Over the next decade, private-sector companies may invest over $1 trillion to develop new sources of high-cost oil production. Much of this future production will (1) be profitable only if oil prices remain near current (historically-high) levels; and (2) come online at a time when global oil demand may be entering the start of a long-term decline. Investors in oil producers need to ask: how rigorously do these companies stress-test new projects against scenarios of declining oil demand and diminished oil prices?
Last year the world consumed 91 million barrels per day of oil to fuel cars and trucks, heat buildings, make petrochemicals, and generate electricity, among other uses. Many observers (including major oil companies) project that over the next two decades global oil demand will increase to over 100 million barrels per day. Roughly 80 percent of projected demand growth, however, is to occur in just two regions – emerging economies in Asia (principally China and India) and the Middle East.
Nearly everywhere else oil demand is expected to stabilize or decline within 10-15 years as a result of slowing economic growth, more efficient use of oil (particularly in transport), and substitution toward natural gas, biofuels, and electric vehicles. Should these trends take root sooner-than-expected in developing Asia and the Middle East – which to some extent is already happening (e.g. China’s recently heightened fuel-economy standards for cars) – within a decade or so demand for oil globally could begin a steady long-term decline.
Note that reducing global oil demand by the early 2020s is essential to limiting future climate change to 2 degrees Celsius (2°C), as 193 nations committed to doing in the 2010 Cancun Accords. To have a 50 percent chance of staying within a 2°C threshold, the International Energy Agency (IEA) projects that global oil demand mustpeak in 2020 before declining to less than 80 million barrels per day in 2035 and to roughly 50 million barrels per day in 2050. Forecasting future oil prices under a 2°C oil demand trajectory is very challenging. Recent history, however, suggests that price reductions could be substantial – from 2008-2009 a drop in global demand of 3 million barrels per day caused the average annual price of Brent crude to fall from $97 to $62 per barrel (and at one point in 2009 to go as low as $40 per barrel).
The prospect of waning oil demand and downward price pressure has major implications for the profitability of future production. One way to understand this is to consider a reference “carbon budget” for oil that is consistent with a 2°C world. In our recent report (Carbon Supply Cost Curves: Evaluating Financial Risk to Oil Capital Expenditures), we estimate that through 2050 cumulative emissions of carbon dioxide (CO2) from oil should be no more than 360 billion tons (or 40 percent of the overall 900 billion-ton 2°C carbon budget for all fossil fuels); this suggests a “2°C safe” average level of global oil production through 2050 of 57 million barrels per day (i.e. nearly 40% lower than 2013 production). Examining the supply curve for global oil production, we find that nearly 100 percent of “2°C safe” production can come from oil with a supply cost of $60 per barrel or less (i.e. projects that, after adding a standard “contingency” margin, would require a market oil price of $75 per barrel in order to be approved development).
One interpretation of this finding is that oil production with supply costs above $60 per barrel may struggle to be profitable should the world’s major economies implement policies to significantly reduce CO2 emissions, increase transport efficiency, and/or promote cleaner alternatives to oil. Over half of potential production below $60 per barrel, however, resides in countries that are members of the Organization of the Petroleum Exporting Countries (OPEC) – which as a matter of policy restricts oil production within specified quotas. Taking OPEC supply restrictions into account, we therefore emphasize $80 per barrel as a reasonable proxy for the supply cost for marginal world oil production (i.e. the highest cost barrel produced to meet demand) under a low-oil demand scenario; in other words, in a low-oil demand scenario the most expensive oil produced would (including the standard “contingency” margin) require a market oil price of $95 per barrel in order to deliver the required risk-adjusted returns.
Applying this $80 per barrel supply cost ($95 per barrel required market price) threshold to the global oil supply curve, we find over one-third of potential production through 2050 to have costs above this level. Moreover, 75 perc ent of this high-cost production belongs to companies in the private sector, rather than to state-owned national oil companies such as Saudi Aramco or Venezuela’s PDVSA. Through 2050 private-sector companies have potential capital expenditures (capex) of $21 trillion (in 2014 dollars) to develop this high-cost production; $1.1 trillion of this amount is likely to come over the next decade. Given the demand risks outlined above, $21 trillion of capex on high-cost production poses substantial financial risks for investors in oil companies. Prominent examples of where this high-cost capex is to be spent include the oil sands of Alberta and deepwater/ultra-deepwater production in the Atlantic.
Moving from demand-side to supply-side risks, profitability of future high-cost production may also disappoint due to higher-than-expected project costs. Many forthcoming oil projects face significant technical risk, for example due to the complex geology of Canadian oil sands, the unpredictable weather patterns and environmental sensitivity of the Arctic and Gulf of Mexico, or the 2000-meter water depths of Brazil’s “pre-salt” ultra-deepwater formations. Continuing difficulties at the giant Kashagan field in the northern Caspian Sea – where operational setbacks have put production years behind schedule and $30 billion over budget – highlight the risks for investors from technically complex projects. In addition to technical risks, through 2025 we also tally $300 billion of high-cost projects in countries with substantial geopolitical risks such as Russia, Kazakhstan, Venezuela, Nigeria, and Iraq. Combined with moderating oil demand growth, potential delays and escalating project costs compound the risks to profitability for many high-cost projects.
Though exposure varies across resource types and geographies, the vast majority of oil companies plan to devote some portion of future capex to high-cost production. Our analysis identified multiple smaller oil companies, particularly those focused on oil sands and deepwater production, who intend to devote 80-100 percent of their total capex budgets to high-cost projects. The share of high-cost projects in the capex budgets of the seven global oil Majors is lower, ranging from 18-28 percent; even so, through 2050 the Majors still have $1.3 trillion potential capex on high-cost projects.
To protect investment portfolios from the risks associated with high-cost oil production, asset owners and fund managers must scrutinize company capex budgets more thoroughly than they have in the past. The essential first step is to quantify a portfolio or fund’s exposure to high-cost oil reserves; specifically, investors should understand the million barrels per day of oil and billion tons of CO2 that are expected to be produced at different levels of supply cost (i.e. above $80 per barrel, above $100 per barrel, etc.). Diligent investors should take particular note of high-cost reserves that will take longer to monetize and hence be subject to more uncertainty about future demand, capital cost, and commodity price conditions; this will include reserves where production is highly capital-intensive or where there is a need to develop new large-scale transport infrastructure (criteria that apply, for example, to many oil sands projects).
Beyond quantifying their exposure to high-cost oil production, investors ought to (1) set thresholds for portfolio company exposure to projects with supply costs above $80 to $100 per barrel; (2) engage with management to emphasize interest in value over volumes (even if this means shrinking the size of a company’s asset base); (3) ensure that compensation policies of portfolio companies prioritize creation of shareholder value (in the short, medium, and long term) over replacing reserves or executing on capital investment programs; and (4) require improved disclosure of the demand and price scenarios that underpin company capex strategy. On this last point, investors should urge disclosure around all potential drivers of oil demand destruction – such as transport fuel-efficiency standards, electric vehicle deployment, curtailment of oil consumption subsidies, etc. – rather than allowing companies to simply disclose high-level assumptions about future CO2 prices.
Investors who adopt the engagement strategies outlined above are likely to identify significant capex dollars that could be better spent as returns to shareholders via buybacks and dividends. Increasing cash returns to shareholders is the logical counterpart to decreasing expenditures on new high-cost production. Reducing exposure to high-cost, high-risk projects, however, does not mean that the oil industry will go out of business. Financial markets frequently have reacted positively to oil producers exiting expensive projects; moreover, the mining and metals sector offer a template for how firms – faced with the prospect of declining demand – can rebalance cash away from new capital projects and toward returns to shareholders. Rather than being inherently antagonistic, the oil industry’s transition to greater capital discipline and more sustainable business models can be a positive experience for companies and investors alike.
Mark Fulton is a Founding Partner of Energy Transition Advisors and an Advisor to the Carbon Tracker Initiative.
Reid Capalino is a Senior Energy Analyst with the Carbon Tracker Initiative and a Research Consultant to Energy Transition Advisors.
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