Canacol Energy — Poised for strong growth

Canacol Energy is a Colombia-based E&P company focused on natural gas and is now the second-largest producer in the country after Ecopetrol, the state oil and gas company. Gas demand is set to increase substantially as Colombia tries to wean itself off oil and coal, with renewable energy projects currently not expected to cover the decline in oil and gas usage. However, under-investment in gas has led to declining domestic production, and hence supply will not meet the forecast demand growth. This is a particular problem for the interior market of the country, which accounts for 60% of Colombian demand, where the mature fields will not be able to fully supply the market beyond 2024 and could meet less than 50% of demand by 2030. Canacol is well-placed with significant reserves and resources and is building a pipeline from its Jobo processing plant through to Medellín, which should be operational at the end of 2024. Construction of the pipeline is awaiting an environmental licence. This will allow the company access to the interior market.

Canacol has experienced very strong growth in gas sales. Over the last decade, the company has seen compound growth of 31% with sales in 2022 reaching 182mmcf/day. This is likely to consolidate in 2023 and 2024 until the group’s new Jobo-Medellín pipeline is in operation. This should enable a step change in production, which by the end of 2024 could be up to 300mmcf/day of gas. Other producers do not have the same advantage as Canacol as they do not have sufficient resources to justify building a further pipeline and, through using the existing infrastructure, are likely to see significant transportation fees of up to US$6/mcf – making the gas expensive.

Management is eager to build its reserve base and is targeting an aggregate annual reserve replacement ratio of 200% (finding 200% of gas produced per annum). In order to meet this, the company is stepping up its exploration programme and plans to drill up to 10 exploration and appraisal wells in 2023. Most of these will be drilled into Tertiary plays where Canacol has gained a high level of experience. Although these are relatively modest exploration targets (with an aggregate size of 20bcf across its current prospect and lead inventory), the group has been successful in using amplitude versus offset (AVO) and has achieved a 90% success rate to date using this technique. Canacol is also looking at a deeper Cretaceous play that could have significant reserves and resources. Canacol plans to spud its first well, Pola-1, towards the end of the year, which, if successful, could have potential reserves and resources of 1tcf of gas on a P50 basis. This would have a significant impact on the group’s current reserve base of 652bcf and would also reduce the risks of the other similar prospects in its exploration portfolio.

Most of the group’s sales are under fixed-price long-term contracts, which gave a netback (sales price less associated costs) in 2022 of US$3.68/mcf. Management guidance is that this will rise to over US$3.80/mcf in 2023 and we assume that, given the long-term contracts in place, they should remain at these levels over the medium term. Therefore cash flow will move in line with production and will give the group a significant boost when its Jobo-Medellín pipeline is operational. We believe that gas sold into the interior will have similar netback to its other contracts. This gives very clear visibility on the earnings of the group and protects investors from the usual volatility of commodity prices that affect most E&P companies, and reduces Canacol’s risks compared to its peer group. For 2023, we are forecasting EBITDAX of US$218m. This is on the back of the 2022 earnings and management’s guidance published in April 2023 with the full-year results. We forecast EBITDAX in 2024 of US$217m rising to US$365m in 2025.

With high visibility on sales and cash flow, management is willing to return excess funds to shareholders by means of a dividend, with management committed to paying US$26m per annum as a dividend and additional money returned via a share buyback. We do not expect management to change this policy in the short term. However, after the sales ramp up following the completion of the Jobo-Medellín pipeline, we believe that this dividend and buyback could be reviewed.

We value Canacol Energy 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. On proved reserves this would lead to a DCF value of US$775.6m. The probable reserves and resources would add a further US$543.0m; 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$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 an NAV of US$570.1m. This equates to US$17.81 (C$23.94) per share and should be compared to the current share price of US$7.93 (C$10.55).

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.

As with all energy companies there is a broad spectrum of risk. This includes the usual risks associated with the industry, such as the availability of equipment and oil services. However, there are some specific risks that we recommend investors focus on. Despite its long-term contracts, Canacol Energy is subject to commodity prices, especially on its interruptible sales (sales made outside of its long-term contracts). The company will also have to compete against the price of liquefied natural gas (LNG) imports, although these are in excess of contracted prices.

Canacol’s operations are all located within Colombia and, as such, the politics of the country will be important. This covers a range of issues such as environmental concerns, the fiscal regime and the ability to operate. Much of Canacol’s attractiveness is its ability to grow its reserve base. This involves exploration that is high risk, with the expected outcome of an exploration well being failure. Although Canacol has extensive expertise in the Tertiary, the larger Cretaceous play is yet untested.

As with many countries, Colombia wants to cut its greenhouse gas emissions and is looking to reduce its CO2 emissions, under the Paris Agreement, by 51% by 2030. The country is focusing on alternatives to oil and coal for energy, with increased use of natural gas and renewable electricity generation. Although hydroelectric generation is probably the preferred choice of renewable generation, as it accounts for approximately 80% of Colombia’s current power generation, there are limits on the potential to build further dams, coupled with a growing concern over water shortages and uncertainty of rainfall. This is a major issue in the country. According to XM Compania Expertos en Mercados, water reserves are currently 70% of useable volumes at a time when Colombia is approaching the dry season.

Therefore, the burden for renewable power will fall on solar and wind generation. In the UPME Plan Energético Nacional in 2020 (in its business-as-usual scenario), electric power is expected to increase from 18% of Colombia’s energy demand in 2020 to 34% in 2050, with most of this coming from renewables. As oil and coal are phased out, there will be a need for additional sources of power on top of that provided by renewables. Natural gas will have to pick up this deficit in supply and will be a fast-growing segment, from a relatively small base of 9% of energy demand in 2020 to 23% in 2050. Although natural gas still releases greenhouse gases, it emits 50% less CO2 than coal and 30% less than oil.

However, with current global trends there could be a shift away from natural gas which, although better than oil and coal, is still seen as a greenhouse gas source. We believe these forecasts for natural gas demand might prove to be optimistic as the environment moves to the fore of most governments’ policies. This was demonstrated by Colombian president Gustavo Petro’s comment at COP27 in November 2022 that the world needs ‘an immediate withdrawal from oil and gas’.

The use of natural gas is expected to increase sharply on the back of measures to reduce greenhouse gases. The problem for Colombia is that there has been underinvestment in the natural gas market, which has seen natural gas reserves decline by a compound rate of 7% a year over the last decade. According to the National Hydrocarbons Agency (ANH), it is thought that 1P (proved) gas reserves at the end of 2022 were at a mere 2.82tcf, down from 3.2tcf in 2021 and 5.7tcf in 2012. This has left the country with a reserve life (reserves divided by annual production) of a modest 7.2 years compared to over 13 years in 2012. This is a weak position when demand is expected to grow.

With declining reserves there will be a subsequent decline in production over the remainder of the decade. Given the long lead times involved between the initial discovery and the start-up of production, there is little the industry can do to alleviate this decline in the medium term. For example, there has been a string of big gas discoveries (such as Kronos and Gorgon) in the deep-water Caribbean Sea, but these are unlikely to be on stream within the next decade, while development and operating costs will be very high compared to an onshore field.

This will mean that an increasing level of gas demand will have to be met through the import of LNG. We believe that this would then become the overall price setter for the country. With the volatile prices and some shortages seen recently, buyers are increasingly looking to secure long-term fixed contracts for natural gas. However, as we mentioned earlier, reserves have declined and few producers are willing or able to lock in long-term gas contracts.

In contrast to much of the industry, Canacol has been growing its natural gas reserves and sales, allowing the company to become one of the leading suppliers of gas in Colombia. Canacol is the second-largest supplier of gas after Ecopetrol, the state oil and gas company.

Over the last decade, Canacol has focused its exploration and appraisal drilling on natural gas targets. This has allowed Canacol to show substantial growth in 2P (proven and probable) reserves. Canacol has seen compound growth rates in 2P reserves of 22% per annum over the last decade, with gas reserves increasing from 95bcf in 2013 to a level of 652bcf in 2022. Canacol now has approximately 12% of Colombia’s proven and probable gas reserves.

The rate of growth has slowed over the last three years as management has looked to monetise its existing gas reserves rather than grow its resource base. However, the company is stepping up its exploration programme and is targeting an aggregate reserve replacement ratio (reserves found as a percentage of reserves produced) of more than 200% over the next few years. By contrast, in aggregate, the global oil and gas industry has struggled to maintain its reserve base. In 2023, the company plans to drill up to 10 exploration and appraisal wells. On 3 May, Canacol announced that its first well, Lulo-1, had been successful, encountering 207 feet of net pay. Most of the remaining wells will target similar smaller clastic Tertiary prospects, typically approximately 25bcf each, located in the Lower and Middle Magdalena Basin. Although these are small targets, Canacol has built up significant expertise in these Tertiary reservoirs and has a remarkable success rate through the use of AVO. Over the last 10 years, 35 of the 41 exploration and appraisal wells drilled have discovered gas. Of these, 33 of 37 wells were successfully drilled through using AVO, representing a 90% success rate with the drill bit. Canacol has amassed a significant portfolio of 160 Tertiary prospects and leads in its acreage. On an unrisked basis, these Tertiary targets could contain gross prospective recoverable resources over 3tcf, on a P50 basis. Adjusting for the geological chance of success (GCS), these would give potentially risked recoverable volumes of approximately 1tcf of gas, which should be put in the context of the current reserve base of 652bcf of gas.

On top of the Tertiary play, 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 towards the end of the year, with the drilling permit granted and well-pad built. However, the precise timing is dependent on the group securing a 3,000hp rig that can cope with the potential pressures. The well is expected to take five months to drill and is unlikely to be completed in the current fiscal year. This exploration well is targeting gross unrisked P50 prospective recoverable resources of over 1tcf of gas. 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 Energy. 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.

Success at this well could allow management to quickly monetise the gas. 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.

The emphasis on building the reserve base can be seen with the increase in exploration spend. Exploration spend was approximately US$75m in 2022, up from US$42m in 2021. The projection for the current year is a spend of US$73–98m. This will rise further over coming years as production increases, with management eager to maintain an average reserve replacement ratio of 200%. This is in contrast to the industry, which has struggled to just replace production over the last five years.

Canacol Energy has seen very strong growth in natural gas sales. Over the course of the last decade, production has increased at a compound growth rate of 31% per annum, rising from 16mmcf/day in 2013 to 182mmcf/day in 2022. This is approximately 17% of Colombia’s current conventional gas production. This share of the market is likely to increase further as the industry struggles to maintain production, while Canacol, by contrast, increases its resource base and production capacity. This growth has been organic and has allowed the group to switch from being an oil and gas producer to being nearly a pure natural gas producer. In 2023, management expects production of 160–206mmcf/day of gas. By the end of 2024, management believes that it could have a year-end production of approximately 300mmcf/day as its new Jobo-Medellín pipeline comes into operation.

Unlike most players in the E&P space, the group has seen growth in production limited by the potential market where it can sell its gas. The company sells most of its gas from its fields in the Lower and Middle Magdalena Valley into the coastal market, which covers the large industrial area with cities like Cartagena and Barranquilla. Much of the demand comes from power generation, which can be variable given that much of this market is predominantly supplied by hydroelectric and, as mentioned earlier, this is reliant on factors such as rainfall. Additionally, the coastal market can be easily supplied by imports of LNG. Canacol supplies over 50% of the gas into this market, but there is expected to be limited growth here and hence limited ability for the group to increase sales too dramatically. We do not expect to see any major declines in demand in this region.

However, Canacol Energy is looking to supply the interior market, which accounts for 60% of Colombia’s gas demand and covers large markets such as Medellín. This is a more stable market with much of the demand coming from residential and industrial users rather than the more volatile power generation. This market will have a potential shortfall in supply due to the declining production from the mature fields, such as Cusiana and Cupiagua, in the Llanos Basin. These mature fields are expected to start seeing lower production with a 40% decline in production earmarked for this region through to 2026, which would create a potentially large shortfall. In its recent forecast, UPME believes that 2030 supply from these fields could be half of the anticipated demand. This would leave a supply/demand gap of over 300mmcf/day of gas that would need to be filled by new supplies or LNG imports. The interior market is expected to become short of supply in 2024.

This market gives Canacol Energy the ideal market, for its large existing reserve base, in which to grow market share and would allow it to ramp up production significantly. In order to accomplish this, the company will transport its gas through a new pipeline that is being constructed from its Jobo gas processing facilities through to the city of Medellín (the Jobo-Medellín Pipeline). Shanghai Engineering and Technology Corp (SETCO) has been contracted to build this pipeline on a build, own, operate and maintain (BOOM) contract, and it will charge Canacol a fixed-fee unit tariff on the gas transported through the pipeline. This will initially have a capacity of 150mmcf/day of gas, filling approximately half of the anticipated supply shortfall in 2030. However, capacity could be relatively easily expanded, with the addition of further compression, up to 200mmcf/day if required. Canacol will initially produce 100mmcf/day into the pipeline. This is expected to start transporting gas by the end of 2024.

In anticipation of this pipeline startup, Canacol Energy has signed two 12-year take-or-pay contracts with Empresas Publicas de Medellín (EPM), the state-owned utility, which will see the company supplying 75mmcf/day of natural gas. The first contract, which starts in December 2024, will be for 21mmcf/day increasing to 54mmcf/day from December 2025. The second contract is for 21mmcf/day with a further company. It is believed that the price to be realised at the wellhead would be approximately US$5/mcf, which is a higher price than the company realises for much of the gas sold into the coastal market and so could lead to an increase in the group’s netback margin. The volume of gas supplied by Canacol will rise as more contracts are signed. We believe that this leaves the company in a very strong place given that, at the moment, competitor suppliers do not have sufficient reserves to justify building their own pipelines, while using the existing infrastructure, the transport fees could be up to US$6/mcf – dependent on where the reserves are located – making the gas very expensive for the customer or leading to lower netbacks for the producers.

Management believes that once this pipeline is up and running, the group could be producing approximately 300mmcf/day by the end of 2024, which represents a 65% increase on 2022 production.

We value Canacol Energy on the basis of an NAV that is derived from a DCF analysis. This uses the anticipated post-tax cash flow from the group’s fields and commercial discoveries after royalties, transportation, development and operating costs. The discount rate we use is 10%, which tends to be the industry standard for making acquisitions and disposals. This cash flow is predicated on the basis of a gas price realised in 2023 of approximately US$5/mcf and escalated at a rate of 2–4% per annum. This escalator is set on a contract-by-contract basis. The group has multiple contracts at differing prices and inflators. There is a small quantity of oil reserves that are valued using a Brent price of US$85/bbl in 2023, although Canacol receives a discount of approximately US$14/bbl to Brent for its crude oil. Oil is a small part of the valuation given that the company has 2P reserves of 5.2mmbbl of oil and accounts for a mere 6% of the group’s reserve base, and that most of these reserves are not in production.

On proved reserves, assuming a 100% chance of success, this would lead to a DCF value of US$775.6m, of which 60% would come from developed producing fields where there is significant certainty given that there is little development spend required and, usually, significant production history. The remainder of the proved reserves are from discoveries that are not yet onstream but are fully appraised. On top of this, there are the probable reserves where, by definition, there is a 50% chance of at least this level of reserves being present. These reserves if included would add a further US$543.0m to the NAV. This would value the group’s 2P reserves and resources at US$1,318.7m. However, for the sake of conservatism, we believe that the full value of the probable reserves should not be included in the asset valuation, given that the market is growing wary of fossil fuels and will not accredit full value. Therefore, we are including a 50% discount compared to the proved reserves. We are not including any value for Canacol’s possible reserves and exploration upside (which some commentators would include) since significant drilling is required in order to prove up these reserves.

Through this approach we realise a risked valuation of the group’s 2P asset base of US$1,047.1m. From this, we adjust for the group’s net debt at the end of 2022 of US$437.9m. This gives a net asset value of US$609.2m, or US$17.87/share (C$23.94/share), compared to the current share price of US$7.93C$10.55). Investors should be aware that this valuation is a US dollar derived value and that movement in the exchange rate (US$/C$) will have a translational impact. Investors should also note that the value of the proved reserves (less net debt) would still be above the current market capitalisation.

Going forward the exploration programme will have an important impact on the asset valuation of the company. We do not attribute any value to the exploration programme given that there are too many uncertainties at this stage. Exploration success in 2023 and beyond would predominantly add to the group’s probable reserve base (given that further appraisal is required to get these to the proved stage). With the group targeting a 200% reserve replacement, this would imply growing the reserve and resource base by 60bcf of gas per annum, which would equate to an approximate 9% increase in Canacol’s current proven and probable gas resource base of 652bcf. It is worth highlighting the Pola-1 exploration well, which, if successful, has the potential of more than doubling the group’s proved, probable and possible reserve base. With the asset value standing significantly higher than the share price, any further buyback is likely to augment the NAV. To be conservative, we are not factoring in any impact of a share buyback programme into our NAV.

The other factor that would provide a boost to the asset value is the impact of higher interruptible sales as we have seen in the Q1 results, which would lead to quicker monetisation of the reserve base. This could be an important factor as Colombia’s hydroelectric power capacity is currently constrained by water shortages, as we mentioned earlier.

The relationship between the value of the assets and reserves can be seen in the chart below. Investors should be aware that this is not a precise match given that reserves added might have a differing value for the reserves produced, due to factors such as appraisal and development costs, the timing of bringing the reserves on stream and the potential prices for gas sales contracts.

We have looked at a potential peer group of Colombian focused oil companies. These are Frontera Resources, Geopark and Parex. We have compared this peer group on a simplistic basis of EV per barrel of oil equivalent (boe) of 2P reserves, which takes no account of the status of the reserves such as whether they are developed or not. Although Canacol comes out above the average for the selected peer group (Exhibit 11), this does not reflect the advantages that the company possesses. These have been covered in the report and include predictable pricing, solid growth in the production profile and exciting exploration upside.

Canacol Energy is a very profitable E&P company. In 2022, the company achieved a netback of US$3.68/mcf of gas sold at an average sales price of US$4.74/mcf. Over 2023, the company will see a slight increase in the price realised, which should be approximately US$5/mcf, allowing the netback to increase to over US$3.80/mcf – a 3% increase on 2022. We believe that this is a stable level and that this is likely to be maintained over the next few years due to the long-term contracts in place. Therefore, as a rough rule of thumb, the volumes of gas sold will reflect the EBITDAX (earnings before interest, tax, depreciation, amortisation and exploration write off) that the company generates. The company has most of its gas sales contracted under long-term take-or-pay contracts and this gives good clarity on the price realised. However, if Canacol were to sell additional volumes on top of the contracted volumes, then these would be done as interruptible/spot sales, which could see a lower realised unit sales price. However, given the higher volumes sold there would be economies of scale and, as such, there would be only a small impact on the netback achieved.

Management is expecting to see sales of between 160mmcf/day and 206mmcf/day in 2023. The 160mmcf/day is purely on the basis of its existing take-or-pay contracts, while at the upper end of the range this could see an additional 22% of gas produced with these being as interruptible sales. This would see the company generate EBITDAX of US$190–263m, driven by the volumes sold. We are forecasting an EBITDAX of US$218m in 2023. This is on the back of the 2022 earnings and management’s guidance published in April 2023. We forecast EBITDAX in 2024 of US$217m rising to US$365.0m in 2025. This is predominantly driven by volumes. Pre-tax and post-tax profits do not tend to be important for an E&P company that has a heavy exploration programme since this would be heavily distorted by the level of exploration success and hence the exploration write-off. This makes profits very volatile.

We believe that these forecasts could be looking increasingly conservative if the company is able to replicate the conditions at the start of the year. The company reported its Q1 results on 11 May 2023, which show that it was able to achieve an operating netback of US$4.01/mcf and EBITDAX of US$60.9m on the back of gas sales of 185.6mmcf/day. This would imply interruptible sales of approximately 26mmcf/day and that the price realised is higher than the contracted volumes driven by the higher demand. However, at this stage we are not changing our forecasts, as weather will play an important factor for the remainder of the year.

As we alluded to earlier, the level of interruptible sales is very much linked to hydroelectric power generation. Colombia is expected to suffer from the El Nino Southern Oscillation (El Nino) effect from the middle of this year. The last time this effect was seen, in 2015, it brought droughts that had a severe impact on hydroelectricity generation. The US National Oceanic and Atmospheric Administration (NOAA) believes that the Pacific Ocean is returning to normal after La Nina and then El Nino will take control in the second half of the year. If this produces water shortages, it could imply that gas sales would be towards the top of management expectations, especially at the end of the year which tends to be the dry season.

Canacol Energy is unusual compared to many E&P companies in that it gives the cash that is surplus to investment requirements back to shareholders. This comes through a dividend as well as the potential for share buybacks. Through a quarterly dividend, the company returns approximately US$26m per annum. On top of this, the company has a share buyback programme, which allows it to buy back up to 1.97m shares through to March 2024, which at current prices equates to approximately 5.8% of the shares outstanding and could see US$20m returned to shareholders. Our forecasts do not take into account the share buyback, given the uncertainty of the price of the buyback. We do not expect management to change this policy in the short term. However, after the sales ramp up following the completion of the Jobo-Medellín pipeline, this dividend and buy back policy could be reviewed. On the current dividend, investors can enjoy a yield of 10.3%.

We expect operating cash flows of approximately US$220m in 2023, which compares to US$297m in 2022, on the back of the slightly lower production assumptions. We forecast that operating cash flow will rise in 2025 on the back of higher volumes of gas produced with higher gas prices (due to indexation) to US$368m.

With the capital expenditure and exploration spend in 2023, which we are estimating at US$150m, financing and dividend payments, we believe that there will be an outflow of cash of approximately US$25m. Thereafter the group will benefit from the increased production feeding into the cash flow, allowing the company to generate free cash flow.

The company has a relatively strong balance sheet given that it has a very high level of visibility on its production and cash flow. At the end of 2022, the company had net debt of US$438m. This comprised US$496m of gross debt partially offset by US$59m of cash. This debt is predominantly US$500m of senior notes, which have a maturity of November 2028 and a coupon of 5.75% so this does not present any liquidity problems in the medium term. The company also has a US$200m revolving credit facility, which was only drawn down by US$75m at the end of March 2023. Although this gives a high gearing (net debt/equity) of 163%, in our view, this should not worry investors. Looking at other measures, net debt/EBITDA is standing at a more modest 2.2 times and this will reduce further as the group is able to significantly ramp up production at the end of 2024, which will see reduced net debt as well as higher EBITDAX.

Canacol Energy is committed to very tough ESG targets and has set up an independent ESG committee to oversee the company’s operations in a transparent manner. This covers all aspects from emissions through to helping the local communities. Perhaps the most important, in the current economic environment, is the emission of greenhouse gases; emissions at the company are at least 50% lower than its peer group and are shown in the chart below.

The company has a very experienced management team in place.

Charle Gamba is the CEO. He has been in this role since founding the company in 2008. He has 29 years of experience in the international oil and gas space and has previously worked for Imperial Oil, Canadian Occidental Oil & Gas, Occidental Petroleum and Alberta Energy. Mr Gamba sits on the board of Asociacion Colombia de Petroleo and Naturgas – two industry groups that form upstream, midstream and downstream policy for the oil industry in Colombia.

Jason Bednar is the CFO and has over 25 years of financial and regulatory management of oil and gas companies. He was a founding director of Canacol and became CFO in 2015. Prior to this Mr Bednar was CFO of Pan Orient Energy Corp.

Ravi Sharma is COO and joined the company is 2015. He has over 30 years’ experience in the industry, working for companies such as Afren, BHP Billiton and Occidental Petroleum. At Occidental Oil and Gas, he held the position of worldwide chief reservoir engineer.

William Satterfield joined Canacol from Sanchez Oil and Gas Corporation, where he served as senior vice-president of New Ventures and Geosciences. Previously he worked for Occidental Petroleum for 22 years in the Americas, Middle East, Africa and South-East Asia in various geotechnical roles, culminating as exploration manager in Bogota, Colombia. Mr Satterfield has a BSc and an MA in geology from the University of Texas in Austin.

As with all energy companies there is a broad spectrum of risk. This includes the usual risks associated with the oil and gas industry, such as availability and pricing of equipment and oil services. However, there are some specific risks we recommend investors focus on.

As with all oil and gas companies, Canacol Energy is subject to commodity prices. Although most of the gas sold is under long-term fixed contracts, some of the gas production could be sold as interruptible spot sales and hence will be subject to localised prices, which can be volatile. Prices will also be important in setting further fixed price contracts. However, in the short term this will not be an issue, with the company being able to realise a price of approximately US$5/mcf for the next couple of years on the back of its long-term contracts. Currency is not a major risk given that most costs and revenues are US dollar related.

Canacol’s operations are all located within Colombia and, as such, the politics of this country will be important. This covers a range of issues such as fiscal regime and the ability to operate. The other important consideration that is becoming more prominent is climate change. This could lead to governments taking stricter measures on the emissions of greenhouse gases, which would imply more restrictions on oil and gas. For example Gustav Petro, the Colombian president, wants to ban the award of new exploration concessions. As we mentioned earlier, within Colombia the current focus reducing the use of coal and oil, rather than gas.

Much of the attraction of Canacol is its ability to grow its reserve base. This involves exploration, which is high risk, with the expected outcome of an exploration well being failure. This is particularly so with the higher-risk deeper Cretaceous play, which is a new play-type for the company. On the shallower Tertiary plays, management has proved adept at exploration using AVO and achieved significant success, which should offset some of this inherent risk.