Published on Tuesday, September 28 2021
Authors : Robert Auers and John Auers

Part 1 – Integrated Oil Company Strategies 

Back in 1970, when Led Zeppelin released, “Hey, Hey, What Can I Do,” (their only song not released on an album), the main issue facing the petroleum industry was whether enough oil could be found to meet the world’s ever-growing thirst for the “black gold.”  The theory of Peak Oil was becoming just as established and on its way to being considered “settled science” back then as climate change caused by human influence is now.  Things have certainly changed in the past five decades, both in the music world and in the petroleum industry.  Led Zeppelin themselves lasted just another decade, disbanding in 1980 after the alcohol induced death of drummer John Bonham and the music world itself has declined significantly in quality and innovation (at least according to these observers) ever since.  As far as the petroleum industry goes, worries of Peak Oil have disappeared, being replaced by the threat of Peak Demand.  This is being driven by the notion that the world has to wean itself of oil consumption to save itself from climate catastrophe – backed up by ever-more ambitious policies to accomplish this Energy Transition.  This leaves companies involved in all segments of the oil industry to ask the question, “Hey, Hey, What Can I Do,” as they seek to adjust their operations and business models to comply with the new policies.  In today’s blog, the first of a multi-part series, we examine the varying strategies Integrated Oil Companies (IOCs) are employing to meet Energy Transition challenges. 

The European and American IOCs have taken markedly different paths with regards to the Energy Transition and required reductions in greenhouse gas (GHG) emissions.  The four major European IOCs (Shell, TotalEnergies, BP, and Equinor) have all committed to become “net-zero” companies by 2050.  In North America, however, Chevron and Exxon have not made the same promises, though they are undertaking significant initiatives to reduce their carbon footprints.  The European IOCs also have, and continue to make, significant investments in various “Green Energy” sectors, especially wind, solar, and grid scale batteries.  Exxon and Chevron, meanwhile, have primarily focused on carbon capture and storage (CCS), biofuels, renewable natural gas, green/blue hydrogen production and, when prudent, powering their own operations with renewable energy.  All of these are related directly to their current petroleum businesses.  CCS allows fossil fuels to become carbon neutral (or even carbon negative), allowing fossil fuels to play a larger role in the Energy Transition.  Biofuels and blue hydrogen (blue hydrogen is steam methane reforming combined with CCS), meanwhile, utilize processes very similar to those currently used in traditional petroleum refining.  Chevron and Exxon, however, are not investing large sums of money into new renewable electricity projects but are instead typically committing to buying power from others who are developing such projects at pre-determined prices.  Despite these investments, the U.S. IOCs have decided to primarily stick to their bread and butter – upstream, downstream, and petrochemicals – while making some comparatively small investments to lower their carbon footprints.  The European IOCs, on the other hand (with the partial exception of Equinor) have committed fundamentally to changing what their companies do and have coupled their new investments in wind, solar, and batteries with divestments of legacy upstream and downstream assets.    To give some perspective of the differences in approach, Chevron recently tripled its low carbon spending plans, and now expects to invest $10 billion in low carbon initiatives by 2028.  Exxon expects to invest $3 billion by 2025.  While these numbers are not inconsequential, they pale in comparison to the $5-$6 billion that Shell and BP each expect to invest annually in such projects. 

“Gonna pack my bags and move on my way” (away from fossil fuels) – European IOCs Transition Away from Fossil Fuels 

Since the beginning of the COVID pandemic, Shell has been perhaps the most dramatic with regards to its shift in outlook regarding the Energy Transition.  This isn’t to say that Shell hadn’t already started down the road of becoming a “greener” company, but they now appear to be fully on board with a slow transition away from being an oil company and toward being a diversified energy company.  As far as the downstream segment is concerned, Shell has expedited its exit from both U.S. and global refining, with the exception of a continued presence in five (previously six) “Energy Parks” – relatively large refining sites integrated with petrochemicals production.  Notably, however, Shell even divested one of these sites with the sale of its share of the Deer Park JV earlier this year, bringing the number of focus sites down to the current five.  Shell’s accelerated exit from North American refining began with the sale of their 157 MBPD Martinez refinery before the onset of the pandemic.  They have since announced the sale of their 145 MBPD Anacortes refinery to HollyFrontier (soon to become HF Sinclair), the 86 MBPD Mobile refinery to Vertex Energy, and their half of the 330 MBPD Deer Park JV to Pemex.  In addition, Shell idled their 235 MBPD Convent refinery after failing to find a buyer for the facility.  While the facility was already unlikely to restart, the damage experienced from Hurricane Ida has decreased the odds of a restart even further.  This leaves Shell with only three operating North American Refineries – Norco (Louisiana), Scotford (Alberta) and Sarnia (Ontario).  Norco currently remains temporarily down due to damage from Hurricane Ida, but it is unlikely to be sold or shut down permanently due to its designation as one of the core Energy Parks together with the nearby Geismar petrochemicals facility.  Likewise, Scotford has also been designated as one of the Energy Parks, and is integrated with other key Shell assets, namely Shell’s Scotford upgrader and petrochemical facilities.  The ultimate fate of Shell’s Sarnia facility, however, remains less clear.  The refinery was being actively marketed between January and October of 2020 and Shell would likely still be willing to part with the refinery at the right price.   

On the upstream side, Shell has also been active in divesting petroleum-based assets. In just the past few days, it announced a $9.5 billion sale of its Permian Basin assets to ConocoPhillips and is in talks to divest its onshore Nigerian assets, two previously core assets for the company.  Shell has also invested heavily in wind (especially offshore wind) and is increasing its investments in renewable diesel production capacity, particularly in Europe (including its recently announced 17 MBPD renewable diesel production facility in Rotterdam).  Finally, Shell operates Europe’s largest green hydrogen production facility, which produces 1.5 MMSCFD of hydrogen via electrolysis.  This is, as most refiners know, a very small plant.  Most hydrogen plants at refineries (using steam methane reforming technology) range in size from ~5 MMSCFD to over 100 MMSCFD.  It’s worth noting that the plant came at an estimated cost of $24 million, an amount of capital that would likely be sufficient to build a 5-10 MMSCFD steam methane reformer.    

While Shell has certainly been aggressive with regards to its approach to the Energy Transition, BP and TotalEnergies have been perhaps even more so.  BP has, in fact, stated a goal of reducing oil and gas production by 40% by 2030.  Further, BP was actually ahead of Shell in devesting most of its U.S. refining capacity, but has held on to three facilities – Whiting (Indiana), Toledo (Ohio/JV with Cenovus), and Cherry Point (Washington); however, BP has considered selling the Cherry Point refinery in the past and also shedding its interest in the Toledo refinery, but in both cases has not been able to achieve an exit at the right price.  BP’s recent sale of its Alaska assets to Hilcorp may further decrease its interest in operating the Cherry Point refinery, making it a likely sale candidate if BP is able to find a buyer.  BP retains a larger, though shrinking presence in European refining, with its only remaining facilities being the 254 MBPD Gelsenkirchen (Germany/JV with Rosneft), 100 MBPD Lingen (Germany), 400 MBPD Rotterdam (The Netherlands), and 110 MBPD Castellon (Spain) refineries.  One or two of these European refineries remain under threat of foreclosure if weak European refining margins persist.  In the rest of the world, BP has closed or divested all of its refineries except for its share in the 50/50 JV with Shell in Durban, South Africa.  Similarly, to Shell, BP is investing heavily in expanding wind electricity generation capacity. 

TotalEnergies has never been as large of a player in U.S. refining as Shell or BP, although at one time it operated several, mostly inland refineries.  The only facility remaining in its U.S. portfolio is the long held 232 MBPD Port Arthur (Texas) refinery.  This is a core facility for the company due largely to its petrochemical integration, and TotalEnergies appears unlikely to divest it completely, although it has expressed interest in bringing in a partner for the refining side.  In the rest of the world, and particularly in Europe (where TotalEnergies holds the majority of its refining capacity), they continue to reduce their refining footprint.  TotalEnergies has also stated a goal of attaining 100 GW of wind and solar production capacity by 2030.  Equinor has always had a much smaller refining capacity than the others discussed and retains just one refinery in Norway and one in Denmark.   

 “I walk the town, keep searching all around” (but can’t find a good ROIC in renewables) – North American IOCs Continue to Focus Primarily on Fossil Fuels 

Exxon and Chevron, meanwhile, have continued to invest in traditional petroleum refining and fossil production, primarily because they see better returns in those areas than in “green” investments.  The COVID pandemic, of course, slowed investment in refining everywhere and accelerated closures, but Exxon is still proceeding with its 250 MBPD Beaumont expansion (though they have delayed the expected start-up date by one year to 2023).  Chevron also recently expanded their U.S. refining footprint with their purchase of the 110 MBPD Pasadena refinery from Petrobras in 2019.  Both of these additions to capacity are linked to both companies’ strong projected growth in LTO production, particularly in the Permian.  These two companies have also been less aggressive in the biofuels segment.  Chevron has made some small investments to allow for coprocessing vegetable oils at its El Segundo refinery, but has stopped short of investing in stand-alone renewable diesel capacity.  The coprocessing allows Chevron to vary the amount of vegetable oil processed at the refinery depending on economics.  Many of Chevron’s other “green” investments, including renewable natural gas production and some portion of hydrogen investments, are also related to generating California Low Carbon Fuel Standard (LCFS) credits, which will be used internally to cover their own LCFS burden.  This is particularly important given that Chevron is the largest refiner in California. Since Exxon does not have a significant LCFS obligation to meet, they have less incentive to invest in these projects, and as a result, have made only small investments in renewable diesel, green/blue hydrogen, and renewable natural gas.  Still, when asked whether Chevron intended to invest in new solar and wind generation capacity, Chevron CEO Mike Wirth recently stated that instead of investing in developing new wind and solar electricity projects, they’d “rather dividend it back to shareholders and let them plant trees.”  Exxon, no doubt, shares a similar view.  As mentioned previously, both companies have touted CCS as a potential path forward for fossil fuels in a low-carbon world.   

The two largest Canadian IOCs – Suncor and Cenovus – have also continued to focus on their traditional business lines of crude oil production, with a particular focus on the Canadian Oil Sands.  Both companies also have some downstream refining capacity, mostly focused on processing a portion of their Canadian production. 

These differences in response to the Energy Transition between European and North American IOCs will lead these companies to look increasingly different as time progresses.  While the major North American IOCs will continue to be “oil companies” long into the future, their European counterparts are increasingly becoming diversified “energy companies” and even, at least to some extent, electric utilities (via their investments in generation capacity).  Meanwhile, these European IOCs have sold assets to smaller independent upstream and downstream companies, some of which are privately owned.  These smaller, more focused companies, tend to be more nimble and less susceptible to outside activist pressure and are typically less focused on their environmental footprint, since they answer to a different set of investors.  As a result, these divested assets may see more investment under new ownership (given the lack of outside activist pressure), allowing them to continue to thrive even while the European IOCs move away from traditional oil and gas. 

In coming segments of the blog series, we will discuss how companies operating in other sectors of the oil industry are responding to Energy Transition pressures.  These will include National Oil Companies, refiners, and midstream companies.