May 24, 2020 - 4:02pm EST by
Alejo Velez
2020 2021
Price: 12.40 EPS 0 0
Shares Out. (in M): 8 P/E 0 0
Market Cap (in $M): 121,000 P/FCF 0 0
Net Debt (in $M): 74,000 EBIT 0 0
TEV ($): 195,000 TEV/EBIT 0 0

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I’m recommending buying shares in Royal Dutch Shell at £12.4/share to take advantage of the coming turn in the oil market cycle as supply rationalization exceeds any permanent demand destruction resulting from the COVID-19 crisis. 

With a medium-term (5 years) investment horizon in mind, I believe the absolute downside is limited and the base case potential returns (based on forward curve oil prices) are in the mid teens annualized. 


  • We are at the point of maximum pessimism for the industry. The sector weight in the MSCI World (4.9% as of 2019, compared to 5.7% in 1995) and S&P 500 (3.5% currently vs. 13.6% in 1990). At current prices and assuming they stay around current levels for the year, the world’s total oil bill would be about 1.5% of Global GDP, vs a 52 year average of 3.1%. 

  • Pessimism is justified, but what’s being discounted is unlikely to materialize. The pandemic demand shock has been the once-in-a-century event nobody anticipated, throwing everyone’s plans in disarray and providing a catalyst for the industry’s capital cycle to finally turn: as profits collapse, managements change, incentives improve, capital expenditure is slashed, and the industry starts to consolidate. A recovery in profits should follow, supported by the ensuing supply/demand mismatch pushing commodity prices higher. 

  • The impact of Covid-19 lockdowns on demand has been brutal: in China, it was down 30% in February. India, the third largest consumer, saw fuel consumption collapse 70% in April. The IEA expects 2020 global demand to be down 6% vs 2019. However, there’s room for hope. Already Chinese demand is back at 90% of its pre-Covid levels. Countries in Europe that have lifted restrictions are experiencing a surge in transportation demand, as is the US. Demand may be lower in 2020, but it will recover, and should still grow for a few more years. 

During the Global Financial Crisis, global oil demand fell by 2 million barrels and took less than 18 months to recover. 

  • The supply response has been material: 

    • OPEC+ have agreed to cut: 

      • 9.7Mbdp in May and June 2020

      • 7.7 Mbpd from July to December 2020

      • 5.8 Mbpd from January 2021 to April 2022

    • Norway agreed to cut production by 250,000 barrels per day in June and by 134,000 barrels per day in the second half of 2020. Additionally, the start-up of several fields has been postponed until 2021. 

    • Canada is expected to produce 600,000 less in 2020 vs. 2019. 

    • In the US, as of late April, a group of the largest 25 E&Ps had lowered production expectations for 2020 by 563,000 barrels. For the week ending May 8th, the US rig count hit its lowest count level since 1975, and as of May 15th, it stood at 258 oil rigs, 68% below 2019 year end levels. As a result, US production (total crude and NGLs) should be around 3-3.5 million barrels lower than 2019s. 

    • In addition to the agreed cuts of late April, Saudi Arabia announced in mid-May it had cut production by an extra 1 million barrels per day. 

  • The supply response could be more permanent than anticipated.

    • Global Oil Majors have announced capex reductions of 20-25% vs. original 2020 budgets. Lower capex leads to lower production in future years (for instance, Exxon’s capex cuts in the Permian basin this year are expected to affect production by 150kbpd in 2021). US independent E&Ps have announced capex reductions of ca. 35%. In aggregate, total industry capex could be down anywhere between $60-100bn in 2020. 

    • Bernstein expects ca. 1 million barrels being permanently shut-in. Smaller fields (<10kbpd), oil sands, Deepwater late-life fields. These would be unlikely to come back as the investments required would be uneconomical. 

    • Appetite for new investments is low: current prices and outlook too negative. Private Equity has had a poor experience so far in US Shale, Canadian Shale, Gulf of Mexico, UK North Sea. Management teams would be reluctant to commit capital to long lead-time projects, with the future of demand being questioned on a daily basis, pressure from climate change debate returning to the forefront after COVID crisis, and 

    • An increased focus from boards on these risks but also on the sustainability of businesses and returns on the capital employed. Looking at Shell’s remuneration policy, for instance, 30% of annual bonus is conditional on operating cash flow delivery, and 67.5% of LTIP outcome depend on relative ROACE and Cash from operating activities, and absolute free cash generation. About a third of BPs LTIP is based on ROACE metrics and 30% on relative TSR.  Exxon incorporates ROACE metrics into the LTIPs already and so does Chevron, TOTAL, Equinor. These have become more relevant and have gradually been replacing TSR or EPS metrics. 

Source: Shell 2019 20F 

Source: BP 2019 20F


  • Against this background, oil majors are discounting $30-40/bbl oil prices going forward. For the reasons mentioned above I believe this is too pessimistic and ultimate prices are likely to be higher. They can’t remain below $30/bbl for too long because that is roughly the marginal cash cost of Global non-OPEC, ex Russia producers (which includes the majors) and ca. 5-6 million barrels of production would need to be shut down. See below:


Source: Bernstein

  • The good thing is they don’t need to be much higher for investors to realize low to mid teen annualized returns in the coming 5 years across the sector. 

In a nut-Shell

To a greater or lesser degree, most Oil Majors operate somewhat similar business models. Shell and Exxon’s are the largest of the group and have the most comprehensive array of businesses. In Shell’s case, they touch every aspect of today’s energy supply chain. See below chart for reference: 

Source: Shell 2019 20F

After the latest strategic plan, Shell looks at their activities in three core groups: Integrated Gas, Upstream and Downstream, with a fourth, Projects & Technology, managing the delivery of major projects and driving R&D across the other three. 

Integrated Gas comprises natural gas exploration, extraction, LNG activities, natural gas conversion into GTLs; Gas upstream and midstream infrastructure; LNG, natural gas, electricity and carbon emissions trading. The New Energies business is also included here. Shell’s total LNG sales volumes have increased from 39.5 Mt/year in 2014 to 74.5 Mt/year in 2019, with 39 Mt/year being trading volumes and the rest equity LNG. Total LNG liquefaction capacity today stands at 42.3 Mt/year. 

Upstream comprises exploration and production of conventional oil and gas, deep water and shales, as well as midstream infrastructure operation to transport and market production. Shell’s upstream production was 2.7 million bpd in 2019, with 63% of these liquids and the difference gas. 

Downstream comprises oil products and chemicals refining, as well as the retail operations. As of 2019, Shell had ca. 46k branded retail sites, generating about $55k/year of earnings each. Their refining system can process 2.9 million barrels of oil per day in 21 refineries around the world and utilization has been 89% on average over the last 5 years. They also sell ca. 15 Mt of chemical products every year. Refining operations are expected to continue declining while chemicals should grow as this has been an area of focus for the business in recent years. 

Source: Shell 2019 20F

Why choose Shell amongst all the majors? 

A good question. It’s not a good business. Its cumulative long-term returns are poor: 3.15% annualized returns since 1988, including dividends. To provide some frame for comparison, Exxon, while underperforming the S&P over the same timeframe has delivered 7.9% annualized returns.