After a challenging 2016, the Colombian oil industry entered 2017 with renewed optimism. In line with other crude-exporting countries, the fall in global oil prices starting in mid-2014 affected investment in the sector as well as government coffers. Country-specific problems during this time included a continued security threat from armed rebel groups in remote regions, and a lack of major new oil and gas discoveries. In 2017, however, the peace deal with FARC may open up exploration opportunities in former guerilla-held territories, and the prospect of a deal with the National Liberation Army (Ejército de Liberación Nacional, ELN) could bring respite to embattled projects in the north-east.
Offshore exploration is set to accelerate in 2017 following major gas finds in the Caribbean and the prospect of further large-scale discoveries. Meanwhile, production cuts by the Organisation of the Petroleum Exporting Countries (OPEC) provide some level of assurance about future prices. “Colombia’s oil and gas sector is experiencing a transformation as it seeks ways to add value and differentiate from cost,” Leandro Forero, director of the Andean region for oil field services company Baker Hughes, told OBG. “The critical projects that will see this are offshore, unconventional and recovery projects — part of Colombia’s government-led strategies.”
There are three important government entities operating in the energy industry. The Ministry of Mines and Energy (Ministerio de Minas y Energía, MinMinas) is responsible for setting policy for both the hydrocarbons and power generation industries in the country. A separate entity, the Mining and Energy Planning Unit (Unidad de Planeación Minero Energética, UPME) is in charge of planning long-term energy policy. A further key organisation in the oil and gas sector is the National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos, ANH), established in 2003 to award and regulate exploration and production blocks, while promoting the wider liberalisation of oil.
As part of a structural overhaul of the sector, private exploration and production (E&P) firms are allowed 100% ownership of concession contracts auctioned regularly by the ANH. The new conditions proved attractive, with dozens of foreign firms, principally from Canada, the US and the UK, buying up acreage in the country. Hydrocarbons came to represent an important source of funds to the Colombian government, growing from 10% of total income in 2002 to 23% in 2012.
Following a decade of strong output, with production increasing from 500,000 barrels per day (bpd) in 2007 to 1m bpd in 2013, 2016 saw a sizeable decline. Over the course of the year average production fell from 986,000 bpd in January to 807,000 bpd in December. In annual terms, average production fell 12% from 1.01m bpd in 2015 to 885,000 bpd. It is unlikely that the situation will significantly improve in the coming years, and the Colombian government has established an 865, 000-bpd production goal for 2017.
A significant contributor to this slide was an uptick in ELN attacks on the Caño Limón-Coveñas pipeline. The 780-km pipeline, which transports 25,000 bpd of oil from the Equion fields to the port at Coveñas on Colombia’s Caribbean coastline, has been a regular target for over 30 years. Nicknamed “the flute” due to the number of holes in the pipeline, in 2016 it was out of operation for a total of 45 days.
The damage to infrastructure continued in 2017, with a total of 28 attacks in the first three months of the year stopping the pumps for 37 days and costing a total of 893,000 barrels of production. The 2000-member rebel unit has a sturdy presence in the north-east of the country near the Venezuelan border where the pipeline passes. With FARC in the process of demobilising, the ELN’s increased sabotage operations seem to be an attempt to strengthen its negotiating position at formal peace talks that began in Quito in February 2017. “If we are in peace talks in Quito, the first thing that [the ELN] would have to do is to suspend the terrorist attacks on Colombian infrastructure,” Mauricio Cárdenas, minister of finance and public credit, told local press. “There is a negotiation table for them to voice their views and ideas, but do not attempt to do it through attacks against the energy infrastructure of all Colombians.” Although the government’s peace talks with FARC have lasted four years, there are hopes that the framework from this agreement can be applied to ELN negotiations. Such a result would be a major boon for the country’s most targeted hydrocarbons infrastructure.
The steady decline in reserves poses a much more pressing challenge, however. The rapid increase in production over the last decade was achieved principally by the arrival of E&P firms to the country’s long-established basins in the los llanos (plains) and the Magdalena Valley. The firms brought marginal fields online, introduced enhanced oil recovery (EOR) techniques to old wells, and found small and medium-sized satellite deposits that were commercially viable given the increasing global oil prices at the time.
However, from 2009 to the present, no major onshore oil discoveries have been made. Colombia’s growing reserves were due mainly to the application of EOR technology, which made previously unviable ground oil profitable to produce under high global oil prices. Much of this production will be halted with oil in the range of $50-60 per barrel. Indeed, having reached an oil reserve peak of 2.31trn barrels in 2014, by mid-2016, with the oil price under $40 per barrel, Colombia’s oil reserves had fallen to 1.7trn barrels, not enough to last five years.
Opportunities for E&P firms remain in the established basins, but increasingly require innovative technology or new approaches to geological plays. A relative late entrant to the Colombian market, Chilean firm GeoPark acquired two small independent E&P companies with properties in the eastern Llanos in 2012. The firm then pioneered a new play type focusing on structural and stratigraphic traps at the Llanos-34 block, eventually boosting production to 43,000 bpd from nine new fields. GeoPark plans to drill between 15 and 20 development wells at the property over the course of 2017.
At the national level, however, development drilling was limited in 2016. The Colombian Petroleum Association (Asociación Colombiana del Petróleo, ACP) estimates that the country will need to drill between 900 and 1000 development wells to maintain current production levels. In 2016 the ANH targeted 450 wells, but only 150 had been drilled over the course of the year.
The drilling statistics for exploration activity are similarly modest. From 2010 to 2014 Colombian E&P firms regularly drilled over 100 exploratory wells a year, but in 2015 and 2016 these numbers fell to 25 and 16, respectively, with success rates ranging from 15% to 20%. According to the Colombian Chamber of Oilfield Services – locally known as Campetrol – only 305 of the country’s rig fleet was under contract in 2016.
Drilling is one of the major expenses incurred by E&P firms, so it is unsurprising that total foreign direct investment (FDI) in the sector has dipped in recent years. From a high of $5.47bn in 2012, FDI fell to an estimated $3.06bn in 2015 and $1.53bn in 2016, of which only $620m was earmarked for exploration activities. As a proportion of total FDI in the Colombian economy, investments in the oil and gas sector have drastically fallen from nearly 50% in 2010 to under 15% in 2016.
The ACP forecasts that the country will receive a major boost in hydrocarbons FDI in 2017, measuring between $4.7bn and $5bn; however, it also estimates that the sector needs annual investments of $7bn over the next decade to ease the continuing decline. Without it, national production could fall to 400,000 bpd by 2022, at which point the country would no longer be self-sufficient and national refineries would have to begin importing crude. “The level of investment in the oil and gas sector this year is expected to double compared to last year, but it will not be enough to maintain reserve levels and production,” Forero told OBG. “Even if investment doubles, it is still far from the pace that the sector was experiencing five years ago.”
Despite this challenging backdrop, there have been some positive indications that the Colombian oil industry may be bouncing back. The first was the successful restructuring of Ecopetrol. Under previous president Javier Gutiérrez, the national oil company underwent a rapid expansion, reaching 750,000 bpd of production in 2015 with a target of hitting 1.3m bpd by 2020. At the height of the Colombian oil boom in mid-2012, Ecopetrol’s market capitalisation reached $129bn – surpassing that of Brazilian national oil firm Petrobras, widely regarded as a rolemodel for the Colombian firm. However, as oil prices plummeted, the firm’s market cap fell 90% to $13.5bn in December 2015. A shifting macroeconomic outlook led to a change at the top, with the former minister of finance and public credit, Juan Carlos Echeverry, replacing Gutiérrez in May 2015 and initiating a set of reforms.
Capital expenditure, or capex, for 2016 was cut by 40% to $4.8bn, the 2020 production target was redrawn to 870,000 bpd and for the first-time dividends were not paid to shareholders in 2015. The company’s average production in 2016 fell by 43,000 bpd to 718,000 bpd, a figure 3000 barrels more than the previously estimated rate.
Despite this decline, the firm registered an earnings before interest, taxes, and amortization of COP18bn ($5.4m) for 2016 and paid a dividend of COP23 ($0.20) per share, corresponding to 40% of net profits for the year. In 2016 the government received COP837bn ($251.1m). In the past Ecopetrol paid dividends equivalent to 70% of profits and the state – which holds 90% of equity – was the biggest benefactor. For 2017 Ecopetrol pledged to invest a total of $3.5bn, with $650m dedicated to exploration activities. These funds provided an almost immediate return; Ecopetrol announcing in March 2017 that its exploration programme in partnership with independent E&P firm Parex Resources brought a discovery of medium API gravity crude at the Boranda-1 oil well in the department of Santander.
A second reason for optimism in 2017 is the prospect that a peace deal with FARC will open up new areas of the country to exploration and increase the chances of a major onshore discovery. The southern states of Caquetá and Putumayo – lying north of major oilfields in Ecuador – are believed to have particular potential. UK-based E&P firm Amerisur Resources has been one of the most active firms in Putumayo over the last decade, exploring the Platanillo field and constructing a pipeline to connect with the Victor Hugo Ruales pipeline in Ecuador, which takes crude to Pacific export ports. In March 2017 the firm was exporting 4113 bpd via the pipeline, and in the same month it announced it would acquire stakes in three further blocks in the Putumayo hydrocarbons basin at a cost of $4.5bn. “The working interests we have acquired are strategically located close to our OBA transfer system, thus potentially securing rapid and basin-leading margin monetisation of new reserves in these blocks, and exposing the company to the full suite of exploration opportunity in the basin,” John Wardle, Amerisur Resources CEO, told media.
Despite the formal signing of the peace treaty, the development of new hydrocarbons basis may take longer than expected. Communities in the region have had little exposure to oil projects and may be more resistant to exploration than in other areas such as the llanos, where the industry has a longer legacy. In February 2017, following complaints from indigenous groups, Colombia’s Constitutional Court ordered the suspension of activities at a project operated by independent firm Vetra Energy in Putumayo. The 27-well project produced 14,000 bpd and was the largest contributor of royalties to the department. The court ordered that operations could not resume until the firm had conducted a full consulta previa (prior consultation) with the Awá indigenous group that inhabit the region.
The case highlights one of the challenges facing E&P companies in Colombia: a lack of clarity over the consulta previa process. Under Colombian law, firms are required to consult with communities when projects affect the territory, culture or economy of ethnic groups, and most oil companies accept their obligation to earn the social licence to operate. However, the limits of the process can be somewhat arbitrary. The case brought forward by the Awá, for example, was first rejected by the Superior Tribunal of Mocoa – the state capital – and then by the Supreme Court of Justice on the grounds that the project did not encroach into the tribe’s territory. Nevertheless, the Constitutional Court ruled that potential contamination from the project could affect the ecosystem and the plants and animals the Awá rely on for their way of life.
This broadening of the scope of the consulta previa is creating delays and extra costs for oil firms as the compensation requests from groups increase. “The fact that operators do not know how much a consultation process costs makes it more difficult for companies to optimise their resources and manage their assets,” Gabino Lalinde, president of Spanish E&P firm Repsol Colombia, told OBG. “There should be a standardised model that states how much time the process will take, and the rules should be clearly stated,” he added.
Given the challenges of operating onshore, the ANH has increasingly focused on the exploration of Colombia’s Caribbean waters since 2014. “Currently, in Colombia one can find exploratory blocks of good quality,” Lalinde told OBG. “However, given the time required to carry out the exploratory activities and the development of possible discoveries, the reality is that production phases won’t take place for 10 to 15 years. The sector is betting heavily on Colombia’s offshore and hopes that these efforts will be rewarded in the future with several production projects.” With the exception of a single dry deepwater well drilled in 2007 by a consortium led by Petrobras, the Colombian offshore sector saw little exploration until an ANH bidding round in 2014 gave renewed emphasis to the segment, awarding a further five offshore blocks and introducing more favourable fiscal schemes. Royalties for offshore projects were cut by 40%, and the windfall tax on profits was reduced. In September 2016 MinMinas announced that offshore projects would be considered free trade zones, allowing operators to bring in the supplies and services necessary for the development of project without passing Customs. “MinMinas and the ANH are trying to boost offshore activity in the country. The offshore free trade zone is a proof that gives positive signals to the sector and the international community,” Lalinde told OBG. So far, results have been promising. In December 2014 a group led by Petrobras discovered gas at the Orca-1 well, drilled 40 km off the Guajira Peninsula at a depth of over 674 metres. In July 2015 deepwater exploration specialists Anadarko Petroleum completed its Kronos-1 well in the Fuerte Sur Block-53 at water depths of over 1500 metres, also hitting natural gas deposits. In February 2017 the US firm drilled the Gorgon-1 well in its Purple Angel block, 4.7 km from Kronos-1, in depths of 1835 metres of water. The well revealed a gas column that represents the largest gas discovery in Colombian history, greater in size than the Chuchupa gas fields, which have been in production for 40 years.
The three discoveries confirm geologists’ predictions that the deep Caribbean shelf could represent the best chance of recovering the country’s declining hydrocarbons reserves. The ANH estimates the potential reserves of the Caribbean waters at 9bn barrels, in addition to 3bn barrels in the unexplored Pacific Basin. Ecopetrol has a stake in each offshore block – although it operates only one – and plans to funnel $295m of its total $625m exploration budget for 2017 into offshore activities, drilling five wells over the course of the year.
However, deepwater offshore exploration is very expensive and the fields, especially gas-prone deposits, take many years to develop. No projects are expected to begin commercial production before 2022. As such, the acquisition of foreign technology and expertise will be key to the successful development of the deposits. “Offshore exploration continues to be an important element in the energy strategy, although still at an early exploration stage,” Forero told OBG. “We should learn from the experience of Brazil and the Gulf of Mexico given their vast knowledge and the technology they utilise. The technological component is very important in these types of production areas, and we will begin to see more nanotechnology entering the market.”
As the Colombian oil industry moves towards new sources of hydrocarbons, the country’s power generation segment is also undergoing a period of transition. In late 2015 and early 2016 a particularly strong El Niño led to droughts across the country. Production from major hydroelectric dams plummeted, and a number of thermal plants meant to provide backup in such circumstances declared they could not profitably produce power. The government was forced to consider the introduction of electricity rationing in the most affected areas, but in the end such measures were not required. The close call brought up memories of the 1992 energy crisis, when shortages led to rationing and the decision to temporarily change the country’s time zone to make better use of daylight hours cost the country an estimated 2.5% of GDP.
Not only did the 2015-16 El Niño drought last longer than ever before, leading reservoirs to fall to their lowest levels in decades, but gas prices spiked, thermal generators experienced financial challenges relating to contractual issues, and the 560-MW Guatapé hydroelectric plant was damaged and out of operation until May 2016. Together, the Guatapé plant, the Playas Dam and the San Carlos Dam account for 8% of Colombian consumption. Under normal climactic conditions, Colombia’s sizeable hydroelectric capacity is sufficient to meet the majority of the country’s energy demand. As of December 2016 Colombia had installed capacity of 16,597 MW, of which 11,606 MW – around 70% – was provided by hydroelectricity. In December 2016 the country generated 5547 GWh of electricity from hydroelectric plants, supplying 85% or 4709 GWh; while thermal energy contributed 13%, or 731 GWh.
UPME forecasts that by 2020 peak demand will reach 11,952 MW, well below current installed capacity. When the country’s reservoirs are full and the hydroelectric plants are operating at near capacity, Colombia exports energy to neighbouring countries. In March 2015 Colombia sent 128,000 MWh of power to Ecuador and 134 MWh to Venezuela. However, in March 2016, in the midst of El Niño, the current to Ecuador was reversed and Colombia imported 142,000 MWh.
The energy crisis highlighted the threat posed to the system by droughts. The government’s response has been to improve energy security through the construction of a liquefied natural gas import terminal and by diversifying the energy matrix to include more renewable energy (see analysis).
With power generation back to normal in early 2017, the country’s Superintendent of Public Services (Superintendencia de Servicios Públicos, Superservicios) was busy dealing with the fallout from the previous year. With each energy bill, Colombian citizens pay a reliability charge – a fee that goes to the country’s thermal power generators to keep them up and running and ready to enter into production at times of high demand. However, during the crisis the Termocandelaria power plant in Cartagena was offline for 27 days during a critical period, despite having received $29m in reliability charge funds in 2014 and 2015. In March 2017 Superservicios handed the firm a record $12m fine. In November 2016 Superservicios took over Electrocaribe, a power company 85% owned by Spain’s Gas Natural Fenosa, with 2.5m customers in the Caribbean coast, after a series of blackouts and a rising debt amounting to $800m. In March 2017 it was confirmed that the company would be liquidated to pay off creditors, opening up the possibility of legal action from Gas Natural Fenosa.
The Colombian energy sector can look forward to increased investment in 2017 and 2018. With a crisis in the electricity sector narrowly avoided, the government is reassessing its strategy to improve energy security. In the hydrocarbons segment, 2017 will see major investments in offshore exploration, which represents the best possibility for the country to maintain energy self-sufficiency, especially with an additional 1500 km of barely explored Pacific coastline. A restructured Ecopetrol operating on a more cost-conscious basis will also provide revenues for the Colombian state as it looks to implement its post-conflict energy policies.
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