between the two countries. Colombia’s state-owned power company, Isagen, and its Ecuadorian counterpart, Celec, will work together on the project. In September 2013 two US firms, Dewhurst and RESPEC Consulting & Services, announced that they had begun initial exploration as part of a geothermal development project under a contract with Empresas Públicas de Medellín, the second biggest utility company in the country (behind Isagen). Exploration had begun on the first of seven exploration sites in the Nereidas Valley near the Nevado del Ruiz volcano range in Colombia’s south. Solar power has gained little traction in Colombia. Of the small amount of capacity that has been installed (likely less than 10 MW), the majority is dispersed throughout rural areas that the national grid does not reach.
Under the governments of Presidents Álvaro Uribe and Santos, the military has waged a constant, and largely successful, campaign against Colombia’s two predominant guerrilla groups, the Revolutionary Armed Forces of Colombia (Fuerzas Armadas Revolucionarias de Colombia, FARC) and the National Liberation Army (Ejército de Liberación Nacional, ELN). For 50 years these two groups have waged terror against Colombian businesses, law enforcement agencies and citizens. They have routinely extracted payments from business owners and government officials under euphemistic monikers such as “war taxes” or “protection levies”. They have also systematically attacked energy infrastructure, notably oil and gas pipelines.
Because of the uneven distribution of the population throughout Colombia and the terrain, including mountain ranges and rainforests, that leave much of the national territory inaccessible, the guerrillas have at times controlled broad swathes of the country. By some estimates, the guerrillas controlled 50% of the country at the height of their power. Today, they are believed to control less than a quarter. The push back of guerrilla influence has been a boon to the oil and gas sector. Hydrocarbons-rich areas in the south and east have now been opened up to exploration after years of being deemed too dangerous. Also, the number of attacks on energy infrastructure fell from 155 in 2005 to 31 in 2010.
Despite the progress, the campaign has experienced something of a setback in recent years. After a period of consistently declining annual attacks, a rebound in attacks began in 2011, and by 2013 the number of attacks had climbed to 259. The increased violence can be attributed to several factors, including the appointment of a new FARC leader who favours infrastructure attacks and, paradoxically, the ongoing peace talks in which teams representing President Santos are engaged with both the FARC and the ELN. Ratcheting up violence is seen as a way to increase bargaining power by the guerrilla groups.
One of the FARC and ELN’s primary sources of funding is “taxes” charged to mining and hydrocarbons companies. Incidences of such extortion are believed to have increased in recent years, although statistics are not always reliable. The uptick in cases of extortion is partially due to a 2011 reform that caused fewer hydrocarbons royalties to be distributed to local governments. Instead, the government now distributes the revenue more equitably throughout the country in an attempt to decrease inequality. The redistribution has caused the guerrillas to shift their extortion tactics. Whereas before they might have been more likely to tap local government officials for cuts of oil and gas revenues, they now go after the companies themselves, feeling the need to extract money before it leaves their region of influence.
Operators have felt the impact of the guerrillas’ new resolve. In 2012 The Economist reported on one nightmare scenario endured by Emerald Energy, a British subsidiary of China’s Sinochem. “[Emerald Energy] has endured repeated attacks by the FARC guerrillas on its small Ombú field in Caquetá,” The Economist wrote. “Security officials in the area say the FARC is demanding $10 for each barrel of oil. Because the company refused to pay, three of Emerald’s Chinese staff, together with their translator, were kidnapped last June. After a bomb attack on a well, Emerald announced on March 6 that it would suspend operations ‘until security conditions improve’. After receiving assurances from military commanders, production resumed the next day, but six days later oil tankers carrying crude from Ombú came under guerrilla fire, leaving two civilians dead.”
While most companies do not experience such ordeals, all must account for these risks when planning operations in Colombia, especially in remote regions. However, relief may be on the horizon. The military has redoubled its efforts to prevent guerrilla attacks and appears to have had some success. The first half of 2014 saw half the number of attacks carried out as in the same period a year earlier. Furthermore, the peace talks with the FARC appear to be progressing and it is possible that an agreement to end the decades-long conflict could be reached in 2015. The government has said an agreement could come as early as the end of 2014. Even if the talks end in failure, there may be a reduction in guerrilla activity directed at energy infrastructure. In this case, the number of attacks might return to baseline levels, rather than the elevated levels believed to be a consequence of ongoing negotiations.
With stable production from conventional sources and expanding opportunities in unconventional and offshore blocks, Colombia’s energy sector appears poised to sustain at least moderate levels of growth. Despite delays caused by the environmental regulatory regime, the rules of the game in Colombia are clear and will allow foreign firms to continue investing in the country with confidence. The MME’s commitment to keeping royalties competitive is another factor that will help Colombia remain one of the most attractive targets for energy investment in the region. Security is a real concern but, at least in the long run, the situation appears to be improving. On balance, Colombian energy appears ready for another strong decade of growth.
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