Vermilion Energy: Small Fields, Big Returns
By: Aleem Virji & Owen Thurston
The Ivey Business Review is a student publication conceived, designed and managed by Honors Business Administration students at the Ivey Business School.
Company Background
Vermilion Energy (Vermilion) is an exploration and production company headquartered in Calgary, Alberta. It operates across ten different countries in three continents. A market darling of the past, Vermilion historically stood out with its differentiated and geographically diverse asset base, historically trading at greater than a 2x premium on an Enterprise Value to Debt-Adjusted Cash Flow (EV/DACF) basis. However, over the past two years Vermilion has seen this industry premium vanish. The multiple compression can be attributed to Vermilion’s growing asset base in Canada following the acquisition of Spartan Energy in April 2018. Canadian production increased from 46 per cent to 60 per cent of overall corporate production, subsequently shrinking Vermilion’s premium to less than 1x.
Vermilion’s Canadian production has some tailwinds that will assist in responding to the multiple compression. A promising catalyst is Liquified Natural Gas (LNG) Canada, an LNG-exporting joint venture backed by Shell, Petronas, Petrochina, Mitsubishi, and Korea Gas. LNG Canada is expected to transport up to 14 million tonnes of LNG per year to Pacific markets—this is equivalent to 350,000 barrels of oil per day of added demand, or about 20 per cent of current natural gas supply in Alberta. However, LNG Canada is not expected to be operational until 2023. Once in service, there will likely be a higher realized price as the currently oversupplied gas in Northwestern Alberta will have access to Asian markets after being converted to LNG. This scenario presents an attractive platform of increased cash flows for Vermilion to fund strategic expansion projects after 2023, but also suggests Vermilion should slow production growth in the meantime until LNG Canada is online.
Vermilion’s recent slump is not indicative of a long-term collapse. The company’s current dividend yield is over 15 per cent, nearly equal to its expected 2020 capital expenditures. Vermilion management has made it clear they will not cut the dividend; however, the company’s payout ratio is expected to increase year-over-year to 125 per cent by 2021. With current commodity prices, Vermilion will have insufficient cash flow to keep production flat, necessitating increased leverage to fund operations. If the dividend is cut without a strategic plan for the excess capital, it is likely that shareholder preference for Vermilion will be lost as it moves operationally and strategically in line with peers. However, with a framework of strategic assets in Europe, Vermilion is presented with an opportunity to re-diversify its asset base and transition back to its historical success.
Burden or Benefit?
While advantageous to re-diversify, shareholders will not reward production growth without a concrete strategic benefit. Vermilion’s untapped opportunity lies within the rising costs of energy in the Netherlands. On the supply side, the retirement of nearly 50 per cent of domestic natural gas supply has transitioned the country into a net importer. On the demand side, progressive global environmental regulations have prompted an expansion of the domestic natural gas industry at the port of Rotterdam.
Domestic Supply
In March 2018, the government of the Netherlands announced that production from the country’s largest gas field, Groningen, would be halted by 2030. Output from the field in 2018 was down 80 per cent from peak production in 2013 due to concerns that exploration and development had resulted in earthquakes. Declines in production have been compensated for with increases in Russian gas imports, nearing 243 million barrels of oil equivalent (MMBOE) since 2014. Given the rocky history between the Netherlands and Russia, importing Russian gas has been an unpopular decision among the Dutch people.
With the only other alternative being importing through more expensive LNG regasification facilities, the Dutch will need to turn to their smaller gas fields to ramp up production. There is precedent for this scenario in the Small Fields Policy introduced in 1974, which prioritized extraction of resources in small fields. This policy was enacted to remove uncertainty in demand and stimulate growth in small-field exploration. Without Groningen, the small fields will now be the lowest-cost source of energy for domestic supply and, since they are not concentrated to one area, pose minimal risk to seismic activity. These small field resources will likely be deregulated further by the Dutch government as Groningen production is phased out.
In 2018, the share of gas revenues in state income fell to record lows making up less than one per cent of the Netherlands’ GDP. Although this may ease the transition away from natural gas production to renewable power, domestic supply today must be maximized to inhibit economic losses from higher import costs. As a producer in the Netherlands, increasing production in small natural gas fields also comes with its own challenges. Complex and time-consuming regulations to obtain permits, as well as increased negative sentiment, have created a barrier to utilizing these resources to their full potential. However, with the high costs of energy and essentially zero transportation costs, the rate of return is only expected to increase as time passes.
International Demand
Environmental trends are pointing to an uptick in LNG demand. The maritime shipping industry currently represents about five per cent of total global oil consumption, but the International Maritime Organization (IMO) is looking to shift regulations towards a more environmentally friendly fuel source. IMO 2020 is a series of new regulations that mandates a global sulfur concentration cap of 0.5 per cent in shipper fuels from the previous cap of 3.5 per cent. In response to the new regulations, shipping tankers are presented with three options:
1. Continue using High Sulfur Fuel Oil (HSFO) but install expensive scrubbers that effectively ‘clean’ the sulfur emissions. Scrubbers can cost about $3 million to install per ship and projections have shown that only 5,000 of 50,000 ships globally will install scrubbers by FYE 2020.
2. Refuel with Low Sulfur Fuel Oil (LSFO) that emits less than the 0.5 per cent sulfur cap. The pitfall is that LSFO is more expensive than HSFO and has been found to emit the similar levels of non-sulfur greenhouse gasses.
3. Use LNG. Environmentally, LNG is a friendly alternative to HSFO and other conventional fuels. LNG reduces sulfur oxide emissions by 85 to 90 per cent and carbon dioxide emissions by 15 to 29 per cent. To use LNG as a fuel, ships need to be renovated to hold the cooled gas and about 80 per cent more combustion volume is needed to achieve the equivalent power to a fuel oil. Even with these drawbacks, various studies have put the operating cost advantage from anywhere between 15 to 30 per cent or more, depending on the price differential between the two fuels.
The IMO has been applauded for its lofty 2050 goals targeting a 50 per cent reduction of current CO2 emissions. However, the International Energy Agency forecasts the IMO will only meet about 10 per cent of its goal based on current measures. IMO 2020 will be the first step of many if the IMO’s 174 member nations are to reach their goals, further accelerating LNG bunker demand. While scrubbers and LSFO are plausible alternatives today, tightening regulations are pushing these options aside.
The Netherlands is home to Rotterdam, the 11th largest shipping port in the world and the largest in Europe. The port is expected to be a market hub for ship-to-ship LNG trade, regasification into domestic markets, and LNG as a bunker fuel. The growth in overall LNG throughput is already being felt with a 37 per cent increase year-over-year in 2019. As a marine fuel, demand grew at approximately 210 per cent year-over-year and is expected to reach 1 million tonnes by 2025. This is an equivalent increase of approximately four per cent to current Dutch natural gas demand; however, this figure is arguably understated as the IMO needs to be more stringent to reach its goals. Whatever the added demand will be, this creates a constant bid for LNG at the port of Rotterdam, leading to higher energy prices in-land, and ultimately benefiting small-field producers.
Growing the Premium
The tandem of rising LNG demand and falling domestic supply will give rise to a cost burden on Dutch consumers, a headache for policymakers, and an opportunity for Vermilion. In 2011, residents of the Netherlands paid €0.0644 per KWh, 15 per cent more than the EU average. Today, they are paying €0.086 per KWh, 45 per cent higher than average. Increasing demand for natural gas and calls to reduce reliance on Russia will force Dutch regulators to increase LNG imports through Rotterdam. However, rising use of LNG as bunker fuel will increase prices at the port, further increasing in-land prices. The optimal option for lawmakers is to reduce regulatory barriers to exploration and production of domestic small-field natural gas, benefiting producers like Vermilion. Initial activity should be driven by established producers with developed assets and geological expertise in the area. As the largest onshore small-field producer in the country, Vermilion is the easy choice to avoid an energy disaster.
Action Plan
Vermilion’s European gas operations are predominantly in the Netherlands and currently contribute nine per cent of corporate production. Vermilion is strategically positioned to leverage its current operations and headquarters in the Netherlands into a larger scale operation. If Vermilion were to double its production in the Netherlands by changing the allocation of its budget from Canada, the estimated share price appreciation would be approximately 50 per cent based on the EV/DACF multiple expanding and the added cash flow from additional Dutch production.
Given Vermilion’s nearly 100-per-cent debt-to-equity ratio, the company is not positioned to raise additional debt or equity to finance a high growth expansion. However, Vermilion can cut the dividend to fund higher return assets, namely the Netherlands. By lowering the dividend to a peer average five-per-cent dividend yield and decreasing the payout ratio from an estimated 110 per cent to 100 per cent, Vermilion could access roughly C$200M of additional capital through 2020. With a determined strategy of where to deploy this capital, the small multiple premium that Vermilion still maintains will not only hold after a dividend cut, but also expand with a strategic diversification strategy.
Vermilion’s cost of each incremental barrel of oil per day in the Netherlands is estimated to be $18,850. With an effective annual decline rate of only 8 per cent in the Netherlands, the C$200 million capital injection takes the expected 2019 production of 8,300BOE per day to 14,600BOE per day in 2020, and to 33,000BOE per day by 2023. Assuming Canadian production is held flat, by 2022 Canadian production will only represent 47 per cent of the company.
Assuming the historical multiple premium over industry of 2x is achieved by 2021, Vermilion should trade at a multiple of 6.9x and imply a share price of $29. This is a 56 per cent increase to the current share price and heavily reliant on regulatory success. Therefore, in the low case, it is assumed that Vermilion only achieves half of its estimated production growth as regulations are more stringent than expected. In this case, Vermilion is unable to diversify to the same extent, only receiving a multiple premium of 0.5x resulting in an expected 6.9x EV/DACF in 2021. This still is quite profitable for shareholders and does allow for the payout ratio to decrease below the 100 per cent threshold to an expected 87 per cent. In the worst-case scenario, it is assumed Netherlands regulators do not allow for any production expansion post-dividend cut. In this situation, Vermilion would push for further deregulation of Netherlands production or explore expansion opportunities in other European countries. By using the excess cash from the dividend cut to pay down debt, Vermilion will decrease its 3x leverage multiple and decrease its payout ratio below 80 per cent for 2020 with no expected downside other than losing the 15 per cent dividend yield.
Conclusion
Given the economics of further expansion into the Netherlands, it is apparent Vermilion must take action to re-diversify its global production base. Vermilion should free up cash flow and lower its payout ratio through cutting its dividend and use the excess cash flow to invest in the Netherlands. These small field Dutch assets have proven to be promising catalysts with IMO 2020 and further environmental regulations increasing demand. On the supply side, the elimination of Groningen production increases the need for small field exploration and production. In the longer term, Vermilion is positioned to capitalize on expansion initiatives with a solid asset base in Northwestern Alberta that will likely provide increasing cash flows as LNG Canada comes online. Overall, by eliminating the dividend to re-diversify its assets into the Netherlands, Vermilion will decrease its payout ratio to sustainable levels and increase shareholder value.