This case study reviews changes to Colombia’s oil and gas taxation regime following reforms implemented in 2003. It focuses on the impact of new and transparent incentive structures on Colombia’s exploration and production landscape.
At end of the 1990s and the beginning of the 2000s, the Colombian oil sector was in steady decline. Production was falling rapidly, from a 1999 peak of 800,000 barrels per day to 541,000 barrels per day in 2003. The oil and gas market was stagnating, with few new discoveries made. To make this situation worse, guerrilla attacks on oil assets imperilled security. Investment began falling, with FDI declining from a peak of $1.4 billion in 2000 to $300 million in 2003. Colombia’s future energy self-sufficiency was in doubt.
To address this situation, President Alvaro Uribe, elected in 2002, pushed through a series of reforms in the oil and gas sector starting with Decree 1760 of 2003. An overall energy regime overhaul, including a number of innovative policy measures, led to a 50% increase in contracts signed,71 an eight-fold increase in exploration area,72 as well as a 61% increase in production between 2009 and 2012.
More significantly, the oil sector received $5.39 billion of FDI in 2012, accounting for 34% of total FDI in Colombia.73 As well as establishing Colombia as “one of Latin America’s foremost destinations for investment into the oil and gas sector”,74 these successes produced a number of additional benefits, including increased infrastructure expansion.75
This success is reflected in Colombia’s EAPI performance, with the country achieving 9th place and leading other Latin American and Caribbean countries by a wide margin. It scores particularly high for economic growth and development (0.75), where it takes the second place in the index, and for energy access and security (0.84). As a net oil exporter, Colombia has successfully exploited its natural resources for economic purposes, as is highlighted by its high score on the fuel imports per GDP (0.89). Thus it is useful to examine the lessons learned from the 2003 reform programme – in particular how changes in policies led to heightened levels of investment into the sector.
A number of regulatory changes played a role in turning the Colombian oil and gas sector around and attracting increased investment. Reforms included Ecopetrol’s transition from a fully-owned state company to an independent and integrated entity, the set-up of an independent regulator, the Agencia Nacional de Hidrocarburos or ANH (National Agency of Hydrocarbons) in 2003 to manage exploration and production activities, and overall improvements in regulatory stability and internal security. In 2007, Ecopetrol sold 11.5% of its shares to the Colombian people, retirement funds and other local and international companies. This change in ownership led to a change in mindset. Ecopetrol now had to compete with the global oil and gas sector, no longer just within its own borders.
These changes notwithstanding, one of the most significant reforms for prospective oil investors was the shift of the fiscal regime from being based on production sharing contracts (PSCs), to being a concession-based regime founded on royalties and taxes.
The pre-2003 tax regime under the so-called “association contract” was heavily biased towards the state-owned Ecopetrol.76 Until 2003, private players could only operate through PSAs with Ecopetrol. This led to a situation whereby the risk balance was heavily weighted against potential investors, who had to take on all of the risk themselves. Until the introduction of a sliding scale, a foreign company paid 100% of the costs of exploration to the NOC. At the point of discovery, 20% in royalties had to be paid to Ecopetrol with 50% of production assumed by the NOC at the start of exploitation.77 Then a sliding scale was introduced, with which Ecopetrol’s stake increased.78
These PSCs ended in 2003 through Decree 1760 and were replaced by an exploration and production contract.79 Since then, the fiscal regime in Colombia has been based on a combination of royalties, corporate income tax and further special oil taxes paid to ANH.80 This is a great improvement for foreign investors, who now enjoy a more equitable share of rewards from increased production. For new oil discoveries, royalties are on a sliding scale from 8 to 25% based on average field production (monthly average in barrels of crude per day).81 For gas exploitation, 80% is applied to oil royalties for onshore and offshore.82 This new system allowed international oil companies to own a 100% stake in oil ventures – a substantial improvement on the old regime. Beyond royalties, the government take on profits is transparent, with various economic rights paid to the ANH for rights to use the subsoil, participation and technology transfer rights. Additionally, overall improvements in the security landscape across Colombia made the country more attractive to foreign investors.
This case study highlights how the right market incentives have significant potential to turn an energy sector around. In particular, shifting the risk/reward balance to a more equitable middle ground supports wider deployment of capital into the market. Today, the big bet for the Colombian oil and gas industry is related to unconventional reservoirs – some estimates show Colombia holding some of the largest deposits of unconventional crude in Latin America, after Argentina.