Is bp’s big move towards renewables a blueprint for other oil & gas companies?
Frontispiece: bp’s announcement last week on 2Q financial results and more details on their strategy to be net-zero by 2050 was met with a wide range of responses. Critics included those that see stopping investment in fossil fuels as the only way to fight climate change, and hence saw the swing towards renewables as simply not good enough. Other critics can’t see how bp’s new model can make the same returns as before or simply doubt that bp is capable of the change required. I consider the energy transition as a very complex problem requiring eclectic solutions with companies having to redefine their triple bottom line: societal purpose, environmental impact, and profit for shareholders, all three of which have to be optimized together, just as society has to manage its energy trilemma of cleaner, yet cheaper and more secure energy. In this blog, I analyze what bp’s sell-off of 40% of its oil production by 2030 in exchange for a 17 fold increase in renewable power generation to around 50 gW could mean for their financial performance. My analysis is based on comparing two different energy companies. EOG, one of the best run US shale/tight oil players has assets that if bp is right about the forward oil price, will struggle to make much full-cycle return in the next decade. For the sake of the inquiry, I use EOG as representative of hydrocarbon assets like BPX Energy, bp’s shale business in the US, and assume this is the kind of low return, capital intensive business that will be divested. To represent the other part of the exchange I use NextEra, a renewables-biased power generator and investor in infrastructure. While this transformation will need some complex change in the cultural and capability aspects of bp, the results of my inquiry suggest that this particular part of bp’s strategy could be the right answer, but needs great execution to generate distinctive shareholder value. There is an interesting opportunity for US-based oil & gas companies to re-purpose and diversify in a similar way.
Profit with purpose
Last week my past employer for 25 years, bp, laid some more cards on the table about its pivot from being an international oil company (IOC) focused on producing hydrocarbon resources to an integrated energy company (IEC) focused on delivering solutions for customers. Within this purpose change terms of social and environment, two parts of the triple bottom line, there's a lot to like. For example, in my view, electrification of mobility, reducing oil demand, goes hand-in-hand with reducing oil supply. Horse and carriage, if you like. Energy firms of the future need to seek market opportnuities on both the supply and demand sides of the energy spectrum.
But what about profit? bp has committed to continued financial performance while transforming the company into the new model. How can that be achieved? With respect to the financials, perhaps the swing to renewables investment and electricity generation is particularly eye-catching. By 2030, bp aims to build 50 gW of power generation capacity, which is similar to NextEra (NEE), a renewables-biased energy company has now. bp intends to ramp up investment to be spending over $5 billion per year by 2030. At the same time, bp will reduce its oil production by 40%, largely by divestments. In terms of net market share change, bp will reduce its share of global oil demand from 2.2% in 2019 to 1.4% (a 36% reduction in market share) in 2030, while increasing its share of total electricity generation from roughly 0.08% in 2019 to 1.4% (a 17 fold increase in market share) in 2030 (I am using the IEA Sustainable Development scenario for 2030 as my forecast of demand). How might this exchange affect bp’s financials and shareholder return?
Profit model
Figure 1: Total Shareholder Return and Dividend Yield of bp, NextEra and EOG. (Source: Data: Yahoo Finance; Graphic: Capriole Energy).
bp’s profit mechanism for shareholders has traditionally been about dividend yield. In the last five years, with the recovery from the Deepwater Horizon incident completing, bp has been delivering about 6% yield (Figure 1). Last week the dividend per share was halved, but interestingly this may not affect the annual yield that much as the share price has of course been pounded by the oil price crash. A similar phenomenon occurred in 2010, but in a more pronounced way, when the dividend was suspended and halved compared to pre-Deepwater Horizon levels when it was reinstated in 2011. In 2019 bp returned 29% of its cash from operations to shareholders in the form of dividends. In its upstream business, bp has a large proportion of “advantaged” oil (and natural gas) assets that are or will be on development highly effective cash machines, requiring relatively less recycling of operations cash as capital for the drilling of new wells. I think it’s a fairly good assumption that the oil assets to be divested will be the ones with lowest returns potential in the portfolio. These assets will be also the ones with highest cash cost and full-cycle breakeven prices hence the most vulnerable to “stranding”, particularly those yet to be developed.
Tail assets for divestment
bp probably has a variety of “tail assets” to choose from, but for this analysis, I am going to pick on the US shale business, which is nowadays run as a fairly separate entity, BPX Energy. In 2019, after a $10.5 billion acquisition of BHP Billiton’s shale portfolio BPX reported having about 500,000 barrels of oil equivalent production, with 25% of that oil, the rest natural gas. That’s about 13% of bp’s total oil and gas production. I don’t have access to detailed financial information on BPX Energy, except an indication in one presentation that the $10.5 billion acquisition needs a WTI oil price better than $45, and a Henry Hub natural gas price better than $2.25. Instead, I am going to assume, generously, that BPX Energy has the financial performance as EOG, one of the best-run independent shale oil and gas companies in North America. EOG had similar total production in 2019 but has a much larger proportion of more valuable oil, more than two-thirds of the total. Like all shale companies, EOG’s shale wells decline very rapidly after first production and the asset base needs constant new drilling and recycling of cash from operations as capital to sustain let alone grow production. For the majority of EOG’s peers over the last 10 years, this recycling has actually exceeded ops cash, and those companies have had to borrow heavily to maintain, let alone grow production. As a result, even a relatively well-run company like EOG has been unable to deliver substantial cash back to shareholders. In 2019, although it had an admirable Return on Capital Employed (ROCE) of 12% (more than twice bp’s ROCE), EOG only returned 7% of its cash from operations to shareholders, about one-quarter of bp’s overall performance. Fundamentally, sustained production from shale is expensive to deliver and needs oil prices much higher than $55 to meet investors expectations for cash returns as well as paying off debt. Even top shale performer EOG’s prospects don’t look too rosy if bp is correct in its price forecast, expecting Brent crude to average $55 (WTI will be about $5 less) a barrel from now until 2050.
I expect BPX Energy’s financial performance to be poorer than EOG’s, with my reasoning starting with the much higher proportion of less profitable natural gas. I suspect it’s adding very little to bp’s bottom line, and at today’s commodity prices may be loss-making. Nevertheless, in the spirit of this inquiry, I am going to assume that bp sells BPX Energy and other similar assets and apply those funds to the renewables capital budget, which appears to be roughly $25 to $75 billion for the next decade. What would a successful renewables sector look like for bp, and how would it compare to the divested oil assets? To illuminate that possibility, I will compare NextEra to EOG.
Figure 2: Financial performance of EOG and NextEra, two end members of the energy transition mix. bp financials are shown on differently scaled charts for reference (Source: Data: Yahoo Finance; Graphics: Capriole Energy).
NextEra versus EOG
NextEra is the world’s biggest utility company and has a capacity today of about 45 gigaWatts of power generation capacity. They have an aggressive strategy, for example planning to convert two coal-fired plants to natural gas within the recently acquired Gulf Power system, and combining the system with the Florida Power system. NextEra’s investment plan has not been affected by Covid-19 and they plan to invest $5 billion in energy storage in 2021. NextEra has invested about $50 billion in the last decade, at a similar scale to EOG, at $60 billion. Figure 2 puts the key financial performance metrics of the two firms in a head-to-head comparison. The volatility of oil price clearly impacts EOG’s profitability, whereas NextEra’s show steady growth until last year, impacted by the acquisition of Gulf Power. Thus NextEra has made three times more profit (net income) than EOG in the last decade.
The differences in the two businesses really come through when capital recycling and cash returns are considered. While EOG has been much more disciplined about capital expenditure since 2016, the company is still cash flow negative for the last decade. In contrast, NextEra is $6 billion in the black on cumulative free cash flow, despite the big acquisition last year. The recycling of capital also shows up in the capital employed charts on the right-hand side of Figure 2. Because EOG’s resource assets deplete quickly as well as the tangibles in the wells depreciating, the oil company has only $32 billion capital employed at the end of 2019, with accumulated depreciation of $37 billion, compared to the $111 billion capital employed in the renewables-biased company. NextEra’s ability to spin off cash is enhanced as a result, so even though EOG’s ROCE has recently been better than NextEra, the latter has been able to return 30% of cash from operations to shareholders as dividends, and for most of the last decade has had the superior yield (Figure 1).
One further contrast to note before discussing the implications for a renewable power segment in the new bp. EOG’s Weighted Average Cost of Capital (WACC), an estimate of the expected returns for debt and equity, has been rising as a result of increasing perceived risk, from 10.93% at the end of last year to 12.04% in June 2020. With a high point ROCE of 12%, EOG is now in danger of once again destroying value. In contrast, NextEra’s WACC is far less and is declining, from 5.6% at the end of 2019 to 3.57% in June. I suggest it’s reasonable to expect that bp’s renewable projects will attract lower-cost capital than their new oil projects and can be utilized by segregated entities like LightSource-BP.
Implications for bp
Figure 3: Changes in costs to install and generate power from renewables. (Source: IRENA).
The first piece to test with bp’s plan is the commitment to build 50 gW of capacity with investment increasing to over $5 billion per year: is it possible? I don’t have any concerns about bp applying its existing capabilities to the build the project pipeline, regardless of the type. Indeed I regard capabilities like international footprint, project management, energy trading, and capital markets access as good for all seasons. It’s also interesting to note that the context is far different from 20 years ago, when bp last launched itself into alternative energy, as part of the “beyond petroleum” initiative. Of course, now the need for transition has increased because the world has consumed (at a higher rate) 20 years more oil and gas in the meantime. In addition the remaining oil, needed to underpin the transition and manufacture much of equipment used to harvest renewable energy, is becoming more expensive as it becomes more difficult to find and extract. On the other side of the challenge, renewable power has dropped substantially in cost, with the reduction in Solar PV particularly remarkable (Figure 3). So the second time around bp finds itself at the bottom end of a 20-year learning curve rather at the top end. Therefore it should be possible for bp to do a lot better than NextEra who spent roughly $3.1 billion to install every gW of their current capacity. If that’s the case, and bp can capture the value as additional earnings and not give it all away as price reductions to consumers, then it follows that a ROCE performance better than that of NextEra, getting into double digits, is achievable for this business.
Figure 4: A simple exponential growth model of bp’s installation of 50 gW of renewable power generation by 2030 at an average of $1.5 billion per gW.
In Figure 4, I have illustrated the capacity growth challenge with a simple model that assumes further installation cost reductions from the 2019 levels depicted in Figure 3 and a mix that is entirely solar to begin with, then a growing proportion of wind with time. Higher proportions of wind, particularly offshore, will increase the cost per gW, but still maintain a capital efficiency substantially better than the last decade.
There are a few things that need to all go well for bp for this scenario to work, but I conclude it is at least possible for bp to replace a substantial part of its oil production with an equally, if not more profitable and cash generative, renewable generation and infrastructure business segment.
A blueprint for other oil & gas companies?
The European majors are certainly tracking in the same general strategic direction as bp. Exxon-Mobil and Chevron appear to be charting a different course with a continued focus on hydrocarbons. How much that is based on base-country idealogy, perceptions of business opportunity and risk, and concerns about the capabilities needed to deliver is a matter of conjecture. The simple point is that for at least for the moment, Exxon and Chevron are counting themselves out of a number of business opportunities in the energy transition. In the US that leaves the independent oil & gas firms as potential players in this space. Frankly, most of them are non-starters as transition era companies. They haven’t been profitable as oil companies and investors are unlikely to feed those firms capital for alternative energy projects when they’re still waiting for their money back on the conventional investments! A number of these companies are currently struggling with debt-laden balance sheets and don’t have the financial capacity to diversify in any case.
That said, there are few US oil & gas companies that have at least some of the capability and skill, if not the will, to diversify. EOG for example has launched a technology team charged with investigating how renewable energy might help reduce emissions in their oil and gas operations. Companies with a large US footprint in multiple states like EOG have the opportunity to become more focused on providing different energy solutions to customers and hence society. A number of the larger US independents, with reasonably robust financial positions, at least relative to the times, also have deep international and offshore experience which could be important in accessing new markets. In addition to wind and solar, geothermal is now getting a lot of attention as a potential source of clean, but dispatchable baseload electricity. Geoscience, reservoir engineering, and drilling engineering skills and know-how are of course particularly applicable to geothermal resource prospecting and development.
A small number of smaller European oil and gas companies have already taken the plunge towards a complete makeover, with DONG now Orsted and GDF Suez now engie the notable examples. As oil and gas will be a part of America’s mix for decades to come, a diversification model is more likely to be successful in the US. It seems to me that a first moving disruptor is required to break the deadlock between oil & gas on one side of the energy business divide, and the current renewables companies on the other. A US-based integrated energy company. Who will it be?