Drilling wells and lifting fluids to the surface are core skills in the oil and gas industry. Hence could geothermal be a natural fit in the energy transition? This 17-page note finds next-generation geothermal economics can be very competitive, both for power and heat. Pilot projects are accelerating and new companies are forming. But the greatest challenge is execution, which may give a natural advantage to incumbent oil and gas companies.
The development of the geothermal industry to-date is summarized on pages 2-4. We also explain the rationale for geothermal in the energy transition.
The costs of a geothermal projects can be disaggregated across wells (page 5), pumping (page 6-7) and power turbines (pages 8-9). We draw out rules of thumb, to help you understand the energy economics.
The greatest challenge is geological complexity, as argued on page 10. It is crucial to find the best rocks and mitigate execution risks.
Base case economics? Our estimates of marginal costs are presented for traditional geothermal power (page 11), next-generation deep geothermal electricity (page 12) and using geothermal heat directly (page 13).
Leading companies are profiled on pages 14-16, after tabulating 8,000 patents. We also reviewed incumbent suppliers, novel pilots, and earlier-stage companies.
We conclude that geothermal energy is a natural fit for incumbent oil and gas companies to diversify into renewables, and arguably a much better fit than wind and solar (page 17).
Carbon capture is cursed by colossal costs at small scale. But blue hydrogen may be its saviour. Crucial economies of scale are guaranteed by deploying both technologies together. The combination is a dream scenario for gas producers. This 22-page note outlines the opportunity and costs.
The mechanics of carbon capture and storage projects are explained on pages 2-4, assessing the costs of CO2 capture, CO2 transport and CO2 disposal in turn.
However CCS faces challenges, which are outlined on pages 4-5. In particular, CO2 has three ‘curses’ at small scale, which dramatically inflate the costs.
We quantify the three curses’ impacts. They are diffuse CO2 concentrations (pages 6-8), high fixed costs for pipelines and disposal facilities (pages 8-10) and difficulties gathering CO2 from dispersed turbines and boilers (pages 10-11).
The rationale for blue hydrogen is to overcome these challenges with CCS, as explained on page 12.
Different blue hydrogen reactor designs are discussed, and their economics are modelled on pages 13-15. Autothermal reforming should take precedence over steam methane reforming as part of the energy transition.
Midstream challenges remain. But we find they are less challenging for blue hydrogen than for green hydrogen on page 16.
A scale-up of blue hydrogen is a dream scenario for the gas industry. The three benefits are superior volumes, pricing power and acceptance in the energy transition, as explained on pages 17-19.
Leading projects are profiled on page 20, which aim to combine blue hydrogen with CCS.
Leading companies in auto-thermal reforming (ATR) are profiled on page 21, based on reviewing technical papers and over 750 patents.
Aker Carbon Capture’s technology is profiled on page 22. Patents reveal a technical breakthrough, but it will only benefit indirectly from our blue hydrogen theme.
Oil markets look primed for a new up-cycle by 2022, which could culminate in Brent surpassing $80/bbl. This is sufficient to unlock 20% IRRs on the next generation of offshore projects, and thus excite another cycle of offshore exploration and development. Beneficiaries include technology leaders among offshore producers, subsea services, plus more operationally levered offshore oil services. The idea is laid out in our 17-page note.
Our oil market outlook is detailed on pages 2-5, seeing 2Mbpd of under-supply by 2022 and a potential inventory draw of 2.5bn bbls.
>$80/bbl oil prices are needed to instigate a new offshore cycle, as modelled and explained on pages 6-9.
Can’t the next oil cycle be quenched purely by ramping up short-cycle shale, instead of another offshore cycle? We answer this pushback on pages 10-11.
Is another offshore cycle compatible with the energy transition and global decarbonization? We answer this pushback on pages 12-13, with detailed data on CO2 emissions per barrel offshore versus elsewhere.
Who benefits? We present the technology leaders among producers, service companies and emerging technologies on pages 14-17, drawing on our prior patent screens and technical research.
A typical Oil Major can uplift its valuation by 50% through targeting net zero CO2. This requires demonstrating four cardinal virtues, as outlined in our recent research note (below). However, a recurrent question is “how much will it cost?”. This short note presents an answer, concluding that the costs are likely to be worthwhile.
Our starting point is to model a typical Oil Major with 1Mboed of upstream production, 1Mbpd of refining and marketing, a gas marketing business and 5MTpa of annual chemicals production. We estimate this Oil Major would have around 30MTpa of Scope 1&2 emissions, 200MTpa of Scope 3 Emissions, over $4bn pa of sustaining capex and almost c$4bn pa of opex. To rebase these numbers for a Major that produces, say, 2.5Mboed, simply multiply all of the above figures by 2.5x, and you have an approximation.
The costs of lowering Scope 1&2 emissions are calculated using granular examples in our recent research note below. We estimate that the first c10% of CO2 reductions unlock net economic benefits prior to a CO2 price, with average capex costs of $150/Tpa. The next 10% require a $1-100/ton CO2 price and cost $850/Tpa. Another c5% emissions reductions are possible, but require higher CO2 prices and cost $2,250/Tpa.
An additional method to lower Scope 1&2 CO2 emissions is to power c10% of operations with renewables. This will also cost $850/Tpa of CO2 that is saved, based on our economic models of wind and solar projects (below).
Thus a typical Oil Major can eliminate 35% of its Scope 1&2 CO2 emissions through funding efficiency technologies and renewables. The average cost of these CO2 reductions is $850/Tpa. Spread out over a period of 10-years, this would increase the Major’s annual sustaining capex by c20%, we calculate.
The remaining 65% of CO2 emissions would need to be offset using nature based solutions, which screen among the lowest cost and most scalable decarbonization opportunities on the planet. The note below provides a short summary of several hundred pages of our research on the topic.
We estimate an incremental c10% would be added to group opex, through funding nature based solutions to reach net zero, at a conservative cost of $25/ton per carbon credit.
Overall costs are thus seen to be 15% higher for a Major that transitions to net zero, using the combination of options described above (chart below). This is equivalent to $1.2bn pa of incremental annual costs for a typical 1Mboed integrated oil company.
For contrast, if $50/ton global CO2 prices are introduced, and a Major chooses not to decarbonize, we estimate that the same company would incur a 17% annual cost increase. In other words, if you think $50/ton global CO2 prices are likely to come into force within the next decade, it would be lower cost to shift a business towards net zero pre-emptively.
It could be a lot lower cost. For example, the cost increase could be reduced to 7.5% per annum, if (a) the company did not fund the final, 5% most expensive CO2 reductions (b) spaced its spending over 15-years rather than 10-years and (c) could source nature based offsets at the bottom end of our modelled range of $13/ton rather than $25/ton (chart below).
Although costs are increasing by 7.5-15%, as a Major transitions to Net Zero Scope 1&2, this can be more than offset by the virtues identified in our original work: tilting businesses towards value-accretive areas, benefitting from 2pp lower capital costs in financial markets, targeting efficiency gains that uplift economics and commercializing CO2 offsets at an additional margin (to cut Scope 3 emissions).
A more extreme re-shaping of Oil Majors sees them incubating vast new businesses, seeding nature based solutions to climate change, then selling these CO2 credits alongside their fuels, for an additional margin. Assuming that land for reforestation is leased (not purchased outright), then a 1Mboed Oil Major might need to dedicate $400M of new capex and $4bn pa of opex to nature based solutions, representing 10% uplifts to group capex and 100% uplifts to group opex. Although this new activity would be rewarded by 5-10% unlevered IRRs at $15-35/ton commercial CO2 prices.
We conclude that a typical Oil Major can uplift its valuation by 50% through targeting net zero. This requires incurring 7.5-15% higher costs in early years. But the costs will break even, assuming $50/ton long-term CO2 prices, amidst the energy transition.
Fuel retailers have a game-changing opportunity seeding new forests, ourlined in our 26-page note. They could offset c15bn tons of CO2 per annum, enough to accommodate 85Mbpd of oil and 400TCF of annual gas use in a fully decarbonized energy system. The cost is competitive, well below c$50/ton. It is natural to sell carbon credits alongside fuels and earn a margin on both. Hence, we calculate 15-25% uplifts in the value of fuel retail stations, allaying fears over CO2, and benefitting as road fuel demand surges after COVID.
The advatages of forestry projects are articulated on pages 2-7, explaining why fuel-retailers may be best placed to commercialise genuine carbon credits.
Current costs of carbon credits are assessed on pages 8-10, adjusting for the drawback that some of these carbon credits are not “real” CO2-offsets.
The economics of future forest projects to capture CO2 are laid out on 11-14, including opportunities to deflate costs using new business models and digital technologies. We find c10% unlevered IRRs well below $50/ton CO2 costs.
What model should fuel-retailers use, to collect CO2 credits at the point of fuel-sale? We lay out three options on pages 15-18. Two uplift NPVs 15-25%. One could double or treble valuations, but requires more risk, and trust.
The ultimate scalability of forest projects is assessed on pages 19-25, calculating the total acreage, total CO2 absorption and total fossil fuels that can thus be preserved in the mix. Next-generation bioscience technologies provide upside.
A summary of different companies forest/retail initiatives so far is outlined on page 26.
Remote working, digital de-manning, drones and robotics— all of these themes will structurally accelerate in the aftermath of the COVID crisis. Our research outlines their economics and how they can accelerate the energy transition. But this short note considers the safety consequences. They are as significant as COVID itself. And equally worthy of re-casting behaviours, policies and investments.
At the time of writing, the United States has been hardest hit by the COVID crisis out of any country in the world. It has incurred c35,000 fatalities. However, in the past five years, the US has also incurred an average of 35,000 fatalities on its roads each year (below). This is c100 deaths per day. 1 out of every 10,000 people is killed on US roads each year. There are 1.2 death for every 100M vehicle miles driven (and 3.2 trn miles are driven each year).
Likewise, at the time of writing, the US has been hit by 700,000 COVID cases. For comparison, there are 2.6M injuries on US roads each year, and 6.3M traffic accidents. This means 1 out of every 125 people is injured on US roads each year. There are 83 injuries for every 100M vehicle miles driven.
If you believe in working from home to save lives amidst the coronavirus crisis, a similar argument may justify working from home, where possible.
In addition, 5,250 US workers were killed in workplace fatalities in the most recent annual data, equivalent to 1 out of every c30,000 full-time employees. 40% of these deaths occur on roads. Of all the major job categories shown below, the most dangerous is trucking, where 1 out of every 4,000 full-time employees is killed each year.
Looking more granularly, COVID has so far killed 1 out of every 10,000 people in the United States. However, fatality rates range from 1 in 10,000 to 1 in 1,000 for workers in some of the more physically intensive industries (as shown below), which comprise 10% of all the hours worked around the US economy.
Workplace injury rates are 3% across the entire US economy. This is also 10x higher than the number of documented COVID cases so far in the United States.
If you believe in using technology to save lives amidst the coronavirus crisis, a similar argument may justifying greater deployment of autonomous technologies, digital de-manning, drones and droids, across the broader US labor market.
Our research finds that 48% of recent digitization initiatives have materially improved safety (chart below). 60% also materially lowered costs, 55% materially increased output and 24% materially lowered CO2 emissions.
To recycle an example from the note, there is no need for a worker to be placed into harm’s way — climbing a scaffold to inspect a roof or lowered on a harness to inspect the undersides of an oil platform — as remote monitoring, drone and robotics technologies become available. This is why we have recently screened which operators are among the technology leaders, including in digital technologies (chart below).
The importance of remote work, digitization technologies and robotics may sound obvious when framed in the terms above. But they are not being deployed sufficiently. The chart below shows the number of road fatalities in the US, declining at a 3.4% CAGR since 1920. But there has been no progress in the past ten years since 2009. The absolute count of road fatalities in the latest data is no better than in 1960 (below).
Likewise, workplace fatality rates deflated at 3% pa since 1992, but they have also since stalled. No net improvement has occurred since 2009.
Safety matters, during the COVID-crisis, and after the COVID crisis. Remote and digital technologies can play an enormous role, if enabled by policies and embraced by forward-thinking companies. Please contact us if we can help you screen opportunities. And sorry for the morbid tone of this short note.
Leading technologies correlate 50-80% with ROACEs and -88% with costs in the energy industry. Hence, we assessed 6,000 patents from 2018-19, to determine which Energy Majors are best-placed to weather the downturn, benefit from dislocation and thrive in the recovery. This 14-page research note finds clear leaders in onshore, offshore, shale, LNG and digital, while others in the industry may be pulling back from upstream oil and gas.
Pages 2-4 quantify the importance of leading technologies in uplifting energy industry returns and deflating costs, including worked examples.
Pages 4-5 outline the added importance of technologies amidst the current downturn, its evolution and the industry’s potentially rapid recovery.
Page 6 explains how we use patents to identify technology leaders in energy.
Pages 7-13 explain who are the upstream technology leaders: onshore, offshore, in deep-water, unconventionals (shale), LNG and digital technologies. This informs which companies will emerge strongest from the current downturn, and how they may react amidst the dislocation.
Page 14 quantifies how upstream patent filings have changed YoY. Some Majors appear to be backing away from upstream technologies, possibly due to fears over the energy transitions, while others have stepped up their focus.
Digitization offers superior economics and CO2 credentials. But now it will structurally accelerate due to higher resiliency: Just 8% of digitized industrial processes will be materially disrupted due to COVID-19, compared to 80% of non-digitized processes. In this 22-page research report, we have constructed a database of digitization case studies around the energy industry: to quantify the benefits, screen the most digital operators and identify longer-term winners from the supply chain.
Pages 2 outlines our database of case studies into digitization around the energy industry.
Page 3 quantifies the percentage of the case studies that reduce costs, increase production, improve safety and lower CO2.
Pages 4-6 show how digitization will improve resiliency by 10x during the COVID-crisis, stoking further ascent of energy industry digitization.
Page 7 generalizes to other industries, arguing digitization will accelerate the theme of remote working, esepcially in physical manufacturing sectors.
Pages 8-9 screen for digital leaders among the 25 largest energy companies in the world, based on our assessment of their patents, technical papers and public disclosures.
Pages 10-11 identify leading companies from the supply chain, which may benefit from the acceleration of industrial digitization; again based on patents and technical papers.
Pages 12-22 present the full details of the digitization case studies that featured in our database, highlighting the best examples, key numbers and leading companies; plus links to delve deeper, via our other research, data and models.
Scaling up natural gas is among the largest decarbonisation opportunities on the planet. But this requires minimising methane leaks. Exciting new technologies are emerging. This 23-page note ranks producers, positions for new policies and advocates developing more LNG. To seize the opportunity, we also identify 23 early-stage companies and 10 public companies in methane mitigation. Global gas demand should treble by 2050 and will not be derailed by methane leaks.
Pages 2-4 explain why methane matters for climate and for the scale up of natural gas. If 3.5% of methane is leaked, then natural gas is, debatably, no greener than coal.
Pages 5-8 quantify methane emissions and leaks across the global gas industry, including a granular breakdown of the US supply-chain, based on asset-by-asset data.
Page 9-10 outlines the incumbent methods for mitigating methane, plus our screen of 34 companies which have filed 150 recent patents for improved technologies.
Pages 11-13 cover the best new developments in drones and robotics for detecting methane emissions at small scale, including three particularly exciting companies.
Pages 14-15 outline next generation satellite technologies, which will provide a step-change in pinpointing global methane leaks and repairing them more quickly.
Pages 16-20 covers the changes underway in the oilfield supply chain, to prevent fugitive methane emissions, highlighting interesting companies and innovations.
Page 20-21 screens methane emissions across the different Energy Majors, and resultant CO2-intensities for different gas plays.
Pages 22-23 advocate new LNG developments, particularly small-scale LNG, which may provide an effective, market-based framework to mitigate most methane.
It is often said that Oil Majors should become Energy Majors by transitioning to renewables. But what is the best balance based on portfolio theory? Our 7-page note answers this question, by constructing a mean-variance optimisation model. We find a c0-20% weighting to renewables maximises risk-adjusted returns. The best balance is 5-13%. But beyond a c35% allocation, both returns and risk-adjusted returns decline rapidly.
Pages 2-3 outline our methodology for assessing the optimal risk-adjusted returns of a Major energy company’s portfolio, including the risk, return and correlations of traditional investment options: upstream, downstream and chemicals.
Page 4 quantifies the lower returns that are likely to be achieved on renewable investment options, such as wind, solar and CCS, based on our recent modeling.
Pages 5-6 present an “efficient frontier” of portfolio allocations, balanced between traditional investment options and renewables, with different risk and return profiles.
Pages 6-7 draw conclusions about the optimal portfolios, showing how to maximise returns, minimise risk and maximise risk-adjusted returns (Sharpe ratio).
The work suggests oil companies should primarily remain oil companies, working hard to improve the efficiency and lower the CO2-intensities of their base businesses.
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