Shale Research and Data

US shale: outlook and forecasts?

What outlook for US shale in the energy transition? This model sets out our US shale production forecasts by basin. It covers the Permian, Bakken and Eagle Ford, as a function of the rig count, drilling productivity, completion rates, well productivity and type curves. US shale likely adds +1Mbpd/year of production growth from 2023-2030, albeit flatlining in 2024, then re-accelerating on higher oil prices. Our shale outlook is also summarized below.

What outlook for shale in energy transition?

Shale is a technology paradigm where well productivity has risen by 3-7x over the past decade, through ever greater digitization. Shale economics are very strong, with 20% IRRs at $50/bbl oil on shale oil (model here) or at $2.8/mcf on shale gas (model here). We think 100bn bbls of recoverable shale resources remain in the US and ultimately, liquids production could be ramped up from 10Mbpd in 2023 to 15Mbpd by 2030 (note here).

However the US shale industry has shifted its focus towards capital discipline and ESG. US shale averages 10kg/boe on a Scope 1 upstream basis (data here), shale oil averages 25kg/boe on a full Scope 1&2 basis running up to the refinery gate (data here) and 55kg/boe on a refined basis running up to the point of combustion (data here). The spread is wide, after comparing and contrasting 425 companies here and here. The best decarbonization opportunities for shale are mitigating flaring and methane leaks followed by electrification. Ultimately, we think the best operators could reach CO2 neutrality.

The most important questions on shale are how the resource base and well productivity will trend. This has been the topic of our shale research, and our latest views are covered in our 2024 shale outlook. Historically, we have also undertaken large reviews of the pace of shale technology progress, based on technical papers (examples here and here). There are fifty variables to optimize. And we are most excited about big data techniques, fiber optics and shale-EOR.

Modelling US shale production by basin?

Our model for US shale production looks at each of the main basins, using a factor breakdown. Total production in month T1 = Total production in month T0 + new additions – base declines. To calculate new monthly additions, we multiply (a) number of rigs running (b) wells drilled per rig per month (c) wells completed per well drilled (d) initial production of newly completed wells (IP30). And to calculate the base declines, we fit a best-fit type curve onto the new additions from past months. This model has worked quite smoothly for 6-years now, including history going back to 2011 and forecasts going out through 2030.

The Permian basin is the largest US shale oil basin, with 8Mbpd of total liquids production in 2023. Over the past six years from 2017-2023, the Permian basin has seen an average of 340 rigs running, drilling an average of 1.2 wells per rig per month, completing 1.06 wells for every well drilled (DUC drawdown) at an initial production rate of 780bpd (IP30 basis), adding +850kbpd/year of new supply to global oil markets. We still see strong growth potential, and the Permian could reach 12Mbpd of total liquids production by 2030, amidst higher activity and oil prices. All of these variables can be stress-tested in the model.

The Bakken is the second largest US shale oil basin, with 1.3Mbpd of total liquids production in 2023. Over the past six years from 2017-2023, the Bakken has seen an average of 40 rigs running, drilling an average of 1.9 wells per rig per month, completing 1.15 wells for every well drilled (DUC drawdown) at an initial production rate of 780bpd (IP30 basis), adding +20kbpd/year of new supply to global oil markets. We see a plateau through 2030.

The Eagle Ford is the third largest US shale oil basin, with 1.1Mbpd of liquids production in 2023. Over the past six years from 2017-2023, the Eagle Ford has seen an average of 60 liquids-focused rigs running, drilling an average of 2.1 wells per rig per month, completing 1.22 wells for every well drilled (DUC drawdown) at an initial production rate of 680bpd (IP30 basis), but liquids production has actually declined, especially during the volatility of the COVID years. We see a plateau through 2030.

Challenges and controversies for US shale?

The main revisions to our shale production models have been because of lower activity, as capital discipline has entrenched through the shale industry. The chart below shows our forecasts for activity levels at different, prior publication dates of this model. We have compiled similar charts for all of the different variables and basins, in the ‘revisions’ tab, to show how our shale numbers have changed.

Our shale outlook for 2023-2030 sees the potential for +1Mbpd of annual production growth as the industry also generates $150-200bn per year of annual free cash flow. You can stress test input variables such as oil prices in the model.

We have also modeled the Marcellus and Haynesville shale gas plays, using the same framework, in further tabs of the data-file. Amazingly, there is potential to underpin a 100-200MTpa US LNG expansion here, with just 20-50 additional rigs. Although recently we wonder whether the US blue hydrogen boom will absorb more gas and outcompete LNG, especially as the US Gulf Coast becomes the most powerful clean industrial hub on the planet (note here).

International shale? We have found it harder to get excited about international shale, but there is strong potential in other large hydrocarbon basins, if European shale is ever considered to rescue Europe from persistent gas shortages, and less so in China.

Please download the data-file to stress-test our US shale production forecasts by basin.

Shale oil: fractured forecasts?

This 17-page note makes the largest changes to our shale forecasts in five years, on both quantitative and qualitative signs that productivity growth is slowing. Productivity peaks after 2025, precisely as energy markets hit steep undersupply. We still see +1Mbpd/year of liquids potential through 2030, but it is back loaded, and requires persistently higher oil prices?

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 500 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 1 GB of data, disclosed by the operators of 500 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 85% of US onshore oil and gas from 2022, including 8.8Mbpd of oil, 100bcfd of gas, 25Mboed of total production, 462,000 producing wells, 800,000 pneumatic devices and 62,000 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 2022 emitted 10kg/boe of CO2e. Across the entire data-set, the lower quartile is below 3kg/boe. The upper quartile is above 12kg/boe. The upper decile is above 20kg/boe. And the upper percentile is above 70kg/boe. There is very heavy skew here (chart below).

CO2 intensity of US oil and gas production.

The main reasons are methane leaks and flaring. The mean average asset in our sample has a methane leakage rate of 0.16% in 2022 (down from 0.21% in 2021) and a flaring intensity of 0.024 mcf/boe (down from 0.028 mcf/boe in 2021). 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.

Flaring intensity of US oil and gas production by basin. Bakken fields flare most, while Appalachian fields flare the least.

US CO2 intensity has been improving since 2018. CO2 intensity per basin has fallen by 21% over the past three years, while methane leakage rates have fallen by 22%. Activity has clearly stepped up to mitigate methane leaks.

CO2 intensity of US oil and gas production by basin. A comparison of 2021 and 2018.

Progress was made in 2022 in switching out bleeding pneumatic devices. Comparing 2022 vs 2021, our data-file contains 33,000 more wells (+8%), yet -3,100 fewer high-bleed pneumatic devices (-35%) and 14,000 fewer intermediate-bleed pneumatic devices (-3%). You can see who has most bleeding pneumatics still to replace in the data-file.

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).

CO2 intensity of oil and gas production in the Bakken basin.

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.

Flaring intensity of oil and gas production in the Permian basin.

All of the underlying data is also aggregated in a useful summary format, across the 500 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.

European shale: an overview?

Overview of European shale. Europe has 15 TCM of technically recoverable shale gas resources according to an assessment from the EIA in 2013, which remains the best overview, almost ten years later. This data-file simply aims to provide a helpful overview of the different countries’ rocks and above-ground challenges, tabulating the main formations, TOCs, depths, thicknesses, clay contents and exploration history.

Our first conclusion is how much the world has changed since the early days of European shale exploration, a decade ago, including ten years’ proof that US shale has not caused an entire continent to die a mysterious death. Indeed, US industry, has seemed to gain a mysterious new life. While Europe is now so short of energy that we may need to scale our industry back at a time when we would rather be re-shoring strategic supply chains).

While Europe is now trying to import vast amounts of US shale gas to Europe as LNG (note here), another complementary option, we think is to re-visit the possibilities of European shale; especially in Eastern Europe, which has large, high-quality shale resources, high continued reliance on coal (Poland, Bulgaria) and a growing desire to avoid Russian reliance.

Ukraine has the best shale resources in all of Europe: 4.5% TOC, 1.15% maturity (gas window), low clay and moderate over-pressure. Shell tested these rocks and obtained results good enough to sign a $10bn development agreement that could ramp output up to 20bcm per year. At the time, Ukrainian politicians stated the country could ultimately run a “gas surplus”. This was 2013. Just before Russia’s first invasion. And this Continent-leading Dniepr-Donets shale resource lies in the East of the country, bounded by Kharkiv and Donetsk, near to the current fighting. Which may or may not be a coincidence.

It is difficult to know to what extent Russia fomented broader opposition to European shale. Some of the hysteria seems almost farcical in retrospect. In Romania, in 2013, as Chevron signed an exploration contract, one town saw the largest protest in its entire history (16% of the population), as 8,000 people took to the streets with signs reading “Don’t kill our children”.

(We humbly submit that if you are writing this on a placard, you might not understand what shale gas involves. The simple goal is to produce energy safely, with 50-60% lower carbon than coal (note here) at a marginal cost of $1.5-2/mcf (model here)).

Other countries with good potential, held back only by sentiment are Romania, Germany, UK, Bulgaria and Spain. We remain more cautious on the potential in Sweden and Denmark (the Alum has expelled its gas), Netherlands (population density), Poland (clay makes the rock harder to fracture) and France (continuing to rely on nuclear is its best low-carbon option).

To read more about our overview of European shale, please see our article here.

Marcellus shale: well by well production database?

Average production curves of shale gas wells in Marcellus over the years. Every year productivity improves

This data-file tracks Marcellus shale well productivity, by tabulating the monthly output from 13,000 wells across the Pennsylvania Marcellus, from 2015 to mid-2024. Average IP rates across the basin have risen at a 13% pa CAGR, from around 5mmcfd in 2015 to 16.5mmcfd in the 2Q24. However, activity and productivity differ starkly by operator.

This data-file tracks Marcellus shale well productivity, by tabulating the monthly output from 13,000 wells across the Pennsylvania Marcellus, from 2015 to mid-2024, based on publicly available data from the Pennsylvania Department of Environment Protection.

It is a very large amount of data. And it contains some absolute monster wells (example below). Production profiles are available for each of 13,000 wells, and we have also averaged the data into type curves, year by year, which informs our shale gas economics model.

An example of a monster shale gas well's productivity over time

Activity levels have also slowed by 40% over time, with a peak of 850 wells drilled in 2018, slowing to 510 wells in 2023. What has enabled activity to slow down is the improvement in well productivity. Average IP rates across the basin have risen at a 13% pa CAGR, from around 5mmcfd in 2015 to 16.5mmcfd in 2Q24.

Marcellus production by operator can be tabulated by matching up each well to its operator, and then adding up and averaging the output across all wells. Hence for each operator, we have tabulated production, well stock, activity levels, average well production, IP rates.

The basin has grown more concentrated over time, with the largest six companies accounting for c60% of production in 2015, while the largest five make up c75% in 2023 (including M&A impacts). They are Expand, EQT, Coterra, Range and National Fuel Gas.

Gas production in the Pennsylvania Marcellus by company over time From 2015 to October 2024.

As an example of the consolidation, Rice was purchased by EQT for $8.2bn in 2017. Coterra was formed via the $9bn merger of Cabot and Cimarex in 2021. Chief was acquired by Chesapeake for $2.6bn in 2022. Most recently, Chesapeake and Southwestern announced a $7.4 billion all-stock merger in January-24, thereafter re-branding as Expand Energy.

First tier operators are visible in the data-file. They have come to dominate as the basin consolidated, while they also achieve higher IP rates, and have been able to do more with less. Their IP rates average 40-130% higher than for the tail of c50 smaller producers.

Full data on each producer, and its Marcellus well productivity are in the data-file. We see rising demand for US gas, as part of our medium-term US gas outlook, and as captured in our US energy model.

US natural gas: the stuff of dreams?

Methane emissions from pneumatic devices: by operator, by basin?

Methane emissions from pneumatic devices across the US onshore oil and gas industry comprise 50% of all US upstream methane leaks and 15% of all upstream CO2. This data-file aggregates data on 800,000 pneumatic devices, from 300 acreage positions, of 200 onshore producers, in 12 US basins.

Pneumatic devices are valves and pumps that are actuated by pressurized natural gas, widely used in the oil and gas industry, and numbering around 800,000 in the US in 2021, across 22Mboed of production that we are tracking, acreage position by acreage position, based on EPA disclosures.

The problem with pneumatic devices is that they leak methane, a greenhouse gas, emitting an average of 1 ton of methane per device per year, explaining 20MTpa of US CO2e emissions, equivalent to 2.5 kg/boe of Scope 1 CO2 emissions, or around half of the CO2 attributed to methane leaks in the US upstream oil and gas industry.

So over time, we expect bleeding pneumatic devices to be phased out in the US, especially ‘high bleed’ pneumatic devices, which emit around 5 tons of methane per device per year, as part of the industry’s growing efforts to mitigate methane. (This note also covers companies in the supply chain to help mitigate methane emissions from pneumatic devices, including a switch to electrically actuated devices, example here).

We have been tracking methane emissions from pneumatic devices in the US oilfield since 2018, although the latest data from 2021 do not show much improvement in aggregate (chart above).

The average well that is in operation in the US oilfield is associated with 1.4 bleeding pneumatic devices, although it is highest in basins that produce similar quantities of both oil and gas, at 2-3 pneumatic devices per well in the MidCon, Anadarko basin and Eagle Ford, while it is lowest in the Marcellus and Utica, at 0.75 pneumatic devices per well, as pure-play gas producers primarily aim to monetize not leak their gas.

Methodology. Note that in the chart above we have adjusted the data into ‘intermediate equivalents’. For example, the average low-bleed pneumatic device emits 9x less methane than the average intermediate-bleed device, and so we consider 9 low-bleed devices “equivalent” to one intermediate bleed device.

Pneumatic devices per well also vary vastly by operator. The best operators have well below 0.5 pneumatic devices per well, while some have shifted almost entirely to electrically actuated devices that use no methane.

Leaders include Pioneer, EOG, Diamondback, with no high-bleed pneumatic devices, and very few intermediate-bleed pneumatic devices across their portfolios.

On the other side of the spectrum are operators with 2-7 bleeding pneumatic devices per well. We have wondered in the past whether regulations are going to tighten and clamp down upon bleeding pneumatic devices, especially high bleed pneumatic devices, and create large capex burdens on companies with methane-leaking assets.

In one case, it is surprising to us that a well-known E&P company, advertising itself as one of the ‘greenest’ operators in the US still has over 1,000 high-bleed pneumatic devices across its asset base, or over 10% of all the high-bleed pneumatic devices in the US.

Underlying data into the CO2 intensity of US oil and gas producers is aggregated by basin, by producer and by acreage position here. Another large source of methane leaks is flaring, covered in our note here.

US shale gas: the economics?

Economics of US Marcellus shale gas production

Shale is a technology paradigm where well productivity has risen by 3-7x over the past decade, through ever greater digitization. Shale economics are very strong, with 20% IRRs at $50/bbl oil on shale oil (model here) or at $2.8/mcf on shale gas. We think 100bn bbls of recoverable shale resources remain in the US and ultimately, liquids production could be ramped up from 10Mbpd in 2023 to 17Mbpd by 2030 (note here), and most of this will be needed as energy shortages loom.

This data-file breaks down the economics of US shale gas, in order to calculate the NPVs, IRRs and gas price breakevens of future drilling in major US shale basins (predominantly the Marcellus).

Underlying the analysis is a granular model of capex costs, broken down across 18 components. Our base case conclusion is that a $2/mcf hub pricing is required for a 10% IRR on a $7.2M shale gas well with 1.8kboed IP30 production.

Economics are sensitive. There is a perception the US has an infinite supply of gas at $2/mcf, but rising hurdle rates and regulatory risk may require higher prices. For a similar model of shale oil, please see our model here.

In our energy transition models US shale likely adds +1Mbpd/year of production growth from 2023-2030, albeit flatlining in 2024, then re-accelerating on higher oil prices.

Amazingly, there is potential to underpin a 100-200MTpa US LNG expansion, with just 20-50 additional rigs. Although recently we wonder whether the US blue hydrogen boom will absorb more gas and outcompete LNG, especially as the US Gulf Coast becomes the most powerful clean industrial hub on the planet (note here).

Shale productivity: snakes and ladders?

Unprecedented high-grading is now occurring in the US shale industry, amidst challenging industry conditions. This means 2020-21 production surprising to the upside, and we raise our forecasts +0.7 and +0.9Mbpd respectively. Conversely, when shale activity recovers, productivity could disappoint, and we lower our 2022+ forecasts by 0.2-0.9 Mbpd. This 7-page note explores the causes and consequences of this whipsaw effect.

What outlook for shale in energy transition?

Modelling US shale production by basin?

Challenges and controversies for US shale?

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