Canacol Energy — Shifting focus

Canacol has announced that its long-term gas sales contract with EPM is cancelled. This was the first contract that it had signed and would have been supplied through its proposed pipeline from its Jobo processing plant to Medellin. The contract was to sell 21mmcf/day from December 2024, rising to 54mmcf/day in December 2025. Management has also announced that it will not proceed with this pipeline. The pipeline had already been delayed but management had felt increasing headwinds from legal, social and security problems over the last six months. On top of this, management felt that the dynamics of the gas market had changed and the company has decided to invest more in the more prospective Middle Magdalena Basin. Despite this there is still the potential of selling some gas in the Lower Magdalena Basin, although this would be through the existing infrastructure where there is increasing spare capacity and will require less investment.

Canacol had spent approximately US$6m on this project in 2023 and an estimated US$32m in total on the project. The cancellation should not incur any further penalty. The lower investment in this will be used on debt reduction and increasing spending in other areas. Management is due to announce its 2024 budget in December, when we will get a better feel for the numbers.

Canacol has announced that it has made a strategic entry into Bolivia with the signing of three exploration and production contracts with YPFB, the Bolivian state oil company. For these the company has placed initial guarantees of a modest US$1.4m. Management is also in discussions with the government for a fourth E&P contract. This is part of the government’s efforts to attract investment to allow an increase in reserves and production. These contracts are located in the main gas producing basin in Bolivia and close to the main export pipeline to Brazil, allowing any reserves to be quickly commercialised. The targets are low-risk redevelopments of mature fields, as well as some exciting gas exploration targets. There is a modest capital commitment, estimated at approximately US$27m over five years. Canacol believes it will be in a position to start investment in the country in 2024. The company has ambitions of building up this business in a similar way to its Colombian operations, where it entered an unloved gas market in 2012 and has since became the largest independent onshore gas producer.

Bolivia looks an attractive gas market. There is a ready export market to Brazil and Argentina, which are both short on gas and, as such, the marginal price driver will be the price of liquefied natural gas imports. The current import price of Bolivian gas is US$10.00–15.00/mcf. Given that there is an export cost of approximately US$2.50/mcf (operating cost of c US$1.00/mcf and tariff of c US$1.50/mcf), this would give a higher well head price than is realised in Colombia. As a slight offset, the fiscal terms would appear slightly higher, with a government take (royalties and income tax) of 60% and a 10% profit share to YPFB.

Canacol is expecting to drill the high-impact Pola-1 exploration well in Q224, which is a delay on the previous expectation of the end of Q423. This is a high-impact Cretaceous play in its acreage in the Middle Magdelena Basin with P50 prospective recoverable resources of more than 1tcf. Success would also open up other prospects in the area. If gas is found, it is likely to be sold into the interior market, through the existing Transportadora de Gas Internacional (TGI) pipeline where there is significant spare capacity. Success at this well would more than make up for the loss of gas sales through the Jobo-Medellin pipeline.

Canacol is looking at a deeper Cretaceous play in its acreage in the Middle Magdalena Basin. These targets are very large prospects but are a higher risk play than its traditional targets in the Tertiary. Canacol has identified 18 prospects and leads with P50 gross prospective resources of 16.6tcf of gas on an unrisked basis (6.6tcf on a risked basis). Successful drilling of these could be transformational for the group’s reserve and resource base.

The first well in this new play is the Pola-1 well in licence VMM-45, where Canacol has a 100% working interest. This is expected to spud in Q224, with the drilling permit granted and well-pad built. This is a bit later than previously expected, with the company having delays in securing a 3,000hp rig that can cope with the potential pressures. The well is expected to take five months to drill. This exploration well is targeting gross unrisked P50 prospective recoverable resources of over 1tcf of gas, with management believing that the geological chance of success is an encouraging 40%. Any gas discovered at this well would be quickly monetised since the block is adjacent to the TGI gas pipeline, which goes to the interior market. There is currently 260mmcf/day of spare capacity, but this is expected to increase as production declines from the mature fields

Success here would give a huge boost to the group’s resource base, but, perhaps just as importantly, it would significantly de-risk the other prospects and leads in this geological horizon and improve the outlook for Canacol. We believe that the risks associated with this well have been reduced, with Shell and ExxonMobil proving the presence of a working petroleum system with earlier wells.

On 9 November, Canacol reported its Q323 results. The group has been able to benefit from strong netbacks, US$4.14/mcf compared to US$3.73/mcf last year, on the back of robust demand from gas due to the increasing impact of El Nino. Beyond the impact of El Nino, there is a growing shortage of gas and we believe that on the back of this, the company should be able to enjoy higher prices/netbacks. Canacol reported EBITDAX for the first nine months of the year (9M23) at c US$184m, compared to US$161m for the previous year. Management expects this strength in netbacks to continue for the rest of the year and believes that its FY23 EBITDAX will be towards the top end of its previous guidance range of US$190–263m. Canacol took a charge of US$32.6m through the profit and loss account, due to writing off of the historic expenditure on the Jobo-Medellin pipeline.

The cancellation of the Jobo-Medellin pipeline will only affect our forecasts for 2025 cash flows, where there will be lower-than-previously-expected gas sales. We are raising our 2023 and 2024 forecasts following the higher netbacks. Our 2023 EBITDAX is raised to US$240m from US$218m, while our 2024 forecast is raised to US$241m from US$217m. However, we are reducing our EBITDAX estimate in 2025 to US$306m from a previous estimate of US$365m. This is on the back of production of 230mmcf/day compared to our previous estimate of 280mmcf/day. As a caveat for investors, this was a somewhat subjective forecast given the relatively fast-moving dynamics of the gas market in Colombia. There is the impact of El Nino, which is starting to be felt and could cause a shortage of gas over the next few years. On top of this, we have not included any contribution from Canacol’s new operation in Bolivia. Potential success at the Pola-1 well would also affect future forecasts.

We value Canacol on a NAV basis, which is derived from a DCF model. This uses the anticipated post-tax cash flow from the group’s fields and commercial discoveries after development and operating costs. The discount rate we use is 10%, the standard rate that the industry uses. Given we are delaying some potential production in 2025 and beyond this will have an impact on the discounted cash flows and hence our asset valuations.

On proved reserves this would lead to a DCF value of US$651.50m. The probable reserves and resources would add a further US$456.1m; for the sake of being conservative we are risking them and including a 50% discount compared to the proved reserves. This would give a risked valuation of the group’s asset base of US$879.6m, down from our previous estimate of US$1,047.1m. From this, we adjust for the group’s net debt (long- and short-term debt less cash), which at the end of 2022 was US$437.9m. This gives a NAV of US$441.6m. This equates to C$17.36 per share (down from C$23.94 per share) and should be compared to the current share price of C$7.22).

The exploration programme will be the main driver of this asset value and, assuming that management is able to achieve the 200% reserve replacement, then the reserve base will grow, allowing the value to move higher. In 2023 a 200% reserve replacement ratio would imply a 9% increase in group reserves. We are currently not adding any value to exploration upside.