Occidental

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.

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.

Ventures for an Energy Transition?

This database tabulates almost 300 venture investments made by 9 of the leading Oil Majors, as the energy industry advances and transitions.

The largest portion of activity is now aimed at incubating New Energy technologies (c50% of the investments), as might be expected. Conversely, when we first created the data-file, in early-2019, the lion’s share of historical investments were in upstream technologies (c40% of the total). The investments are also highly digital (c40% of the total).

Four Oil Majors are incubating capabilities in new energies, as the energy system evolves. We are impressed by the opportunities they have accessed. Venturing is likely the right model to create most value in this fast-evolving space.

The full database shows which topic areas are most actively targeted by the Majors’ venturing, broken down across 25 sub-categories, including by company. We also chart which companies have gained stakes in the most interesting start-ups.

Oxycombustion: economics of zero-carbon gas?

Oxycombustion is a next-generation power technology, burning fossil fuels in an inert atmosphere of CO2 and oxygen. It is easy to sequester CO2 from its exhaust gases, helping heat and power to decarbonise. We model that IRRs can compete with conventional gas-fired power plants and base case oxycombution costs are 6-8c/kWh.

This data-file models oxycombustion costs, which is a next-generation power generation technology, burning natural gas (CH4) in a pure atmosphere of oxygen, so that power generation cycle yields an output of pure CO2 and H2O.

We have built up our econonic assumptions by reviewing technical papers, public information from leader Net Power, and based on thermodynamic modelling, from the power cycle through to super-critical CO2 compression.

Our model of oxycombustion costs, averaging 6-8c/kWh in our base case, is based on asssumptions for capex, opex, utilization, efficiency, gas prices, oxygen costs and CO2 disposal.

We first looked at NET Power in a research note in 2019, exploring how next-generation combustion technologies could facilitate easier capture of CO2 (note here). However, we updated the model in 2022-23, with further disclosures, released as the technology has progressed, and as Rice Acquisition Corp acquired Net Power.

Reliable and low-carbon baseload power are increasing important in our power grid research. We estimate CO2 intensities of 0.04-0.08 kg/kWh for oxycombustion, including the embedded CO2 of cryogenic oxygen production.

Competition? It is also under-appreciated that the utilization rates of developed world power grids have progressively been falling, inflating unit costs, which generates a growing incentive to self-generate clean and reliable power (note here).

Another key debate is how the reliability of oxycombustion power cycles will compete with smaller-scale CHPs and fuel cells. Fuel cells have historically had high decline rates, averaging 5% per year, but recent fuel cells are slowly improving.

Input assumptions that impact oxycombustion costs can be stress-tested by downloading the model. Further discussion here.

Permian CO2 Emissions by Producer

This data-file tabulates Permian CO2 intensity based on regulatory disclosures from 20 of the leading producers to the EPA in 2018. Hence we can calculate the basin’s upstream emissions, in tons and in kg/boe.

The data are fully disaggregated by company, across the 20 largest Permian E&Ps, Majors and independents; and across 18 different categories, such as combustion, flaring, venting, pneumatics, storage tanks and methane leaks.

A positive is that CO2 intensity is -52% correlated with operator production volumes, which suggests CO2 intensity can be reduced over time, as the industry grows and consolidates into the hands of larger companies.

Solar Use within the Oil Industry?

This data-file tabulates 20 solar projects being undertaken within the oil industry, in order to clean up production and reduce emissions. More projects are needed, as the total inventory will obviate <1% of oil industry CO2 by 2025.

For each project, we estimate total TWH of power generation per annum, the CO2 emissions avoided, the timeline; and we also summarize the project details.

Leading examples include the use of concentrated solar for steam-EOR in Oman and California, Solar PV in the Permian, and leading efforts from specific companies: such as Occidental, Shell, Eni and other Majors.

CO2-EOR in Shale: the economics

We have modelled the economics of CO2-EOR in shale, after interest in this topic spiked 2.3x YoY in the 2019 technical literature. Our deep-dive research into the topic is linked here.

The economics appear positive, with a 15% IRR under our base case assumptions, and very plausible upside to 25-30%.

There is potential to sequester 3.5bn tons of CO2 in shale formations in the US, plus another 40bn tons internationally, for a CO2 disposal fee of c$40/ton, which we have quantified based on the technical literature.

The model also allows you to stress-test your own assumptions such as: oil prices, gas prices, CO2 prices, CO2 tax-credits, compressor costs and productivity uplift. The impacts on IRR, NPV and FCF are visible.

Major technologies to decarbonise power?

leading oil companies for decarbonising the energy system

Leading Oil Majors will play a crucial role in decarbonising the energy system. Their initiatives should therefore be encouraged by policy-makers and ESG investors, particularly where new energy technologies are being developed, which will unlock further economic opportunities to accelerate the transition.

In order to help identify the leading companies, this-data file summarises c90 patents for de-carbonising power-generation. It is drawn from our database of over 3,000 distinct patents filed by the largest energy companies in 2018. These technologies will secure the role of fossil fuels, particularly natural gas, in a decarbonising energy system.

De-carbonising carbon?

Decarbonisation is often taken to mean the end of fossil fuels. But it could become more feasible simply to de-carbonise fossil fuels. This 19-page note explores two top opportunities: next-generation combustion technologies, which can meet the world’s energy needs relatively seamlessly, with zero carbon and little incremental cost. They are ‘Oxy-Combustion’ using the Allam Cycle and Chemical Looping Combustion. Leading Oil Majors support these solutions to create value advancing the energy transition.

Re-Frac Economics. How much uplift?

$economics of re-fracturing shale wells$

This model assesses the production-uplifts and well-level economics of re-fracturing shale wells in the Permian and the Eagle Ford, to improve recovery of previously missed pay. The opportunity is interesting but not quite game-changing.

Economic breakevens are seen at c$45/bbl under our base-case assumptions. The most likely NPV uplift is c$0.5M/well. However higher prices and process-enhancements can unlock $2-3M of NPV10 per well.

Input assumptions are informed by disclosures from Occidental and Devon Energy, the two E&Ps that dominate the technical literature. They are summarised in the ‘notes’ tab. Please download the file to stress-test the assumptions…

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