The prevailing low oil price saw exploration and production (E&P) companies cut costs in 2014 and 2015. In order to produce crude profitably at prices of under $40 per barrel, expensive greenfield exploration programmes have been put on the back-burner. However, if Colombia is to maintain its production target of 1m barrels per day (bpd) and prevent the reserves to production ratio – which stood at just 6.4 years at the end of 2015 – from slipping any further, new discoveries are necessary. According to Hermés Aguirre, general manager of Halliburton Colombia, “Cost reductions will inevitably be frequent in 2016. However, we expect the second half of the year to bring a slight rebound to the industry.” In this context, regulators took steps in 2015 to incentivise exploration.
E&P firms shot a little more than 1000 km in both 2D and 3D onshore seismic activity from January to November of 2015. This compared to 3118 km of 2D onshore seismic and 4861 km of 3D onshore seismic activity in 2014. A number of CEOs have suggested that in order for reserves to be replaced at the rate of extraction the country would need to drill around 200 exploration wells each year. However, in the first 11 months of 2015, just 24 exploration wells had been drilled, down from 113 in 2014. Development wells have fared slightly better. In the first 10 months of 2015, a total of 750 were completed, compared to 978 in 2014. However, “step-out” drilling campaigns have little chance of making the major discoveries necessary to boost Colombia’s flagging reserves. According to the Colombian Oil Association’s (Asociación Colombiana de Petróleo, ACP), as of December 2015 a total of 180 of the country’s 506 drills were in operation, with the rest standing idle or in maintenance.
One positive sign for investors in 2015 was that the National Hydrocarbons Agency ( Agencia Nacional de Hidrocarburos, ANH), the body that licenses and regulates oil blocks, showed itself to be adaptable in the face of economic headwinds. The most important regulation, announced in August 2015, was a relaxation of capital adequacy requirements. Under previous legislation, E&P firms were required to put down a 10% guarantee for total investment over a 36-month period. This has been changed to a 10% downpayment on the first 12 months of operations. The measure should free up cash flow for firms facing liquidity problems.
A second accord extends the deadlines for exploration work and permits firms with more than one exploration block to migrate their total investment commitments between blocks. This allows them to focus their investments on bringing their most attractive properties to production. According to local business magazine Dinero, these changes have saved more than $600m in investments and allowed 30 wells to be drilled that would have been at risk otherwise. In addition, the ANH extended incentives introduced in 2014 to stimulate bids for offshore exploration blocks to those offshore contracts signed prior to 2014.
The most radical measure proposed by the ANH is a return to direct contracting of oil blocks. In 2012 the government put an end to direct contracting, meaning the only way for firms to acquire properties was through open auction rounds first introduced in 2007. In December 2015 the ANH was preparing a proposal to be put to Congress, which would allow for direct contracting to be reinstated.
Although the details of the bill have yet to be confirmed, it is expected that E&P firms will be allowed to bid for unoccupied acreage, stipulating the price they are willing to pay and the investment they would commit to the project. The bid would then be publicly announced with a period of time indicated for counter bids from third parties.
The system would remove some of the inefficiencies of the auction process and reduce the responsibility of the ANH to organise and promote rounds.
“Colombia no longer has the luxury of maintaining this dynamic of bid rounds every two years,” Mauricio De La Mora, president of the ANH, said in September 2015. “We need a scheme of permanent investment and we are improving the geological and geophysical part in order to offer quality blocks that incentivise exploration as much as production.” De la Mora also announced that the ANH was investigating ways to introduce multi-client seismic studies to Colombia. Under the scheme, the ANH and a group of private firms would pool funds to pay leading geophysics companies to undertake detailed studies of the country’s hydrocarbons potential, giving firms greater confidence to make direct bids for acreage.
The direct contracts signed before 2012 also have a superior track record in meeting their investment commitments than contracts signed at auction, where firms are tempted to overstate their ambitions in order to secure a winning bid. According to figures from the Colombian Chamber of Petroleum Goods and Services, of the $7.3bn of investment committed in the 221 contracts signed at auctions, just $1.4bn had been executed. In comparison, the 145 direct contracts signed before 2012 had investment commitments of $3.1bn, of which $2.1bn were executed.
Contractual reform is just part of the ANH’s push to incentivise exploration and provide relief to ailing oiling companies. Many in the industry believe that the oil sector’s fiscal obligations also need to be restructured, although changes to tax and royalty legislation will have to be passed through Congress, probably as part of a wider tax reform set to take place in 2016 (see Tax chapter). The precipitous fall in oil prices in 2015 coincided with increased corporate and wealth taxes that the ANH estimates cost the industry up to $1bn during the course of the year.
The ANH has proposed extending the sliding scale of royalty payments – whereby producers pay between 8% and 25% based on production figures – to those contracts signed before 2002 which currently pay a 20% flat rate. The ACP, meanwhile, has also laid out a proposal for corporate tax from oil firms to be indexed to the oil price and that non-producing assets be excluded from the wealth tax.
The prospect of the oil industry seeing its requests met in a wider tax reform was unclear in early 2016. However, even if the fiscal burden is eased somewhat, other bureaucratic and legal issues could hamper competitiveness.
A particularly important issue is the role that the government can play in allowing companies to be more cost-efficient. While operators themselves can take steps to reduce their own costs, delays and expenditure accrued through taxes, environmental licensing and community consultation are currently hindering efforts to be cost-efficient. According to ACP estimates, around half of all oil companies in the country are considering cutting or cancelling investment plans in 2016 as a result of delays and tax increases.
Working within its mandate, the ANH reacted quickly and effectively in 2015. By restructuring costs and contract conditions, E&P companies will be able to focus their investments and, hopefully, achieve improved results with smaller expenditure. However, the agency is fighting against a strong tide. The prospects of Congress passing meaningful tax incentives for oil companies and streamlining licensing processes look uncertain at best (see Tax chapter).
According to ACP’s forecasts, total investment in oil projects is expected to fall by roughly 37% from $4.8bn in 2015 to an estimated $3bn in 2016. Furthermore, the vast majority will be spent on producing assets or on offshore exploration, which involves development periods of five to seven years.
Just $280m is expected to be spent on onshore exploration drilling, and although a total of 35 exploration wells are set to be drilled in 2016, as many as 25 of those were delayed from 2015, meaning only 10 new wells are planned. Discounting the highly unlikely scenario that one of the 35 makes an elephant-sized discovery, it is unlikely that the country will replace its 2016 production with new reserves. A lot of responsibility lies on the shoulders of the country’s geologists.