Oil in the energy transition

Development capex: long-term spending from Oil Majors?

This data-file tabulates the five ‘Big Oil’ Super-Majors’ development capex from the mid-1990s, in headline terms (billions of dollars) and in per-barrel terms ($/boe of production). Real development capex quadrupled from $6/boe in 1995-2000 to $24/boe in 2010-15, and has since collapsed to $10/boe.

The peer group of Super-Majors comprises ExxonMobil, Chevron, BP, Shell and TOTAL, which comprise c10% of the world’s oil production and 12% of the world’s gas production. As a good rule of thumb, this group can be thought of as c10% of global production.

Development capex by region: gaining share? The US has always been the most favored destination, attracting c25% of all development capex, both offshore (e.g., Gulf of Mexico) and increasingly for short-cycle shale. However, the share of these companies’ development capex in the US has averaged around 32% in the past three years.

Development capex by region: losing share? Development projects in Africa and Europe have fallen most out of favor. Development capex in Africa peaked at $17bn in 2009, almost 25% of the group’s total development capex, and has since fallen back to $5bn per year, or 8% of the group’s total development capex.

It is somewhat terrifying to consider that the industry needed to spend an average of $15/boe (real terms) on development capex in order to hold its organic production “flattish” (including some large acquisitions in 2014-17, such as Shell buying BG).

Another scary data-point is that this peer group of Super-Majors spent $18/boe (real) on development projects in the decade from 2004-14 (which is 80% more than recent levels of spending) yet its net production declined by 1.5% per year over this timeframe.

Similar data for the Super-Majors’ exploration capex over time is tabulated here.

Under-investment across the entire energy industry may foreshadow a sustained shortage of energy, especially if 50% lower-carbon gas is intended to replace coal as part of the energy transition, per our roadmap to net zero. Hence one cannot help wondering about energy shortages, energy pragmatism and our fears of another up-cycle.

This data-file aggregates the Oil Majors’ development capex, across ExxonMobil, Chevron, BP, Shell and TOTAL disclosures, apples-to-apples, back to 1995, based on supplementary oil and gas disclosures, in the SEC’s EDGAR archives.

Offshore vessels: fuel consumption?

This database tabulates the typical fuel consumption of offshore vessels, in bpd and MWH/day. We think a typical offshore construction vessel will consume 300bpd, a typical rig consumes 200bpd, supply vessels consume 150bpd, cable-lay vessels consume 150bpd, dredging vessels consume 100bpd and medium-sized support vessels consume 50bpd. Examples are given in each category, with typical variations in the range of +/- 50%.

Global oil demand: breakdown by product by country?

This data-file breaks down global oil demand, country-by-country, product-by-product, month-by-month, across 2017-2022. The goal is to summarize the effects of COVID, and the subsequent recovery in oil markets. Global oil demand is hitting new highs, even though several product categories are still not fully recovered.

Overall, global oil demand fell by -22Mbpd at trough in April-2020; and by an average of -9Mbpd YoY in 2020 overall. In 2021, two thirds of the lost demand recovered, but global oil demand was still -3Mbpd below 2019 levels. However, 2022 demand most likely hit all-time highs (chart above).

Comparing 2022 versus 2019. We think total oil demand was around 100Mbpd in both years. But strikingly, air travel is nowhere close to having fully recovered. Jet fuel demand remains -2Mbpd below 2019 levels, portending possible upside in 2023+. Relatedly, gasoline demand remains -0.8Mbpd below 2019, of which the decline is entirely in the developed world, and probably also linked to travel activity remaining somewhat disrupted.

All other categories are making new highs. In 2022, distillate demand was +0.6Mbpd above 2019 levels (-0.6Mbpd in the OECD, +1.2Mbpd in non-OECD, and a lot of the charts in the data-file show a trend like the one below).

Likewise, in 2022 versus 2019, naphtha use was +0.5Mbpd above, LPG use was +0.4Mbpd above and NGL use was +0.4Mbpd above (all three of these lines feed into global plastics demand). Fuel oil use was +0.4Mbpd above (chart below).

Overall this data-set confirms our fears that renewables, EVs and other new energies would all need to ramp about 3-5x faster than their likely run-rate in the 2020s to stop oil demand (and even coal demand) from continuing to rise (note here).

This matters because in 2020, many commentators were stating that 2019 would have been the all-time peak for fossil fuels, that demand would never recover to pre-COVID levels, and that the world should therefore “stop investing” in hydrocarbons. Even today, we worry that some commentators are still materially over-estimating future efficiency gains in the global energy system (note here). A lack of pragmatism worries us (note here). Long-term energy shortages worry us (note here). Our LT oil demand model is here.

However, there is some uncertainty in this data-set, as the original data-source (JODI) only covers 80% of the oil market. We estimate the remaining countries by taking a proxy from “analogous countries” (the methodology is described in our original report here). Meanwhile some of the reported data look suspect. Most notably, “other product demand” in China is a very large and erratic data-line.

Flaring reduction: fire extinguishers?

Controversies over oil industry flaring are re-accelerating, especially due to the methane slip from flares, now feared as high as 8% globally. The skew entails that more CO2e could be emitted in producing low quality barrels (Scope 1) than in consuming high quality barrels (Scope 3). Insane environmental impacts are entirely preventable. This 10-page note explores how, across producers, energy services and new technologies.

US CO2 and Methane Intensity by Basin

The CO2 intensity of oil and gas production is tabulated for 425 distinct company positions across 12 distinct US onshore basins in this data-file. Using the data, we can break down the upstream CO2 intensity (in kg/boe), methane leakage rates (%) and flaring intensity (mcf/boe), by company, by basin and across the US Lower 48.

In this database, we have aggregated and cleaned up 957 MB of data, disclosed by the operators of 425 large upstream oil and gas acreage positions. The data are reported every year to the US EPA, and made publicly available via the EPA FLIGHT tool.

The database covers 70% of the US oil and gas industry from 2021, including 8.8Mbpd of oil, 80bcfd of gas, 22Mboed of total production, 430,000 producing wells, 800,000 pneumatic devices and 60,000 flares. All of this is disaggregated by acreage positions, by operator and by basin. It is a treasure trove for energy and ESG analysts.

CO2 intensity. The mean average upstream oil and gas operation in 2021 emitted 10kg/boe of CO2e. Across the entire data-set, the lower quartile is below 3kg/boe. The upper quartile is above 13kg/boe. The upper decile is above 20kg/boe. And the upper percentile is above 70kg/boe. There is very heavy skew here (chart below).

The main reasons are methane leaks and flaring. The mean average asset in our sample has a methane leakage rate of 0.21%, and a flaring intensity of 0.03 mcf/bbl. There is a growing controversy over methane slip in flaring, which also means these emissions may be higher than reported. Flaring intensity by basin is charted below.

US CO2 intensity has been improving since 2018. CO2 intensity per basin has fallen by 17% over the past three years, while methane leakage rates have fallen by 22%. Activity has clearly stepped up to mitigate methane leaks.

(You can also see in the data-file who has the most work still to do in reducing future methane leaks. For example, one large E&P surprised us, as it has been vocal over its industry-leading CO2 credentials, yet it still has over 1,000 high bleed pneumatic devices across its Permian portfolio, which is about 10% of all the high-bleed pneumatics left in the Lower 48, and each device leaks 4 tons of methane per year!).

Most interesting is to rank the best companies in each basin, using the granular data, to identify leaders and laggards (chart below). A general observation is that larger, listed producers tend to have lower CO2 intensity, fewer methane leaks and lower flaring intensity than small private companies. Half-a-dozen large listed companies stand out, with exceptionally low CO2 intensities. Please consult the data-file for cost curves (like the one below).

Methane leaks and flaring intensity can also be disaggregated by company within each basin. For example, the chart below shows some large Permian producers effectively reporting zero flaring, while others are flaring off over 0.1 mcf/bbl.

All of the underlying data is also aggregated in a useful summary format, across the 425 different acreage positions reporting in to EPA FLIGHT, in case you want to compare different operators on a particularly granular basis.

Flaring reduction: screen of service and equipment companies?

This data-file is a screen of companies that reduce gas flaring emissions, either by avoiding routine flaring directly, or by reducing the ESG impacts of unavoidable flaring. The landscape is broad, ranging from large, listed and diversified oil service companies with $30bn market cap to small private analytics companies with <$10M pa of revenues.

Our screen explores a dozen companies that reduce gas flaring and can help to mitigate flaring; whether they are public or private, their size, headcount, focus, revenues, valuation, and an overview of their technology. But this is just a sample of names, to illustrate the breadth of the theme.

Breadth and the giant furnace model. There is a dangerous temptation to assume that oil industry flaring is simple. It is vastly, complex. Flaring rate by country range from effectively nil in industry-leading Norway and Saudi Arabia through to 0.7 mcf/bbl in the highest-flaring producing countries. And even where flaring does occur, beware assuming there is some kind of giant furnace in the desert of Texas where the shale oil industry ‘chooses to burn off waste gases’.

The reality is borne out by this screen. Avoiding flaring requires oilfield service equipment to separate out gas from produced oil. Moving it away from the well site then requires compressors, pipelines, small-scale LNG, CNG or using gas in basin, e.g., for dual-fuel rigs or frac services or in-basin power generation. Sometimes it is not possible to separate the gas, and fluids must be moved by multi-phase pumps. Sometimes wells are flowed back before gas infrastructure is available. Sometimes, despite extensive separation, gas still flashes off in storage tanks. Sometimes flaring is unavoidable, and the goal is simply to ensure all methane is effectively destroyed in the flare, and not leaked away.

The emissions tab contains a similar calculator for the CO2 intensity of flaring, depending on the gas-oil-ratio, percent of gas that is flared, combustion efficiency and timeframe over which methane emissions are considered. We believe that poorly-managed flaring operations from some oil production sites around the world will emit more CO2 than burning the resultant oil itself, due to methane slip. Whereas emissions from flaring are negligible for high-quality producers.

Exploration capex: long-term spending from Oil Majors?

This data-file tabulates the Oil Majors’ exploration capex from the mid-1990s, in headline terms (in billions of dollars) and in per-barrel terms (in $/boe of production). Exploration spending quadrupled from $1/boe in 1995-2005 to $4/boe in 2005-19, and has since collapsed like a warm Easter Egg. One cannot help wondering about another cycle?

The peer group comprises ExxonMobil, Chevron, BP, Shell and TOTAL, which comprise c10% of the world’s oil production and 12% of the world’s gas production. As a good rule of thumb, this group can be thought of as c10% of global production.

This peer group quadrupled its exploration expenditures, from $5bn pa spent on exploration in 1995-2005 to an average of $20bn pa on exploration at the peak of the 30-year oil and gas cycle in 2010-2015. Exploration spend ramped from $1/boe to $4/boe over this timeframe. It has since fallen back to $1/boe, or around $1bn per company pa in 2022.

The US has always been the most favored destination, attracting c25% of all exploration investment, both offshore (e.g., Gulf of Mexico) and increasingly for short-cycle shale. During the last oil and gas cycle, the largest increases in exploration investment occurred in Africa, other Americas, Australasia; and to a lesser extent in Europe and the Middle East.

One possible scenario for the future is that this peer group will continue to limit its exploration expenditures to the bare minimum, below $1bn per company per year, or below $1/boe of production; under the watchwords of “capital discipline”, “value over volume” and “energy transition”.

However, it is somewhat terrifying to consider that the industry needed to spend an average of $2.5/boe on exploration from 2005-2019 in order to hold its organic production “flattish”.

Under-investment across the entire industry may foreshadow a sustained shortage of energy, especially if 50% lower-carbon gas is intended to replace coal as part of the energy transition, per our roadmap to net zero, or more pressingly as Europe faces sustained gas shortages. Hence one cannot help wondering if industry-wide exploration capex in the 2020s and 2030s is going to resemble the 2000s and 2010s?

This data-files aggregates the Oil Majors’ exploration capex, across ExxonMobil, Chevron, BP, Shell and TOTAL disclosures, apples-to-apples, back to 1995.

Weird recessions: can commodities de-couple?

In a ‘weird recession’, GDP growth turns negative, yet commodity prices continue surprising to the upside. This 10-page note explores three reasons that 2022-24 may bring a ‘weird recession’. There is historical precedent, prices must remain high to attract new investment and buyers may stockpile bottlenecked materials. How will this affect different industries?

How do commodities perform during recessions?

How do commodities perform in recessions? Industrial metals are usually hit hardest, falling 35% peak-to-trough. Energy price spikes partly cause two-thirds of recessions, then typically trade back to pre-recession levels. Precious metals, mainly gold, tend to appreciate in financial crises. Data are compiled in this file, across recessions back to 1970.

Industrial metals are typically hit hardest, declining 35% peak-to-trough and still trading -20% lower in the year after the recession ended compared to the year before it began.

Energy is more mixed, typically declining -23% peak-to-trough, but in two-thirds of the recessions, energy prices continued spiking for an average of 6-months after the recession started, suggesting that energy shortages were a cause.

Gold is an outlier. In the median average recession, real gold prices have been +5% higher in the 12-months following the end of the recession, compared to the 12-months preceding its start. Other precious metals tended to be 10-15% lower, industrial metals tended to be 20-30% lower, and energy commodities tended to be “flat”.

Each recession is unique, hence while the averages are useful, we think it may be even more useful to delve into the underlying tabs of this data-file, to review individual commodities in individual recession contexts.

The Great Recession of 2008-09 has become an archetype for asset price performance during recessions, for those of us who lived through it. However, in commodity terms, it was unusually severe. Six of the twelve commodities in this data-file experienced their worst peak-to-trough decline of any recession, while another three of the twelve experienced their second worst declines.

Methodology. We downloaded monthly commodity prices from the World Bank pink sheets. We then translated these nominal prices into real terms using the US CPI. Next, we downloaded a list of recession dates from the NBER. We indexed commodity prices at 100 at the start of each recession. Then we plotted the pricing performance 12-months prior to the start of the recession through to 12-months after the end of each recession. We computed three metrics for each commodity in each recession: peak-to-trough price decline, TTM average-to-trough price decline, and average pricing in the year after the recession had ended versus average pricing in the year before the recession began. Finally, we aggregated the data for each recession and took an average.

How do commodities perform in recessions? Commodities assessed in the data-file include oil, natural gas, coal, corn, iron ore (precursor to steel), aluminium, copper, zinc, nickel, platinum, silver and gold.

Recessions assessed in the data-file include the Global Financial Crisis of 2007-09, the collapse of the Dot Com bubble in the early 2000s, after the First Gulf War in the early 1990s, after the 1980+ oil shock, after the 1973-74 oil price shock, and the monetary-induced recession of 1969-70. We have also published detailed reviews into energy crisis and bursting bubbles.

World’s largest energy assets: by category and risk?

World’s largest energy assets by type. The size and risk of global energy assets are assessed in this data-file, which focuses in upon the largest energy assets in the world, the energy derived from them (in TWH) and their resultant risk profiles. Our workings and conclusions are presented in the data-file.

For example, the analysis includes a description and a risk assessment for each of: the world’s largest oil terminal (1,100TWH pa of useful energy supplied to the world), the world’s largest LNG plant (700TWH pa), oilfield (650TWH pa), oil pipeline (500TWH pa), gas pipeline (400 TWH pa), refinery (200TWH pa), coal mine (200TWH pa), hydro plant (100 TWH pa), nuclear plant (50TWH pa), offshore wind farm (4TWH pa) or solar asset (4TWH pa).

The main risks for large assets are one-offs, such as outages, political disputes and outright sabotage. But the energy industry is also shifting to smaller assets (renewables, shale), where the main risks are systemic ones that impact all assets, such as particularly non-windy years or possible kamikaze policies such as fracking bans. Climate change likely also creates higher risks to energy security due to drier weather and hurricanes.

Overall, the analysis suggests it is not unrealistic to fear that global energy supplies could come in 2% lower than base case models, which are linked here.

Further discussion on the world’s largest energy assets, and our conclusion on a particularly large and important gas, oil, shale, nuclear, wind and solar assets are linked here.

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