BP's Slowing Transition Strategy Gives Reason for Another Look as Shares Still Undervalued

Strategist

Allen Good

BP previously expected to reduce production by 25% by 2025 and 40% by 2030, but it will now increase production slightly through 2025 and reduce it by about 25% from 2019 levels by 2030, largely through divestments. During that time, it should also improve upstream profitability as higher-margin volumes from major projects come online and costs are reduced.

The extended life is a result of greater investment, but not at the expense of the transition businesses, to which BP remains committed. Its ambitious growth plans for renewable generation capacity remain intact, with targets of 20 gigawatts in 2025 and 50 GW in 2030 from 5.8 GW currently. It also plans to double its liquefied natural gas equity portfolio, expand its fuels and lubricants business in emerging markets, sell more food in its retail stores and charge electric vehicles, and develop hydrogen production. 

In fact, the change in plans results in only a modest increase in the expected relative earnings contribution of the legacy oil and gas business to 2025 and 2030 earnings targets, since BP increased the anticipated earnings growth from its energy transition businesses as well. Current guidance suggests resilient hydrocarbons will constitute about 86% and 75% of EBITDA in 2025 and 2030, respectively. That’s a few points more than previous guidance, but it also includes the recently acquired bioenergy business and assumes higher oil prices of $70 a barrel compared with $60 previously and adjusts for the loss of Rosneft. 

Nonetheless, the tack in strategy should give investors greater confidence in BP’s long-term ability to deliver on its targets for earnings growth (12% EBIDA per share CAGR) and returns (18% return on average capital employed at $70/bbl) as it remains leveraged to oil and gas prices for longer than before.

Business Strategy & Outlook

BP does not have an economic moat, in our view, as our forecast for excess returns has become too low and future uncertainty too high. 

BP has made significant headway in reducing operating costs in its existing production base and capital intensity of new projects so that we forecast it could safely earn excess returns at our midcycle price assumption of $60/bbl. 

However, the uncertainty of excess returns 10 years from now has increased due to the changing composition of the business and potential level of commodity prices during the next 10 years. We don't have the confidence that BP's plan to transition to a more renewable and low-carbon business will create competitive advantages or that commodity prices will be consistently at levels sufficient to generate excess returns during the next 10 years. As such, BP fails to meet key criteria for a narrow economic moat rating. As time passes and BP demonstrates a high level of competence and execution in these newer areas, or our view changes on commodity prices, we could revise our moat rating. 

At our current midcycle oil price of $60/bbl, we assume BP can still deliver excess returns with its current portfolio and revised growth plans. After updating our model with the company's revised strategic update, which includes maintaining hydrocarbon volumes around current levels for longer, we forecast higher returns. However, the forecast for excess returns 10 years from now remains highly uncertain, given the large investments in low-carbon businesses and potential for destructive acquisitions. 

Incremental investment in BP’s hydrocarbon portfolio is likely to be value-accretive, however. As part of its energy transition strategy, it is narrowing its hydrocarbon portfolio through divestments as well as more focused investment. Both exploration and upstream capital spending will be well below the levels of the last decade at about $10 billion per year through 2025 and falling to about $9 billion after 2030. Furthermore, this investment will focus on high-return opportunities such as efficient tiebacks, infill drilling, and other near-hub options that leverage existing infrastructure. To earn capital, projects must earn 15%-20% returns at $60/bbl along with an assumed carbon price for operational emissions and have a payback of less 10 years for oil projects or 15 years for gas. Its current set of opportunities averages a payback of five years with an attractive development cost of $10/barrel of oil equivalent. Based on Rystad data, we estimate BP’s project queue (sanctioned and unsanctioned) has an average breakeven price of $40/bbl, well below our assumed midcycle price of $60/bbl. 

Although this would imply BP can safely deliver incremental excess returns, the last decade or so has left us wary. Including the crash in 2008, oil prices have crashed three times. While they quickly rebounded to $100/bbl by 2010, they subsequently crashed again in 2014 due to the oversupply from the emergence of light tight oil in the U.S. This also represented a permanent downward shift in the cost curve and led to the revision of our midcycle price to $60/bbl. As a result of this volatility, BP’s cumulative economic profit from 2011 to 2019 was negative. In 2020, the coronavirus pandemic caused another oil price crash, which we estimate will result in a negative cumulative economic profit during the next five years even as we continue to assume that oil prices recover to $60/bbl and that the improvement in BP’s cost structure holds.

Given the oil price volatility of the last decade, the emergence of U.S. light tight oil, which acts as the global marginal supplier that can quickly ramp up or down, and the uncertainty of demand (coronavirus fallout, work-from-home impact, EV penetration, and so on), we think it's reasonable to expect similar volatility during the next decade. This does not imply that prices can only fall. The fallout from currently low prices is also industry underinvestment, which could ultimately result in a global shortage and much higher prices than our $60/bbl assumption. Regardless, however, the excess returns we forecast for BP at our midcycle price are too narrow to instill the necessary confidence that they can endure through the cycle in a variety of price environments; thus our no-moat rating. 

Our rating not only reflects our concern about commodity prices or BP’s hydrocarbon business returns. It is also a function of the uncertainty surrounding the company's strategic shift toward renewable and low-carbon businesses. BP has announced plans to move away from hydrocarbons toward renewable power generation, including solar and offshore wind development and EV charging. Management projects about 20% of BP’s earnings will be in energy transition businesses by 2030 and its collective plan (including hydrocarbons) can deliver return on average capital employed of 18%. 

At this level, returns would safely exceed BP’s cost of capital, but we have our concerns. The returns assume $70/bbl oil versus our midcycle estimate of $60/bbl. Also, BP’s renewable power generation targets are relatively aggressive as it plans to expand capacity from 5.8 GW currently to 20 GW in 2025 and 50 GW in 2030. Although BP has some prior experience with developing solar projects through its Lightsource joint venture and recently joined Equinor to develop offshore wind, the growth holds execution as well as acquisition risk, given its growth targets. With the focus on growth, BP risks making the same value-destructive investments at the top of the cycle in the renewables sector as it did in the oil sector. 

It’s also questionable whether the renewable power generation business is capable of earning a moat. Power generation is a commodity business, and it’s unlikely a cost advantage can be earned. Offshore wind likely holds the greatest opportunity for a firm to carve out a cost advantage, given the greater complexity involved in operating in harsher environments, particularly compared with onshore solar. In this respect, firms such as BP could hold an advantage as it can leverage its experience gained from offshore oil and gas developments in harsh environments. Evidence on this transition of experience remains unclear at this point, however. Additionally, development costs for offshore wind are largely composed of elements that offer no opportunity for advantage. For example, turbines are made by many different third-party manufacturers and available to all developers. Costs such as the foundation or transmission to shore are dictated by turbine size and distance from shore, respectively. A firm can carve out an operating cost advantage if it has a large concentration of assets, but there is no barrier to multiple firms achieving this. 

Returns on renewable generation projects typically are 5%-6% on average. BP plans to lift those to 8%-10% through its operational experience, integration with other parts of its business (trading), and low-cost leverage. Not only has BP yet to consistently demonstrate it can do this, but other integrated oils have similar plans. Arguably, none of these elements are particularly unique, either. BP has operational experience, but little directly in renewable generation development, while low cost leverage is widely available. Its most unique asset is its trading operation, but this is not entirely irreplaceable over time. The rising tide of global renewable power generation is likely to lift all boats over time as private and public customers seek out renewable generation. As such, there are many projects available for bid, each typically offering a contract or power purchase agreement that offers above-market power prices or targets a specific return on capital. These type of contracts can act as an intangible asset supportive of a moat if it results in excess returns. However, industry barriers to entry are relatively low—evidenced by integrated oils' ability to enter a space historically dominated by utilities, not to mention firms like Tesla in distributed generation—and available competitive advantages are limited, which is likely to result in more competitors entering the market. As competition intensifies, it is possible the contracted prices or rates of return fall toward the cost of capital in a competitive bid process, reducing the potential for excess returns. The increase in competitors may also mean that governments no longer need to offer above-market rates to secure supply. European countries have already begun to withdraw subsidies that kept prior contract prices above market rates. So while BP’s return targets might be achievable, the level of uncertainty on how the market develops at this point prevents a narrow moat rating. 

A key element of BP’s strategy to address the energy transition is to leverage and grow its existing retail assets to charge EVs and sell more convenience items (coffee, prepared food, and so on), but the uncertainty and lack of competitive advantages keep it from delivering a moat. Marketing is already a high-return business for BP, and it expects its expanded strategy to deliver returns on average capital employed of 15%-20% by 2030 as it doubles its retail sites that offer food, grows retail sites in emerging markets sixfold by 2030, and increases its EV charging points from 7,500 to 100,000. We have a relatively high level of confidence in this strategy, given BP’s experience and current returns (21% in 2019). However, we’ve typically viewed the fuel retail business as having no moat because of the lack of switching costs. Our previous research has shown that EV charging actually leads to relatively little energy sold and will likely just serve as a traffic generator for retail sales, not a meaningful source of revenue itself. Also, it remains unclear what the future of EV charging will look like and if the typical roadside location will play its historical role, given the convenience of at home/office/retail charging. 

BP is exposed to several environmental, social, and governance-related risks, but these have no bearing on our final moat rating as most are too long-term for moat consideration or are not probable or material enough risk to cause material value destruction. BP’s primary ESG risk stems from carbon emissions in its operations and use of its products and emissions, effluents and waste generated in operations such as oil spills. 

The risk from carbon emissions is most likely to materialize through a carbon tax, which increases the price of end products to consumers, reducing demand over time and threatening BP’s hydrocarbon business. We expect carbon taxes to gain greater adoption over time but think the impact on hydrocarbon demand remains more than a decade away. Furthermore, BP strategic plans call for a relatively rapid move away from hydrocarbons, which should insulate it to a greater degree than peers from any carbon tax.

Oil spills are an ever-present risk for oil companies operating offshore and can be devastating to a firm's value, as BP’s Macondo incident in the Gulf of Mexico shows. While oil companies regularly cause spills, most are immaterial in size and associated fines and cleanup costs are manageable. Meanwhile, large spills such as Macondo are very rare and do not factor into any of our scenario modeling.

None

Economic Moat

Castrol is a British global brand of industrial and automotive lubricants offering a wide range of oils, greases and similar products for most lubrication applications.

Castrol

Amoco is a global chemical and oil company formerly Standard Oil Company.

Amoco

BP Plc operates as an integrated oil and gas company. It operates through the following segments: Upstream, Downstream and Rosneft. The Upstream segment engages in the oil and natural gas exploration, field development and production, midstream transportation, storage and processing, and marketing and trade of natural gas, including liquefied natural gas and power, and natural gas liquids. The Downstream segment refines, manufactures, markets, transports, supplies, and trades crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers. The Rosneft segment engages in investment activities. The company was founded by William Knox D'Arcy on April 14, 1909 and is headquartered in London, the United Kingdom.

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