U.S. supermajor Chevron Corporation will only take equity stakes in LNG liquefaction terminals when necessary to get its gas to market, CEO Mike Wirth said on the firm’s second quarter results call.

Wirth noted that the midstream part of the value chain had the potential to be very capital intensive and deliver low returns.

“We’re really looking to drive high returns, not necessarily to own assets for the sake of control, unless it creates a differentiated value proposition,” he said.

In the U.S., Chevron signed two deals last year with LNG developers Cheniere Energy, Inc. and Venture Global LNG for a combined four million metric tonnes per annum (mtpa) that will provide an outlet for natural gas flowing from its Permian Basin shale holdings in West Texas and New Mexico, without it having to take a stake in terminals.

Because it has its own shipping portfolio Chevron can lift the cargoes on a FOB basis and sell them into international gas markets.

Outside the U.S., Chevron has some stakes in LNG projects — notably in Angola and Australia. It is also evaluating a floating LNG project offshore Israel that would process gas from the Leviathan field.

“In places where you’ve got remote gas where you need to be in the entire value chain and you can create an economic model that supports the investments, we’ve done that,” said Wirth. “In other locations where you’ve got other people that will put capital into the midstream assets … that’s certainly a model that helps us support our aspiration to drive higher returns.”

Chevron has experienced several challenges with its Gorgon LNG liquefaction facility offshore Australia. It was licensed to build the export plant on the condition it would inject at least 80 per cent of the CO2 it emitted. But it injected just a third of the CO2 it produced in the 2021-2022 financial year due to issues with its water management system. Chevron was required to purchase a significant volume of carbon offsets to make up the shortfall.

Chevron’s Angola LNG has also suffered technical issues and was shut down for more than three years from 2015 to 2019.

Mixed strategies

New types of contracts have allowed some gas producers to get exposure to international gas prices without having to take equity stakes in liquefaction projects.

EQT said in its second quarter results that it would not look to take stakes in U.S. liquefaction but would gain exposure to international gas markets via a tolling agreement with Energy Transfer’s Lake Charles project. Chesapeake Energy Corporation similarly has agreed to supply trading house Gunvor with two million mtpa LNG at JKM-linked prices without yet specifying which terminal will be used.

But other producers continue taking equity stakes in the U.S.

ConocoPhillips has a 30 per cent stake in the Port Arthur LNG project it is developing with Sempra Infrastructure, and Exxon Mobil Corporation has a 30 per cent stake in Golden Pass export terminal.

Devon Energy Corp. also has a preliminary agreement in place to help finance Delfin Midstream’s first floating LNG vessel.

Outside the U.S. firms, TotalEnergies SE has a stake in Cameron LNG and Rio Grande LNG.

For more on Evaluate Energy’s company performance data, click here. 

 

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TotalEnergies SE has made renewables a cornerstone of its net zero strategy, though a recently signed oil and gas deal in Iraq worth a reported $27 billion could potentially check its progress in curbing emissions.

The French energy giant aims to hike renewables capacity tenfold this decade from 10 gigawatts (GW) in 2021 to 100 GW by 2030.

Last year, it grew installed capacity by seven GW, to reach a total of 17 GW by the end of 2022, with a focus predominantly on wind and solar power.

That includes acquiring 50 per cent of Clearway Energy in the U.S., one of the country’s leading renewable energy groups. The transaction also gives TotalEnergies a U.S. development pipeline portfolio of more than 25 GW — this will underpin its goal of generating at least 25 per cent of its 2030 global target of 100 GW from the U.S.

The Americas overall represents the second-largest region globally in terms of currently installed renewables capacity, after Asia, with a broadly even split of wind and photovoltaic energy projects.

Keen to accelerate growth, Patrick Pouyanné, chairman and chief executive officer of TotalEnergies, is allocating $5 billion in 2023 for low carbon energy, more than its investments in new gas and oil projects.

According to the group’s Sustainability & Climate 2023 Progress Report – available with hundreds of other climate related publications from oil and gas companies around the world via Evaluate Energy Documents – investments in electricity and low-carbon molecules amounted to almost $4 billion in 2022, about a quarter of the $16.3 billion in total capital expenditures.

Oil and gas

At the same time, oil and gas remains an integral part of TotalEnergies’ global business, even though new projects are increasingly intertwined with parallel low-carbon ventures.

In Iraq, its long-delayed energy deal encompasses various oil, gas and renewables projects with an overarching goal to improve the Middle East nation’s electricity supply.

Working with QatarEnergy and the local Basrah Gas Company, this includes plans to recover flared gas from three oil fields to supply local power plants, as well as plans to build a seawater treatment plant for water injection to increase oil production.

In addition, TotalEnergies will develop a one-GW solar plant to supply electricity to the Basrah regional grid, working alongside Saudi Arabian company ACWA Power.

The company signed a similarly broad energy agreement in Algeria this month with state-owned Sonatrach to extend its gas partnership and to collaborate on renewables.

This includes raising output at the Tin Fouyé Tabankort fields, securing LNG deliveries, and exploring projects to harness solar power for oil and gas installations, and studying the potential for renewable, low-carbon hydrogen for the export market.

LNG is set to remain a key component of the group’s global portfolio.

On July 13, TotalEnergies and its partners announced the final investment decision for Phase 1 of the Rio Grande LNG project in South Texas.

The $14.8-billion first phase comprises three liquefaction trains with a total capacity of 17.5 million tons per annum (Mtpa), with Bechtel handed the engineering, procurement and construction work.

The plant is scheduled to come onstream in 2027, with TotalEnergies signed up to offtake 5.4 Mtpa of LNG from the first phase over a period of 20 years.

Road to net zero

Announcing the Rio Grande launch, Pouyanné said LNG from the first phase of the project will boost the company’s U.S. LNG export capacity to over 15 Mtpa by 2030.

He also called it a boost for European gas security, and to provide customers in Asia with an alternative form of energy with half the emissions as coal.

TotalEnergies’ ambition is to increase the share of gas in its sales mix to close to 50 per cent by 2030, as part of efforts to cut emissions and to help partners in the transition from coal to natural gas.

However, this is expected to fall back during the 2030 to 2050 period.

Last year, TotalEnergies published an outline of what its business might look like as it transitions to a carbon-neutral company through to 2050.

It expects about a quarter of energy production and sales to still come from oil, gas and LNG combined by that date.

The majority, about 50 per cent of energy and sales, will be derived from low-carbon electricity, with corresponding storage capacity, totalling about 500 TWh/year, on the basis that it develops around 400 GW of renewable capacity.

It expects a further 25 per cent of its energy to come from decarbonized fuels in the form of biogas, hydrogen or synthetic liquid fuels by 2050.

The company projects combined oil and gas production of about one million boe/d by 2050 — about a quarter of the total in 2030 — primarily LNG, with very low-cost oil accounting for the rest, to be used predominantly within the petrochemicals industry.

 

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Shell plc has made sustained progress cutting emissions in recent years, though a commitment to maintain oil production through to 2030 could make reaching its short-term emissions targets a challenge.

Scope 1 and 2 emissions fell from 72 million tonnes of CO2e in 2016, the baseline year, to 51 million tonnes by 2022, Evaluate Energy data shows.

Net emissions intensity has also dropped — down 3.8 per cent in 2022, with a further six to eight per cent reduction projected in 2023 — a trend expected to accelerate in the decade ahead on the road to net zero.

The company says it is committed to achieving net zero emissions status by 2050.

Shell’s chief executive officer Wael Sawan updated investors on the group’s strategy during a June capital markets day, calling for “more value with less emissions” as it seeks to balance the need to supply secure energy and deliver investor returns, while it transitions to a low-carbon future.

The company recorded output of 1.5 million bbls/d during the first quarter of 2023 and sees this holding steady through to 2030.

Sawan also flagged Shell’s commitment to its gas business and maintaining its status as one of the world’s leading liquefied natural gas (LNG) players.

There has been a clear effort to cut emissions from all corners of Shell’s sprawling global business.

The company has been successful in cleaning up its Chemicals & Products business where emissions have been reduced from 46 million tonnes of CO2e in 2016 to 32 million tonnes by 2022 (see graph below).

Upstream emissions have also declined consistently over the same period, though its Integrated Gas unit has seen little change.

In October 2021, Shell set a target to reduce absolute emissions by 50 per cent by 2030, compared to 2016 levels, as part of its net zero pathway.

It estimates its absolute emissions peaked in 2018 at around 1.73 gigatonnes of carbon dioxide equivalent (GtCO2e) per annum (gtpa). By 2022, the total emissions were down to 1.2 gtpa.

The group also aims to achieve near-zero methane emissions by 2030 and to eliminate routine flaring from its upstream operations by 2025, moving faster than the World Bank’s Zero Routine Flaring 2030 initiative.

Sustaining output

Shell’s North American operations are integral to its oil and gas strategy and, consequently, its overall ESG record.

It says its Gulf of Mexico portfolio currently provides among the lowest GHG intensity in the world for producing oil.

In February, the company launched production from the deepwater Vito field, with an estimated peak production of 100,000 boe/d.

The original Vito design was re-scoped and simplified in 2015, resulting in a reduction of approximately 80 per cent in CO2 emissions over the lifetime of the facility, as well as significant cost savings.

Shell is also scheduled to launched production in 2024 from its Whale field, which is of a comparable size to Vito.

It will also see new production onstream from Brazil and Malaysia over the coming years.

On the gas side, Shell’s flagship LNG Canada project will also add 14mtpa of LNG output from the first two trains, with start-up expected in 2025.

Still spending big on transition technologies

Shell is also investing heavily in transition projects and technologies, from hydrogen to carbon capture and storage (CCS), across its global portfolio.

It plans to spend $10–$15 billion across 2023 to 2025 to support the development of low-carbon energy solutions including biofuels, hydrogen, electric vehicle charging and CCS.

In 2022, Shell increased the number of electric vehicle charge points it owned or operated worldwide by 62 per cent to around 139,000, up from 86,000 the previous year.

Other recent initiatives include a $1.6-billion investment in Indian renewable power developer Sprng Energy, and the final investment decision on the Holland Hydrogen 1 project in the Netherlands, set to be Europe’s largest renewable hydrogen plant.

It also this year completed the $2-billion acquisition of Denmark’s Nature Energy, which produces renewable natural gas.

Again, the U.S. is home to some of the group’s biggest low-carbon ventures, including Bovarious and Galloway, two dairy manure-to-renewable natural gas facilities located in Idaho and Kansas, respectively, with start-up expected within the coming year.

The company is also scaling up investments in offshore wind with a number of big U.S. projects. Mayflower and Atlantic Shores are scheduled for start-up in 2026 and 2027, respectively.

 

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Canada’s gas producers posted five-year highs in capital spending in Q1 2023, according to new analysis using Evaluate Energy’s cash flow data.

Canada’s 17 natural gas weighted producers posted a combined spend of over C$2 billion for the first time and seven of the group recorded individual five-year highs in spending.

The seven companies posting individual highs included the group’s largest two producers, ARC Resources and Tourmaline Oil, as well as several smaller producers including relative newcomer Kiwetinohk Energy.

Full details on the record spenders can be found below. Cash used for M&A activity is excluded.

An eighth member of the group, Paramount Resources, was just short (~C$200,000) of recording a similar record spend, as it focuses on drilling and completion operations in the Grande Prairie and Kaybob regions of Alberta.

These record spends could be seen across the North American oil and gas industry in Q1 2023. More details can be found here.

Evaluate Energy’s streamlined cash flow data, including detailed breakdowns of all uses and sources of cash, provide our users with a far clearer picture than ever before of how oil and gas producers use their cash as commodity prices change over time. Data points include capital expenditures, finance raised, debt repaid, assets sold or acquired, dividend payments and more. 

 

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BP plc is one of the few oil majors to set an absolute Scope 3 emissions reduction target — meaning it has a goal to reduce the emissions from the combustion of the fossil fuels it produces, as well as the emissions it takes to produce them.

Of the majors, only BP and Shell plc have net zero Scope 3 targets for 2050. BP set a baseline of 361 million tonnes of CO2e for its Scope 3 emissions in 2019, and initially set a target to reduce this by 20 per cent by 2025 and by 35-40 per cent by 2030. That equates to achieving annual emissions of 289 million tonnes of CO2e or lower in 2025 and 216-234 million tonnes of CO2e or lower in 2030.

As of 2021 the firm had achieved a 15.8 per cent reduction with Scope 3 emissions of 304 million tonnes of CO2e (see chart below), Evaluate Energy data shows.

But earlier this year the firm downgraded the 2025 target from 20 per cent reduction to a 10-15 per cent reduction and the 2030 target from a 35-40 per cent reduction to a 20-30 per cent reduction. The move illustrates that the company’s emissions reduction targets are not binding and can be adjusted depending on global energy security concerns.

This downgrading gave BP leeway to increase emissions over the next few years and still hit its targets. Emissions in 2022 have already increased slightly year-on-year to 307 million tonnes of CO2e — a 15 per cent reduction on the baseline — as fossil fuel production increased 1.6 per cent year-on-year to 2.253 million boe/d.

Between now and 2025 BP expects emissions to grow further due to major project start-ups, deferred divestments of existing production, and further production growth — suggesting it is likely to hit the lower end of the downgraded 10-15 per cent reduction target. But in its latest sustainability report it restated its confidence to hit the mid-range of the 2030 target with a 25 per cent reduction on the baseline, thanks to the anticipated base decline of existing fields and to new low carbon projects coming online after 2025.

BP’s fossil fuel exploration and production capital expenditure has declined from a peak of $4.6 billion in 2010 to around $500 million in 2022, but again it has indicated this figure could grow in the next three years.

Earlier this year BP adjusted upwards its overall capital expenditure expectations from $14-16 billion per year to $14-18 billion per year out to 2030. Of the midpoint $16-billion annual investment between now and 2030, $8 billion will go into transition technologies and $8 billion into fossil fuels.

“We are growing our investment into our transition and, at the same time, growing investment into today’s energy system,” said CEO Bernard Looney, announcing the extra investment.

After 2030, the firm is looking to reduce Scope 3 emissions through two key strategies. The first is producing blue hydrogen using carbon capture and storage (CCS). In April BP signed an agreement to take a 40 per cent stake in the Viking carbon capture and storage (CCS) project in the North Sea.

The second is generating more renewable electricity from its power portfolio.

Renewable generation capacity

By 2030, BP aims to have developed 50 GW of renewable generating capacity, with an interim target of 20 GW by 2025. Apart from Norway’s Equinor, few oil and gas firms have adopted the strategy, preferring instead to focus on hydrogen or CCS.

By the end of first quarter in 2023 the firm had brought 5.9 GW of renewables to FID, and had 38.8 GW in the pipeline, including 10.3 GW relating to the Australian Renewable Energy Hub green hydrogen project and 1.5 GW relating to its Morven offshore wind project in Scotland, in which it was awarded a lease option in January 2022 in partnership with EnBW.

In 2022 the company progressed its offshore U.S. Empire Wind 1 and 2 projects with Equinor and development work continued on its Beacon Wind project. In March 2022 BP partnered with Marubeni Corporation to explore an offshore wind development opportunity in Japan.

In 2022, BP’s transition technology investment doubled year-on-year to $4.9 billion, forming around 30 per cent of total capital expenditures for the year, up from around three per cent in 2019 (see chart above). It sees this figure reaching $6-8 billion in 2025 and $7-9 billion in 2030, meaning a cumulative investment over 2023-2030 of around $55-65 billion.

BP does not provide guidance for oil and gas investment that far out, but this transition spending would leave a remaining cumulative non-transition capital expenditure budget of $73-79 billion over the same time period.

 

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Chinese oil and petrochemicals product supplier Sinopec made progress towards its goal of creating a full value-chain for hydrogen during 2022, advancing production, refuelling stations, fuel cells and storage technologies, according to the company’s latest sustainability report.

Sinopec is accelerating the development of hydrogen energy as a core business of its new energy portfolio, with an initial focus on supplying the refining and transportation sectors.

“We are actively promoting the development of the domestic hydrogen energy industrial chain, ranking the first globally in terms of hydrogen refuelling stations in operation and under construction,” said chairman Ma Yongsheng.

Sinopec has an interim target to install 1,000 hydrogen refuelling station by 2025, supplied with 120,000 tonnes a year of low-carbon hydrogen. Sinopec is allocating 30 billion yuan (US$4.6 billion) to the project.

By the end of 2022 it had built 98 hydrogen refuelling stations to provide high-purity hydrogen for fuel cells, with a total delivery capacity of 16,500 tonnes a year, Evaluate Energy data shows.

Sinopec is already China’s largest grey hydrogen producer, manufacturing 3.5 million tonnes in 2021, accounting for 14 per cent of China’s total output.

It wants to leverage this position to increase its production of low-carbon green and blue hydrogen. By 2050 it has a stated goal to develop a nationwide low-carbon transportation energy supply net-work and operate the largest number of low-carbon hydrogen refuelling stations in the country.

In the midstream, Sinopec has finished construction of nine hydrogen supply centres and completed its first short-pipeline hydrogen transmission station in Jiaxing City, in the eastern Zhejiang province. It has also been developing a suite of hydrogen purification technologies for fuel cells, which require higher purity hydrogen than industrial applications.

And it has undertaken engineering and technical research on high-strength, high-pressure hydrogen storage materials and equipment, as well as a large double-shell vacuum insulated liquid hydrogen spherical tank with a view to deployment in the next few years.

During 2022 Sinopec announced a 100,000 tonne-per-year hydrogen pipeline stretching 400 kilometres from Inner Mongolia — where it is planning a 30,000 tonne-per-year green hydrogen production plant — to the capital Beijing.

CCUS

Sinopec captured 1.53 million tonnes of CO2 in 2022, its highest level ever. The bulk of the CO2 was captured from the firm’s ammonia production processes. During the year the firm used 657,000 metric tonnes of this CO2 for enhanced oil recovery in 36 separate projects.

Sinopec does not yet provide figures for how much CO2 it has injected into storage but says that by 2023 it will have the capability to store 300,000 tonnes.

During 2022 Sinopec began operation of the Qilu-Shengli Oilfield CCUS project, which has the capability to capture one million tonnes of CO2 every year, some of which will be injected into reservoirs for oil production and some of which will be injected into storage.

“This achievement has made Sinopec a technology company with a complete carbon-related industrial chain,” said Yongsheng.

Sinopec says it will build another similar sized CCUS demonstration project in partnership with Sinopec Nanjing Chemical Industries before 2025, as well as constructing a CCUS research and development facility. The firm wants to combine its CCUS and hydrogen expertise to create a blue hydrogen value chain across China.

It is also conducting a joint study with Shell plc, German chemical company BASF, and Chinese steel manufacturer Baowu to develop a CCUS-as-a-service model to transport emissions from third-party industrial facilities in the eastern region of China to offshore reservoirs for injection.

The firm has continued to increase investment in CCUS technology research and development, pioneering its own capture process and high-efficiency solvents, including a new high-efficiency ionic liquid capture solvent that it says could reduce capture costs by about 20 per cent.

In a demonstration project for industrial partners the company built a capture unit that achieved a 96 per cent capture rate. Most available technologies currently can achieve a capture rate of around 90 per cent.

Sinopec says its goal is to reach an emissions peak by 2030 and become carbon neutral by 2050.

 

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PetroChina, the largest oil and gas producer in China, saw a 6.35 per cent year-on-year decrease in methane emissions from 2021 to 2022, the first two years the company reported data.

Methane emissions fell from 428,100 tonnes of CH4 in 2021 to 400,900 tonnes of CH4 in 2022, according to Evaluate Energy data.

Meanwhile, annual hydrocarbon production rose from 1,625 million boe in 2021 to 1,685 million boe in 2022, indicating methane emissions reduction came from process. PetroChina’s methane intensity fell from 0.45 per cent in 2021 to 0.4 per cent in 2022. Methane intensity is the ratio of methane leaked compared to hydrocarbon output.

Reducing methane emissions was one of 10 sustainability projects outlined by PetroChina last year.

It has several actions it is taking on methane emissions, including reducing flaring, putting in place leak detection and repair (LDAR) and emissions monitoring and accounting systems, as well as implementing technologies to recover vent gas from oil production. In 2022 it reported for the first time a figure for recovery from gas venting of 1.5 billion cubic metres.

The company says it is participating actively in China’s methane monitoring pilot projects and is currently undertaking a study to evaluate China’s nationwide methane emissions in 2030.

Global action

PetroChina is a member of the Oil and Gas Climate Initiative (OGCI), a group of 12 of the world’s largest oil and gas companies including Chevron Corporation, Exxon Mobil Corporation and Occidental that have a collective target to reduce methane emissions intensity to “well below” 0.2 per cent by 2025, among other targets.

OGCI members met the target early, reporting an aggregate upstream methane intensity of 0.17 per cent in 2021, the last year for which data is available, suggesting there is scope for PetroChina to make further reductions in line with its peers.

The OGCI has provided its members with a methane flaring reduction toolkit and has conducted a satellite monitoring study in Iraq which found that there is significant potential to use that technology to detect methane emissions in other regions around the world.

PetroChina started its methane reduction program later than most EU and U.S. companies — many of which began to tackle the problem after the Paris Agreement in 2015. PetroChina only began reporting in 2020 and has an individual company goal to reduce methane intensity to 0.25 per cent by 2025 and to 0.2 per cent by 2035. It hopes to maintain methane intensity this year despite targeting a 2.6 per cent increase in production to 1,729 million boe in 2023.

Hazardous waste

Hazardous waste refers to any waste material generated during exploration, extraction, refining and production processes that poses a threat to the environment or human health. Fluids used during fracking and drilling are the most common examples.

PetroChina reduced the amount of hazardous waste it produced by 32 per cent from 1.396 million tonnes in 2021 to 0.943 million tonnes in 2022.

The company has reduced its use of oil-based mud in its operations by deploying layered drilling techniques and has begun using new technologies to capture and dispose of what oil-based mud it does use.

PetroChina has recently adopted a new digitalized control system for its entire waste management process from generation through to storage, transportation and disposal to ensure it is compliant with regulations.

In 2022, the firm built more facilities to dispose of oil-bearing waste and stepped up its inspection and maintenance regime for existing facilities.

 

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Share buybacks are having a major impact on investors in upstream North American oil and gas companies – and Evaluate Energy’s latest data has more than one way to identify who’s benefiting the most.

First, examine the sheer amount of dollars spent.

Investors welcome buybacks because share prices get a boost. Reviewing company cash usage – a calculation streamlined in our database – shows 87 U.S. and Canadian producers spent $53 billion on buybacks over the past 15 months.

More than 80% was spent by 33 oil-focused U.S. producers plus five Canadian oilsands operators. These groups include the largest producers in the study, with ConocoPhillips, Imperial Oil, CNRL, Suncor and Occidental among the biggest spenders.

Second, and perhaps more interestingly, we have improving per share metrics.

Operators of all sizes are buying back shares. Analyzing per share metrics identifies significant activity regardless of company size and cash outlay. If a company buys back shares, i.e. reduces the number of shares it has in-market, this has a direct positive impact on any metric that investors use to analyze performance on a per-share basis. Earnings or cash flow per share are popular examples.

A simple all-encompassing barometer for success for us here, therefore, is the percentage reduction in outstanding shares, a figure that directly impacts every single per-share metric.

By analyzing this data since January 2022, several smaller companies are highlighted.

The results reflect the extent of change in share volume within these smaller companies.

Appalachia-focused CNX Resources plus International Petroleum, Advantage Energy, ARC Resources and Enerplus – four Canadian companies not involved in oilsands – comprise five of the top seven companies when ranked by percentage reduction in outstanding shares.

This means these five producers were able to have the largest relative positive impact on their per share performance metrics than nearly every other producer in our group.

This is despite just $2.5 billion in buybacks combined over the entire 15-month period, proving that share buybacks of all sizes can have a significant impact when analyzing oil and gas company performance.

(All $ figures shown in US$)

Evaluate Energy’s streamlined cash flow data, including detailed breakdowns of all uses and sources of cash, provide our users with a far clearer picture than ever before of how oil and gas producers use their cash as commodity prices change over time. Data points include capital expenditures, finance raised, debt repaid, assets sold or acquired, dividend payments and more. 

 

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North America’s oil and gas capital expenditure is at a five-year high despite significant cuts to operating cash flow caused by lower per barrel prices.

Evaluate Energy has created a study group of 87 U.S. and Canadian domestic-focused companies to examine quarterly changes in cash usage, a key barometer of how oil and gas companies feel about the present market and their confidence in the future.

Around $25 billion in capex was deployed in Q1 by these domestic producers excluding all M&A activity – the highest level of spending per quarter since 2018, and the tenth consecutive quarterly increase.

Evaluate Energy’s streamlined cash flow data helps uncover some of the key reasons why.

Free cash flow is still high

Producers have seen operating cash flow decrease significantly in recent months. Q1 2023 saw $42 billion generated by the study group – around $20 billion less than just under a year ago.

Despite this, U.S. and Canadian producers continue to increase exploration and development capital spending.

The fact is Q1 2023 was still a relatively bumper quarter for both operating and free cash flow – the difference between operating cash flow and capital expenditures.

Since the start of 2018:

• Only periods in 2022 saw higher operating cash flow than Q1 2023
• Free cash flow hovered around $17 billion. Pre-pandemic, no quarter even got close to hitting $10 billion.

Debt is not a factor

Importantly, company debt is largely under control. A deeper dive into the data illustrates this change over time.
For sure, debt was the focus in late 2020 and early 2021. As producers emerged from the pandemic, they tackled immediate debt problems and it’s less of a priority now.

• Debt was intensely tackled at 37% of all cash used in Q3 2021; the only quarter over five years where debt management outranked all other cash usage.
• The percentage of cash for debt dropped sharply to 16% in Q3 2022. It dropped below 10% in Q1 2023, the first time post-Covid.

Plenty of cash for dividends and buybacks too… for now

Q1 2023 saw 35% of all cash used for dividends and buybacks. This is slightly down on the quarterly average since Q3 2022, but way above the five-year average of 22%.

Capex is on the rise while dividends and buybacks absorb a substantial and sustained portion of cash.

Evidently, free cash flow is yet to hit levels where promises made over shareholder returns conflict with capital spending plans. There is clearly plenty of cash for both.

If operating cash flow continues to drop to the point that something must give, it would be interesting to see how producers react.

For now, though, there is no conflict. Producers are pressing on in a big way.

Evaluate Energy’s streamlined cash flow data, including detailed breakdowns of all uses and sources of cash, provide our users with a far clearer picture than ever before of how oil and gas producers use their cash as commodity prices change over time. Data points include capital expenditures, finance raised, debt repaid, assets sold or acquired, dividend payments and more. 

 

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ExxonMobil Corporation is prioritizing carbon capture and storage (CCS), hydrogen, and low emission fuels rather than renewable energy like solar and wind, as it pursues its rigorous climate goals.

The largest U.S. oil producer has also made headway in driving down emissions despite a portfolio that remains dominated by hydrocarbons, Evaluate Energy data shows.

Scope 1 GHG emissions dropped from 109 million tonnes of CO2e in 2016 to 96 million tonnes in 2021, though it has not always followed a straight, downward trajectory.

Exxon also reduced Scope 1 and 2 emissions intensity in operated assets by more than 10 per cent, it noted in its 2023 Advancing Climate Solutions Progress Report, resulting in an approximately 15 per cent absolute reduction through year-end 2022 vs. 2016 levels.

Methane emissions intensity on operated assets, and absolute methane emissions, have been cut by more than 50 per cent over the same period.

After issuing its first sustainability report over 20 years ago, Exxon is stepping up the pace of activity.

The company said it plans to invest $17 billion on lower-emission initiatives between 2022 and 2027 — a 15 per cent spending hike from a year ago — as CEO Darren Woods sets about reshaping the business as part of a broad, long-term decarbonization effort.

That includes tripling the size of the Low Carbon Solutions unit, pointing at a major structural realignment to come over the next decades.

In forward modelling, capex on low carbon projects will broadly match that of traditional oil and gas by 2030, the company estimates, and eventually dominate spending by 2040.

Carbon capture & storage

The company’s Low Carbon Solutions unit has singled out CCS as a major thrust of this investment. It is an area in which Exxon already has decades of experience.

While CO2 captured for storage has been stable for years, reaching seven million metric tonnes per annum in 2021, mainly from the LaBarge facility in Wyoming, this is expected to accelerate with projects such as Pecan Island in Louisiana.

Current CO2 storage capacity is closer to nine million tonnes, according to information on the Low Carbon Solutions website.

A flurry of new initiatives is taking shape, including plans to expand LaBarge by up to one million more tonnes a year, starting in 2025.

Exxon is also helping the industrial sector to decarbonize, signing contracts with major partners such as Linde, and most recently steel producer Nucor Corporation, for assistance with CO2 storage.

The project with industrial gases group Linde will capture, transport, and permanently store up to 2.2 million tonnes of CO2 a year from Linde’s new clean hydrogen production facility in Beaumont, Texas, with operations starting around 2025.

The Nucor project, expected to launch in 2026, means Exxon has now agreed to transport and store a total volume of five million tonnes of CO2 per year for third-party customers.

Hydrogen investment

Hydrogen is another target area for Exxon, which, unlike many of its peers, is steering away from big renewable energy investments in solar and wind power.

In January, it awarded front-end engineering and design work to Technip Energies on what will be the world’s largest low-carbon hydrogen facility at planned start-up in 2027-2028.

The hydrogen, ammonia and CCS plant in Baytown, Texas, is expected to produce one billion cubic feet of hydrogen a day, with a final investment decision expected by 2024.

More than 98 per cent of associated CO2 produced by the facility — around seven million tonnes per year — is expected to be captured and permanently stored.

The CCS network developed for the project will also be made available for use by other third-party CO2 emitters in the area.

It reflects a broad aim to a forge a new business model making money helping others to decarbonize their operations and reduce greenhouse gas emissions.

Exxon’s own targets are to achieve net-zero operated Scope 1 and 2 GHG emissions by 2050 — and by 2030 for its unconventional Permian Basin operated assets.

It is working to electrify operations with lower-emission power, including wind, solar and natural gas, as well as expand methane detection and mitigation, eliminate routine flaring, upgrade equipment, and employ high-quality emissions offsets, including nature-based solutions.

At the same time, Exxon will be tested in keeping a lid on emissions with production from major new upstream projects coming onstream.

These include the Uaru development in Guyana, which will add 250,000 boe/d of gross capacity in 2026.

Exxon’s overarching strategy is that all energy sources will remain important in the coming decades, with oil and gas still accounting for 55 per cent of the world’s energy mix in 2050.

But it hopes its new focus areas can become key pillars of growth in the years ahead as the hydrogen sector and carbon markets continue to evolve.

 

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