Complex challenges for energy and utilities players in Colombia

Over the past decade the oil industry has been at the centre of Colombia’s economic growth. The sector accounted for nearly one-fifth of all foreign direct investment (FDI) over the past 10 years, approximately half of all export revenues and, through taxes and royalties, provided up to 30% of government income. Consequently, the fall in the oil price from more than $100 per barrel in mid-2014 to less than $30 in early 2016, and expected to drop even lower, has had a large impact on the national economy (see Economy chapter). Major companies have been forced to drastically re-adjust their growth plans and streamline operations. “We must acknowledge that Colombia is not the only country in which oil companies are being hit by the crisis in oil prices. This is noticeable even in the US,” Hermés Aguirre, general manager for Halliburton Colombia, told OBG.

While production has plateaued, exploration work has dropped off sharply. However, promising offshore discoveries – such as the one made at the Orca-1 well by Petrobras, Ecopetrol, Repsol and Statoil – a nascent shale gas segment, and a new, cleaner and more efficient refinery underpin optimism for the long-term future of the industry.


In 2015 Colombia produced an average of 1.54m barrels per day (bpd) of crude oil. The 1m-bpd figure has been a symbolic target for the Ministry of Mines and Energy (Ministerio de Minas y Energía, MME) since the country’s hydrocarbons sector was liberalised in 2003. That year saw the introduction of concession contracts for 100% private ownership of oil blocks, as well as the creation of the National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos, ANH), the body charged with awarding and regulating blocks and promoting foreign investment in the sector.

In 2007 national oil firm Ecopetrol was partially privatised – selling 10% of stock at an initial public offering – and obliged to compete on equal terms with private companies for oil concessions. The effect of these reforms was dramatic. From 2007 to 2013 national oil production doubled from 500,000 bpd to 1m bpd. However, since then production has remained at this mark. Low oil prices and a drop in exploration (see analysis) means that expectations of rapid growth have been dampened.

Since 2007 the ANH has held auction rounds every two years for oil concessions, with a total of 26 bids received for 95 blocks on offer in 2014. In the effort to boost competitiveness, the ANH has moved to allow bidding to take place twice a year.

Ecopetrol Rethinks

Following its partial privatisation, Ecopetrol’s production grew rapidly, reaching 750,000 bpd by the end of 2015. Under Javier Gutiérrez, who presided over the entity from January 2007 until March 2015, the company had ambitious plans to emulate Brazilian national oil firm Petroleo Brasileiro (Petrobras), expanding internationally and entering new segments such as deepwater offshore exploration and non-conventional shale deposits.

In May 2012 the company’s market capitalisation reached $129bn – briefly surpassing the Brazilian firm in valuation – but since then it has fallen by approximately 90% to $13.5bn in December 2015. The firm had targeted 1m bpd of production by 2015 and 1.3m bpd by 2020. However, under Gutiérrez’s successor, Juan Carlos Echeverry, Ecopetrol has revised its expectations downwards. By 2020 the firm targets production of 870,000 bpd, equating to an annual growth rate of 2.5% over the 2015-20 period.

Federico Pérez Garcia, a junior analyst for oil and gas at Bancolombia, told OBG, “In the past our analysis of Ecopetrol was critical of the company for setting very ambitious targets that we believed would be hard to achieve, given the challenges posed by exploration in the country. Now, however, the goals are very conservative”. In December 2015, Ecopetrol announced capital expenditure of $4.8bn for 2016, which represents a 40% drop year-on-year. Although Ecopetrol consistently generates positive cash-flow from its operations, it must hand over a significant percentage of profits to the state, which controls 88.2% of total equity. “The government sees Eco-petrol as a funding source, regularly taking 70% of net income as dividends,” says Pérez. “In 2014 the company generated profits of COP8bn ($2.94m), but the government took COP5bn ($1.84m) in dividends, meaning that the firm had to fund its 2015 capital expenditure (capex) plan with debt”.


Ecopetrol’s 2016 capex plan is indicative of the firm’s priorities in a low oil price context. More than $2.3bn is marked for production activities as the firm looks to reach an average of 755,000 bpd in 2016. In addition, $1bn will go toward the company’s downstream activities, with profitability boosted by low input costs and the commissioning of the Cartagena refinery, known as Reficar, which can better handle Colombia’s mostly heavy crude oil. A further $473m will be spent on transport and $660m on exploration. Though Ecopetrol has exploration and production (E&P) contracts in Peru, Brazil, Angola and the Gulf of Mexico, just 4% of spending will go overseas.

Meanwhile, an ongoing cost-restructuring programme is expected to save $750m in 2016 and the firm will renegotiate contracts with suppliers. Eco-petrol has already begun a process of divestment from non-core assets. In July 2015 it sold half of its 5% stake in electricity company Empresa de Energía de Bogotá for $215m. Two months later it received government approval to sell its 5.32% stake in a second energy company, Interconexión Eléctrica, for an estimated $150m. In September 2015, Echeverry said that these sales, combined with the additional sale of the firms’ shares in Inversiones de Gases de Colombia, a natural gas and liquefied petroleum gas distribution company, could raise a total of more than $1bn.

The sell-off is unlikely to end there. In October 2015, Bloomberg reported that Ecopetrol was exploring options to sell its petrochemical subsidiary, ESENTTIA, although Ecopetrol has since said that as yet no decision has been taken. The firm is also looking to divest its marginal fields in the coming years, Max Torres, Ecopetrol’s vice-president of exploration, told media. In a plan known as “Ronda Ecopetrol”, the company opened up to bids for up to 50% stakes in Ecopetrol’s own 100%-owned exploration blocks. However, only four of the blocks had received bids by December 2015, according to Bloomberg.

The firm’s austerity budget for 2016 appears aligned to a low oil price environment. Following the capex announcement, Fitch Ratings maintained its BBB+ stable rating for the firm, citing its “relatively sizeable reserves, stable production levels, competitive cost structure and dominant domestic market share” as reasons to expect positive cash flow in the future. Ecopetrol’s fortunes could also be bolstered by the return of the Rubiales field to its complete ownership and operation. However, Moody’s is less optimistic, downgrading the firm to Baa3 in 2016.

One of the country’s most prolific deposits, the Rubiales field is owned by Ecopetrol but operated by Toronto-based firm Pacific Exploration & Production (formerly Pacific Rubiales) in return for 40% of production. In March 2015, Ecopetrol announced it would not renew the contract, which expires in June 2016. Full ownership of the block will add some 70,000 bpd to Ecopetrol’s portfolio, though the field is in decline and significant investment is required to maintain production levels. In the meantime, the private sector is awaiting the restructuring of Ecopetrol. “We hope to witness the re-activation of the sector during the second quarter of 2016, after a two-year cycle in the lower part of the pricing curve has been completed,” said José de Oliveira, CEO of Atina Energy.

Private Concerns

The country’s private E&P companies have also been forced to revise their plans in the wake of lower prices. One notable example is Pacific Exploration & Production, the most successful of dozens of foreign E&P firms that entered Colombia following liberalisation of the oil industry. Boosted by revenues from the Rubiales field, the firm grew rapidly, acquiring local competitors and expanding into five other countries in Latin America and the Caribbean, including Peru and Brazil. By 2011 the firm had become the largest independent oil firm in the region with a market capitalisation of more than $8bn.

However, Pacific had borrowed heavily to make its acquisition and to build subsidiary companies focused on midstream and infrastructure projects. As such the company was heavily exposed to falling oil prices, and its market capitalisation had dropped to less than $380m by the end of 2015.

In July 2015 the company rejected a $1.7bn takeover bid from a consortium made up of Alfa SAB from Mexico and Harbour Energy from the US. Refocusing on upstream activities, Pacific’s share price jumped in December 2015 on news that it had acquired the remaining 50% stake in the CPE-6 block from Canadian firm Talisman Oil. The 2400-sq-km block is located on the same heavy oil trend as the Rubiales field in the country’s eastern plains. The August 2015 name-change from Pacific Rubiales to Pacific Exploration & Production was also explained as a reflection of the company’s broader focus on Latin America, and that Mexico and Venezuela could become the focus of future expansion, according to a Bloomberg interview with one of the firm’s largest investors.

Pacific is far from unique in finding itself in a challenging position. A study published in April 2015 by the Superintendence of Companies ( Superintendencia de Sociedades), a regulator of the sector, showed that 23 of 53 E&P companies surveyed were at risk of insolvency, given a continued low oil price.


While E&P companies large and small have recalibrated their business plans for 2016 to meet the demands of $30 per barrel of oil, the industry as a whole faces a much broader issue. Over the past decade, the increase in production has been achieved primarily by bringing marginal fields on-line – often under the control of small, nimble companies – and by applying new and often costly technologies to exploit heavy oil fields and complex deposits. While there have been numerous discoveries, very few have been of sufficient size to have a significant impact on the country’s dwindling proven reserves.

In June 2015, the MME announced that proven reserves had fallen by as much as 5.6% over the previous 12 months to 2.3bn barrels. This represents a reserves-to-production ratio of 6.4 years, the lowest of any major oil country worldwide. In addition, this figure could take a major hit when Ecopetrol presents its new reserves figures in March 2016. “Ecopetrol’s 2014 reserves figures were based on an average oil price of $100 per barrel,” Pérez told OBG. “Their 2015 reserves were calculated at a much lower average price for the year, meaning that probably, many barrels may be deemed uneconomic,” he added.

New Frontiers

Potential long-term relief for Colombia’s dwindling reserves could lie in the deep waters of the Caribbean coast. US offshore exploration specialists Anadarko Petroleum hold nine exploration blocks in Colombian waters, several in consortium with Ecopetrol.

In 2015 the company began a 16,300-sq-km, offshore 3D seismic study on its blocks, the largest seismic survey in Colombian history. In July the firm drilled the Kronos-1 well at a depth of 1584 metres of water at its Fuerte Sur Block, 53 km off the Caribbean coast, which it holds in a 50-50 partnership with Ecopetrol. Although the size of the discovery has yet to be confirmed, Echeverry told media, “These results are very important and confirm the potential of the Colombian Caribbean petroleum system in a vast area and are aligned with Ecopetrol’s new strategy, in which one of the key areas is the exploration on high potential marine basins,” he explained.

Another significant development is the creation of Ecopetrol Costa Afuera Colombia in late January 2015 by Hocol Petroleum, a fully owned subsidiary of Eco-petrol. With authorised capital of COP2bn ($736,000) and subscribed capital of COP400m ($147,200), the new entity will be responsible for E&P activities offshore in Colombian waters.

According to Humberto Calderón Berti, Chairman of The Board of Vetra Energía, an international operator with a presence in Colombia, “The government should leverage the presence of oil companies in remote regions. These companies bring technical infrastructure and can economically simulate these areas to create jobs,” he told OBG.

In 2014 the ANH introduced reforms to stimulate offshore exploration, and while deepwater deposits are likely to take a decade to put into production, this approach allows well-funded firms to develop projects without worrying about oil price fluctuations.

Following this measure, Petrobras, Ecopetrol, Repsol and Statoil confirmed the first offshore gas discovery in the Caribbean at the Orca-1 well. Located at the Tayrona Block, 40 km north of Guajira Peninsula, it was detected 3.6 km from sea level, under 674 metres of water. The discovery is a stimulus for exploration activities on the Caribbean coast and an important precedent for offshore investments. “The Caribbean deepwater basin has the potential to emerge as an area of hydrocarbons production in the near future. When these discoveries come on-line will depend not only on the plans of E&P companies, but also on environmental and fiscal considerations,” Marco Antonio Toledo, director-president at Petrobras, told OBG.

Shale Gas

Colombia is also keen to develop its non-conventional shale reserves, though investor appetite has been lacking. At the 2012 auction round only five of 31 fracking blocks received bids and in the 2014 edition just one of 18 blocks attracted an offer. However, the Middle Magdalena Valley is estimated to hold technically recoverable reserves of 510bn cu metres of shale gas and 4.6bn barrels of oil. Only a handful of wells have been drilled in the blocks since the government legalised fracking in September 2014. Nevertheless, the sector received a boost in December 2015 when US player ConocoPhillips, in a majority partnership with a subsidiary of Canadian firm Canacol Energy, announced that it would invest $85m in fracking its VMM-3 block in the departments of Cesar and Santander.

The move followed an ANH initiative to allow firms that signed conventional exploration contracts before 2012 to search for non-conventional deposits on their properties.


While E&P companies across the globe have faced major challenges in 2015, refiners have benefitted from lower input costs and wider margins. Colombia has five refineries, all owned by state oil firm Ecopetrol, the biggest of which is located in Barrancabermeja in the department of Santander with a capacity of 205,000 bpd. National refining capacity as a whole rose from 290,850 bpd to 376,000 bpd through the ramp up of Reficar in March 2015. The high-tech refinery is capable of processing the country’s heavy crudes and producing low-sulphur content fuels. A private refinery, to be located in the department of Meta, home to much of the country’s oil production, is also planned.

In December 2015 the owner of the project, local firm Llanopetrol, announced that it had signed a memorandum of understanding with Russian firm Rosneftegazstroy, whereby the latter would provide $19bn in financing for the construction of the project in return for an 80% participation.

LPG Dreams

Reficar will also produce 4000 bpd of liquefied petroleum gas (LPG), used as cooking fuel, heating and, increasingly, as an economical motor fuel. In November 2014, Ecopetrol inaugurated an LPG-fuelled 16-MW plant to power remote oilfields. Although LPG consumption is low compared to other Latin American countries such as Peru and Mexico, this is expected to change rapidly. “The LPG industry is currently focused on creating demand in the local market. At present, consumption is 18,000 bpd but is expected to grow to 44,000 bpd by 2017,” Eva María Uribe, president of Gasnova, the association of Colombian LPG distributors, told OBG. “The LPG industry in Colombia remains very fragmented; however, the entrance of international companies will bring about greater structure to the market,” she added.

Power Generation

In general, the Colombian electricity industry is in excellent shape, with an ample supply of low-cost hydroelectric power, a clear regulatory framework and an impressive 96.78% of coverage. However, in periods of low rainfall and drought, the system’s Achilles heel is exposed, as thermal generators struggle to pick up the slack caused by falling output from hydroelectric production.

In June 2015 Colombia had a total installed energy capacity of 15.5 GW following the start-up of the 820-MW Hidrosogamoso dam in late 2014. More than 70% of supply comes from hydroelectric resources. The largest three electricity firms – Empresas Públicas de Medellín (EPM), Isagen and Emgesa – have a long history of developing projects in the country’s wet and mountainous interior. All three have installed capacities exceeding 3000 MW.

The potential for future hydroelectric projects is enormous. In October 2015 the Mining and Energy Planning Unit (Unidad de Planeación Minero Energética, UPME) published its first atlas of hydro-power potential which revealed that the country’s rivers have the capacity to generate 56 GW of power, nearly six times the current volume. The Magdalena River alone has 17 potential sites for future dams, according to Luís Álvaro Mendoza, director of Cormagdalena, the company tasked with making the river navigable. In late 2015 there were two major hydroelectric projects under construction: EPM’s 1200-MW Ituango project and Celsia’s 352-MW Porvenir II project. Both are expected to start by the end of 2018, bringing capacity up to 19 GW.


In a normal year, the country’s hydro projects are more than sufficient to meet the country’s energy needs. In October 2015 UPME forecast that annual national electricity demand would grow by 2.9% that year to hit 66,000 GWh. By 2020 this figure is expected to reach 80,930 GWh.

Yet, maximum demand is forecast at only 10,161 MW in 2015 and 11,952 MW in 2020, well the below the country’s current total capacity of 15,521 MW. When the reservoirs are full, the surplus capacity can be exported, principally to Ecuador. In the wetter months of November to March, Colombia typically exports 60-140 GWh per month to its southern neighbour. Even during the drier months an energy deficit can be met by importing electricity from Ecuador’s diesel-powered plants. However, in years when the El Niño climactic phenomenon led to long periods of dry weather, Colombia’s reliance on hydroelectric power puts the country’s energy security at risk.

Bad Boy

The El Niño phenomenon occurs when a band of warm water forms on the Pacific coast of South America. This warm water feeds clouds that cause periods of high rainfall in Peru and Ecuador, but in Colombia the result can be high temperatures, decreased precipitation and drought. The phenomenon occurs every six or seven years.

In 1992 a severe El Niño led to the worst energy crisis in recent Colombian history. Bogotá experienced regular blackouts and the government had to introduce energy rationing and change the country’s timezone in order to minimise demand for electricity. Memories of Apagón, or “the big blackout”, as it came to be known, cast a long shadow over the country’s electricity policy. It cost Colombia an estimated COP20trn ($7.36bn) and forced the population to drastically change their energy usage behaviours.

In response, the government adopted a policy known as the Firm Energy Obligation (Obligación de Energía Firme, OEF). Since December 2006 consumers have paid a reliability charge on their energy bills. By October 2015 revenues from the charge had reached $7.8bn. Meanwhile, the government auctioned licences for the construction of thermal-generation projects as part of the OEF. Under the scheme, winning proposals receive transparent and stable compensation for their power plants. Most of the time, these generators sit idle.

However, when Colombia’s spot energy price surpasses the scarcity price – which is set by the Energy and Gas Regulatory Commission (Comisión de Regulación de Energía y Gas, CREG) – thermal power plants under the OEF scheme must fulfil two obligations. Firstly, they must deliver a determined daily quantity of energy laid out in the contract and, secondly, this must be done under the scarcity price. In theory, the OEF should ensure that the country has sufficient capacity to meet 100% of its domestic energy demand, and so it proved for subsequent strong El Niños in 1997-8 and 2009-10.

The Perfect Storm

By late 2015, however, there was talk of a return to energy rationing. The Colombian Institute of Hydrology, Meteorology and Environmental Studies predicts that the 2015-16 El Niño will be one of the most severe on record. At the time of writing, extreme temperatures had already brought severe problems across the country, with crops, livestock and forest destroyed by a number of wildfires (see Agriculture chapter). The cities of Cali and Medellín have been particularly affected, with the Cali River all but drying up, leading to water rationing.

By November 2015 the reservoir feeding the Hidrosogamoso dam had dried up to one-third of its capacity. Beginning in September 2015 the spot price of energy had increased from a historical average of $30-50 per MWh to more than $400. As energy prices pushed through the scarcity price, thermal generators were obliged to start up their turbines. There was a problem, however, as production from the country’s principal gas fields has declined significantly. In June 2015 the Ballena and Chuchupa fields, operated by Chevron, produced 450m standard cu feet per day (scfd) down from a peak of 684m scfd in 2010.

The country does have other major gas reserves, but limited pipeline capacity makes transmission to thermal projects next to impossible. As a result some thermal generators were forced to use liquid fuels, primarily diesel. The scarcity price is determined by international prices for fuel oil no. 6. While global prices for this product have dropped significantly, diesel has fallen less, meaning that generating electricity is done at a major loss to the company. In October 2015 the Termocandelaria and Termovalle power plants, which account for approximately 25% of the country’s thermal capacity, announced that they were suspending operations as a result of high costs.


Although Colombia received much needed rain in December 2015, MME anticipates that thermal generation could be required for up to 50% of power generation in 2016. The country’s thermal generators are forecast to lose about $1bn in the first six months of 2016. Around two-thirds of this shortfall will be covered by small increases in utility prices for all users. Consumers pay between $0.14 and $0.93 per KWh, depending on which of the country’s six social stratum, “estrato”, their residence is located.

Consumer groups in the country complain that Colombians have been paying what basically amounts to an insurance premium on their bills for years and are being asked to stump up more. There is no question that thermal power plants are contractually obliged to produce, but there is also little to stop them from declaring bankruptcy and shutting down completely. In the short term there is little option but to pay to avoid shortages, though the crisis looks likely to provide momentum for a new energy strategy in the coming years.

One option is to revise the way in which the scarcity price is calculated in order to take into account the price differential between diesel and fuel oil no. 6. However, the CREG has also introduced new legislation aimed at diversifying the energy matrix and reducing electricity prices.

Under Law No. 109 of July 2015 the CREG will divert payments from the reliability charge to those plants that can produce energy under the scarcity price, including in times of drought. Critics of the resolution say that it will draw resources away from diesel-burning plants and thereby undermine energy security. However, Bayron Triana, director of regulation and environment for the Colombian Power Generators Association, told OBG, “The new plants will have to provide reliable energy but they will also help to increase contracts for electricity demand.”

The next auction is scheduled for 2016 for plants entering production between 2018 and 2020, though the CREG has yet to decide what capacity of electricity will be offered under the conditions of Law No. 109. The auction could inevitably open up the possibility for thermal electric plants using Colombia’s high-quality, abundant coal reserves and for those using natural gas fuel.

The Gas Conundrum

Although the country’s natural gas reserves have proved insufficient to alleviate the challenges posed by the 2015-16 El Niño, major investments could make gas a viable future fuel. Firstly, offshore gas discoveries in Venezuela have opened the door to imports from that country through a cross-border gas pipeline built in 2007. However, political tensions between the two countries, which resulted in the closure of the border in 2015, could make for unreliable supply. Venezuela was meant to begin supplying 39m scfd of gas through the pipeline beginning in January 2016, but the start-up was postponed after Venezuela said it would prioritise domestic supply hurt by its own climactic events. A $140m liquefied natural gas (LNG) import terminal on the Caribbean coast is scheduled to be completed in late 2016 to receive product from Trinidad & Tobago and elsewhere.

Domestic gas reserves will also be brought to market through the construction of pipelines. In July 2015 local gas firm Promigas received its environmental licence for a 190-km pipeline connecting its Caribbean network to gas fields in the department of Sucre. This will go some way to offsetting falling supply from the Ballena and Chuchupa fields. Another local firm, Transportadora de Gas Internacional, will invest $460m in new pipelines and expanding the capacity of its gas infrastructure from the eastern plains. In February 2015 Canacol Energy signed a 15-year take-or-pay contract to supply US firm Altenesol with 35m scfd of gas from its Clarinete gas field. Altenesol intends to build an LNG gas train in the department of Cordoba capable of supplying Colombian coastal cities and other Caribbean markets. In the long term, early signs from offshore exploration suggest that Colombian waters are more gas prone, suggesting a healthy future for reserves.


According to data from the Colombian Oil Association, total investment in hydrocarbons projects in 2016 is expected to drop by about 36.9% to $3bn, and it could be several years before the sector regains optimism of the late 2000s. Nevertheless, the country looks set to remain above the 1m-bpd production benchmark in the coming years, and the massive potential of shale and offshore deposits is just starting to be explored. Likewise, despite the threat of blackouts and rationing as a result of the 2015-16 El Niño, which may bring back uncomfortable memories for those who remember 1992, the huge potential of hydroelectric power and the prospect of increased natural gas production puts Colombia in an enviable energy security position in global terms.

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The Report: Colombia 2016

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