Author: Martin Clark

Occidental’s CrownRock deal caps busy year of Permian M&A

Occidental Petroleum Corporation’s $12 billion deal to acquire CrownRock LP added to the rush of M&A activity in the Permian Basin in 2023 as operators looked to build future drilling inventory in the massive Texas and New Mexico resource play.

The deal saw Occidental acquire 170,000 boe/d of production in the Midland Basin, along with a 94,000 net acre land position and supporting infrastructure and 1,700 undeveloped drilling locations.

In the last decade over $400 billion in Permian assets have changed hands, with the recent $64.5 billion Exxon Mobil Corporation deal to acquire Pioneer Natural Resources the largest deal recorded.

The top 20 deals in 2023 accounted for almost $107 billion in assets shifting ownership, according to Evaluate Energy data.

Source: Evaluate Energy M&A

Consolidation expected to continue

Operators expect consolidation to continue, although the number of targets available is shrinking.

“I do think that you’ll continue to see consolidation,” Devon Energy Corporation president and chief executive Rick Muncrief, said at the company’s third quarter 2023 earnings call.

“We’ve been on record as saying we support continued consolidation in the sector. We think it’s the right thing to do for investors,” said Muncrief. “But as far as Devon’s participation goes, I’m going to go back to those key elements and we’re going to have a high bar, be very disciplined, be very thoughtful, and make sure we can sell that to investors, that it’s the right thing to do.”

Diamondback Energy chief executive officer Travis Stice echoed a similar sentiment, with buyers becoming more discerning following a lengthy period of consolidation, and opportunities now thinning out.

“We have such a high-quality inventory right now that the bar is pretty high for additional opportunities,” he told analysts on a third-quarter call.

Diamondback activity

All of Diamondback’s operations are in the Permian, a position it has strengthened following its own streak of acquisitions during the past several years.

Most recently, that includes its subsidiary, Viper Energy Partners, moving to acquire interests from affiliates of Warwick Capital Partners and GRP Energy Capital to bolster its presence in the basin in a cash and stock deal worth about $1 billion.

Almost 90 per cent of Diamondback’s future drilling plans target the Midland basin, but the company also has a smaller position in the Delaware Basin. While the Delaware assets are not on the market, president Kaes Van’t Hof said it would consider a deal under the right circumstances.

“Inventory is coming in at a premium,” he said. “So I think we’re going to hold it for now, and if someone wants to pay for upside in a reasonable number… we’ll take a look at it.”

The buyer pool may also have thinned, he noted, with the disappearance of many smaller private operators, which might dictate what happens in the next tranche of consolidation.

“You’ve had a couple of very large buyers do a couple of deals in the Permian Basin and out of the basin. They could kind of do whatever they want, it seems,” said Van’t Hof, referring to the Exxon-Pioneer deal, and Chevron’s $53 billion move for Hess Corporation.

“I would just say generally industry consolidation has happened and is continuing to happen. I think a lot of the privates are gone to logical acquirers. There may be less buyers of assets, but they’re well-funded, good operators with big balance sheets and competitive.”

Other large transactions

While the Exxon-Pioneer mega-deal dwarfs other M&A activity in the Permian, there have been several other large and notable transactions this year.

Civitas Resources acquired NGP Energy Capital management for $4.7 billion.

Others include the $4.5 billion Permian Resources deal for Earthstone Resources, and Ovintiv Inc.’s $4.3 billion Black Swan Oil & Gas, Piedra Resources and PetroLegacy II assets acquisition.

“We have long said that we expect to see further industry consolidation,” said Ryan Lance, chair and chief executive of ConocoPhillips, which landed Shell plc’s Permian business in a deal worth $9.5 billion in late 2021.

The company has a “high bar” for M&A,” he said. “And, as a reminder, we’ve been actively high grading our own portfolio over the past several years.”

As well as the Shell transaction, ConocoPhillips also landed Permian assets via its Concho Resources deal in 2020, worth over $13 billion.

Occidental Petroleum’s $55 billion acquisition of Anadarko Petroleum Corporation in 2019 stood as the largest Permian deal prior to ExxonMobil’s takeover of Pioneer.

 

Evaluate Energy’s M&A database holds every upstream deal worldwide since 2008, allowing daily comparisons of key metrics, corporate valuations and changes in spending behavior over time. For more on our data, which also includes data on downstream, midstream, service sector and renewable energy M&A activity, click the button below.

 

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Texas oil players continue finding productivity gains

U.S. oil producers are delivering productivity gains across Texas, unlocking more output, bringing down costs, and helping navigate ongoing market uncertainties.

Several producers, such as EOG Resources, Inc., Diamondback Energy, Inc. and Devon Energy Corporation, raised output forecasts during the third quarter, resulting from higher well productivity than expected.

Efficiency and productivity gains are being driven through improved cycle times, new technology and greater collaboration, the companies reported.

EOG Resources

EOG Resources is one of several companies to report up to 20 per cent increases in well productivity in the Delaware Basin of the Permian from new wells.

Source: EOG Resources Q3 Results Investor Presentation. For more on Evaluate Energy Documents, watch a short video here or click here for more information.

“Well productivity improvement is the primary reason we were able to increase the full-year oil guidance by 1,500 bbls/d,” said Billy Helms, EOG’s president and chief operating office, on the firm’s third quarter results call.

Total third quarter oil production of 483,300 bbls/d was above the high end of the company’s guidance range and up one per cent from the second quarter.

NGL production was also above the high end of the guidance range, and up seven per cent from the second quarter.

One of the largest Eagle Ford producers, Helms said completed lateral feet per day in this basin had increased by 19 per cent, year on year.

Completions efficiencies also reduced the time to bring wells to sales, he noted.

“Our teams are optimizing both production and cost through our many technology applications that allow for real-time decisions to maximize production and reduce interruptions of third-party downtime,” he said.

Leveraging both in-field technology and digital technology to improve well productivity and efficiencies, EOG has increased production 33 per cent over the past five years, while per unit operating costs have fallen 17 per cent.

Devon Energy

Devon Energy has similarly achieved success at its South Texas Eagle Ford play, including through its refrac program.

“The rock is incredibly forgiving in the sense of down-spacing refracs,” said Clay Gaspar, executive vice-president and COO, in a third quarter update.

“We continue to find and uncover new ways to extract more and more of that oil in place, so we’re very encouraged with that.”

The company has set a baseline oil production of around 315,000 bbls/d, with overall gas and liquids output forecast to be around 650,000 boe/d in the fourth quarter.

Next year, Devon Energy expects to see the same or similar production but on 10 per cent less capital expenditure, with a primary focus on the Permian Delaware. The company anticipates 2024 capital investment of $3.3 billion to $3.6 billion.

Source: Devon Energy Q3 Results Investor Presentation. For more on Evaluate Energy Documents, watch a short video here or click here for more information.

A highlight in the Delaware Basin during the third quarter was the Bora Bora project, developing the upper Wolfcamp at Devon’s Todd area, with IP30s averaging 4,600 boe/d, and 60 per cent oil, with costs coming in under budget.

At its CBR 17 development in Texas, IP30s rates averaged 4,100 boe/d, at 49 per cent oil.

Average well productivity (IP30s) in the Delaware stood at 3,010 boe/d in the third quarter, up from 2,470 boe/d during the first half of 2023.

Rick Muncrief, president and chief executive officer, said Devon had sharpened its capital allocation and pushed service costs lower to deliver “a step change improvement in well productivity and efficiency.”

The company cited infrastructure improvements that support optimized development plans, reduced appraisal requirements on the Wolfcamp-focused program, and a higher allocation towards the core of the play in New Mexico, as reasons behind the productivity boost.

In 2024, well productivity in the Delaware is expected to improve again by up to 10 per cent, the company added.

Diamondback Energy

At Diamondback Energy, driving down costs and raising the productivity bar has become integral to navigating the maturity of shale basins.

“If we retain our cost structure and our ability to drill wells $1 million, or $1.5 million, or $2 million cheaper, well, as the shale cost curve goes up, we continue to stay at the low end of that cost curve,” said Kaes Van’t Hof, president and chief financial officer, in a third quarter results update. “It’s been kind of our mantra for 10 years now.”

In the third quarter, the company’s full year 2023 oil production guidance crept up to around 263,000 bbls/d, up from 260,000–262,000 bbls/d.

Source: Diamondback Energy November 2023 Investor Presentation. For more on Evaluate Energy Documents, watch a short video here or click here for more information.

Average per well productivity in the Midland Basin continued to improve in 2023, up two per cent on 2022, which the company credited to the shift to co-development of all primary targets, a move that began in 2019.

Large-scale development across the Midland has also brought with it time and cost savings, with teams drilling wells up to four days faster than two years ago.

“On the frac side is where we save the most money from a capital perspective, because we’re doing, in some cases, two Simul-Frac crews on the same site at the same time,” said Van’t Hof. “So you’re saving essentially $250,000–$300,000 a well from Simul-Frac.”

He said two fleets also run off lean gas, which saves a further $200,000–$250,000.

This focus on large-scale development has aided in planning and created more predictability, and ties into the longer-cycle nature of the energy business, helping to dampen the effects of market volatility, he added.

“We don’t want to change the plan every move in oil price,” said Van’t Hof.

 

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Eni scales up renewables but net carbon intensity largely unchanged

Italian oil and gas company Eni has committed heavily to renewable power production as part of its decarbonization efforts.

The group has a strong hydrocarbon presence in the U.S., with a portfolio of upstream and downstream assets, but is shifting away from oil towards gas, as well as rolling out a substantial alternative energy infrastructure.

Despite building up its clean energy profile in recent years, overall net carbon intensity across the group remains largely unchanged, as Evaluate Energy data shows.

Source: Evaluate Energy Single Company Emissions Dashboard

Net carbon intensity has fallen fractionally since 2018, by about three per cent, though the company hopes this will become a 15 per cent drop by 2030, led mainly by improvements within its upstream business.

Overall, Scope 1, 2 and 3 emissions have fallen more significantly, with a 17 per cent reduction in 2022, compared to 2018 levels.

Total energy production from renewable sources – notably wind and solar – is rising fast, reaching 2,552 gigawatt hours (GWh) in 2022, up from just 12 GWh in 2018.

It is an area that has seen especially strong growth since 2020, momentum that the company hopes to continue to build as part of its 2050 carbon neutral plan.

Eni aims to grow renewables capacity to more than 15 gigawatts (GW) by 2030, pointing to a huge expansion in the decade ahead.

Source: Eni

In 2021, Eni set up its Plenitude unit to drive its clean energy mission, which also manages the sale and marketing of gas and electricity for households and businesses, and the management of charging points for electric vehicles.

Its most recent acquisition — via Plenitude’s GreenIT joint venture — will see the development of four more renewables projects in Italy with a capacity of up to 200 megawatts (MW).

These will use agri-voltaic technology, which involves installing raised structures to achieve synergy between agriculture and the production of renewable energy.

Gas focus

Oil and gas, however, remains integral to the group’s global portfolio, with total daily hydrocarbon production of 1.6 million boe/d in 2022, though increasingly skewed towards gas.

Eni sees natural gas as a critical bridge energy source during the energy transition and is focused on increasing its share of production to 60 per cent of hydrocarbons output by 2030, and over 90 per cent in 2050.

This includes growth in its LNG activities with contracted volumes expected to rise to over 18 million tonnes in 2026, more than double that of 2022.

This rationale has steered recent M&A activity, including its US$5-billion acquisition with Var Energi of Neptune Energy in June, and the US$300 million disposal of oil assets in the Congo to French independent, Perenco, though it retains its gas holdings in the West African country.

Neptune Energy operates fields across the U.K., Norway, Germany, Algeria, the Netherlands and Indonesia, but with a heavy emphasis on gas, comprising 77 per cent of its overall production.

Source: Presentation “Eni to acquire Neptune Energy” June 2023.  For more on Evaluate Energy Documents, watch a short video here or click here for more information

Eni’s CEO, Claudio Descalzi, says the acquisition supports the objective of reaching net zero emissions (Scope 1 & 2) from the group’s upstream operations by 2030.

The acquisition ticks other boxes, too, with Neptune advancing various carbon capture and storage (CCS) schemes in Norway, the Netherlands and the U.K., another dimension to Eni’s decarbonization drive.

It aims to develop hubs for the storage of CO2 from hard-to-abate emissions generated by Eni’s and third-party facilities and is targeting a gross capacity of 30Mtpa by 2030.

Ongoing innovation

Other threads in Eni’s sustainability drive include bioenergy through the development of biomethane and biofuels.

It also expects to see a progressive increase in the production of new energy carriers, such as hydrogen.

In the U.S., it recently signed a new co-operation pact with Commonwealth Fusion Systems (CFS) — a spin-out of the Massachusetts Institute of Technology (MIT) — to accelerate the industrialization of fusion energy.

CFS, in which Eni is a strategic shareholder, is working to have a first pilot reactor capable of generating energy from fusion operational as early as 2025, with a view to the first grid-connected industrial plant planned for early next decade.

At the same time, the company is continuing to invest in reducing methane emissions from production and embedding other innovative mitigation measures on its latest oil and gas projects.

That includes the offshore Baleine deposit in Côte d’Ivoire, which Eni believes will be Africa’s first Scope 1 and 2 net zero development.

Emissions will be compensated through several initiatives, including projects to preserve, restore and manage forests and savannas, as well as the distribution of energy-efficient cookstoves, produced locally, which the company says will improve the livelihoods of 800,000 people.

First production from Baleine, which holds 2.5 billion bbls of oil and 100 billion cubic metres of associated gas, is expected in mid-2023.

 

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Repsol scaling up U.S. low-carbon business

Spanish energy group Repsol is increasing its focus on renewable energy as part of its effort to cut corporate emissions.

Repsol expects to more than triple renewables capacity between 2022 and 2025, and then again in the 2025-2030 period. The company has a goal of achieving total renewable generation capacity of six gigawatts (GW) in 2025 — up from 1.6 GW in 2022 — rising to 20 GW in 2030.

By 2030, around two-thirds of its renewables production will be derived from PV solar with the rest mostly from onshore wind and hydroelectricity.

Source: Repsol Global Sustainability Plan 2023. For more on Evaluate Energy Documents, watch a short video here or click here for more information

In the U.S., Repsol’s portfolio already includes some solar and battery storage, while its upstream oil and gas assets are scattered across the Gulf of Mexico, the Marcellus shale in Pennsylvania, the Eagle Ford shale in South Texas, and Alaska’s North Slope.

Low-carbon growth

Repsol’s chairman, Antonio Brufau, recently called the energy transition an “enormous opportunity” for the company, and one that will dictate future spending patterns.

The proportion of capital expenditure on low-carbon businesses will rise from 35 per cent to at least 50 per cent by 2031, and 60-90 per cent in the 2041-2050 timeframe.

As well as production and marketing of renewable electricity, it also plans to increase investment in biofuels, renewable hydrogen, synthetic fuels, carbon capture, utilization, and storage (CCUS), energy efficiency, and other value-added services such as electric mobility.

While much of this will be focused on Spain, Repsol is actively building up its low-carbon business unit in the U.S., with collaborations and investments in CO2 storage and geothermal.

It entered the U.S. renewables market in 2021 following the purchase of 40 per cent of Hecate Energy, a PV solar and battery storage project developer, and started producing electricity from its first operated project the following year with the 62.5 MW Jicarilla 2 solar plant in New Mexico.

The company is developing a further 62.5 MW solar photovoltaic and 20 MW battery storage project at the same location and is also advancing two additional solar projects in Texas — the 637 MW Frye project and 629 MW Outpost project.

It has also proposed a CO2 storage hub offshore Louisiana, in shallow waters in the South Timbalier Lease Area, working alongside Carbon Zero LLC and other partners.

Repsol is technical leader for the project, which was recently selected to negotiate funding support from the Department of Energy.

The company is also evaluating geothermal potential on its Eagle Ford asset in Texas.

Upstream emissions challenges

Source: Evaluate Energy ESG – find out more here.

Repsol is targeting net zero emissions by 2050 and aims to reduce the carbon intensity of its operated assets by 75 per cent by 2025 compared to its 2021 baseline. It hopes to slash methane emissions intensity by 85 per cent by 2025, compared to 2017.

Like other operators, though, it faces a test in achieving emissions goals as it nurtures and expands oil and gas activities.

That includes the Pikka development — Repsol’s first in Alaska — adding gross production of 80,000 bbls/d of oil, with production expected in 2026.

The company claims Pikka has a carbon intensity index among the lowest in its global portfolio, highlighting its focus on lower-emissions projects.

This year, Repsol also added to its Eagle Ford shale acreage, where it now operates 126,364 net acres with average production of around 48,905 boe/d in the unconventional play.

To help meet emissions targets, it is deploying technology such as aerial and satellite leak detection and electrification of its operations, as well as circular economy initiatives aimed at energy efficiency.

In line with its decarbonization objectives, this year Repsol also achieved certification for all of its natural gas production in the Marcellus of Pennsylvania with the MiQ standard for methane emissions performance.

 

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ExxonMobil looking to grow low-carbon solutions business through targeted M&A

Exxon Mobil Corporation is looking for M&A opportunities that leverage or extend its own technologies or skillsets to build out its Low Carbon Solutions business, chief executive officer Darren Woods said during a brief update on M&A during the company’s second quarter conference call.

In the upstream oil and gas business, the company is focused on M&A opportunities that help drive down costs or add significant value, Woods added. ExxonMobil has cut costs by $8.3 billion since 2019.

“We’re pretty picky acquirers. I don’t see us changing that position,” Woods said, adding that any prospective deals need to create unique value and, “the opportunities have to be bigger than what ExxonMobil or any potential acquisition could do independent of one another.”

While no details were released on a move for Pioneer Natural Resources Company — the two sides are reported to have held preliminary talks about a potential deal earlier this year — Woods alluded to some of the company’s strategic thinking in the current M&A climate.

Evaluate Energy M&A users have access to data and analysis metrics on every major deal around the world in the upstream and wider energy sectors. Find out more here.

Denbury Acquisition

Source: ExxonMobil Acquisition Presentation. For more on Evaluate Energy Documents, watch a short video here or click here for more information

The recent US$4.9-billion acquisition of Denbury Inc., a developer of carbon capture, utilization, and storage (CCUS) solutions and enhanced oil recovery (EOR), provides an example of the type of deals ExxonMobil is targeting.

The Denbury acquisition helps fast-track the company’s low-carbon objectives, he said.

“It significantly enhances our competitive position and offers a compelling customer proposition to economically reduce emissions in hard-to-decarbonize heavy industries which, today, have limited, practical options.”

The acquisition provides ExxonMobil with the largest owned and operated CO2 pipeline network in the U.S., at 1,300 miles. The network covers areas of Louisiana, Texas and Mississippi, and is close to various onshore sequestration sites.

The transportation and storage system could accelerate CCUS deployment for ExxonMobil and third-party customers over the next decade, the company noted. It also underpins development of other low-carbon technologies including hydrogen, ammonia, biofuels and direct air capture.

The Denbury deal adds Gulf Coast and Rocky Mountain oil and gas assets with proved reserves of over 200 million boe, and 47,000 boe/d of current production — though this is supplementary to Exxon’s pursuit of the company, said Woods.

“That, frankly, for us, was not a key driver or strategic driver of the opportunity. I think EOR, certainly in the short term, can play a role. But if you think about the broader opportunity, it’s really around carbon capture, storage, and sequestration and keeping the carbon under the ground. So that’s the longer-term play for us.”

Woods said as ExxonMobil continues to invest in and understand new low-carbon technologies it will gain clarity regarding prospective M&A targets.

“The more we do that, the more we advance our technology portfolio, the bigger the opportunity to identify unique value opportunities with other companies. And so, we are continuing to look for that. But we’re not going to compromise our expectation of generating returns and growing value for shareholders.”

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 it reshapes its 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.

ExxonMobil has not moved big into solar and wind, although it is eyeing potential opportunities in lithium production for EV batteries. It is more focused on what Woods calls “the molecules side.”

He also suggested that a narrow focus on wind, solar and electric vehicles (EV) may have hindered progress on low-carbon efforts, referring to it as “an incomplete solution set,” at the expense of other alternatives such as hydrogen or CCUS.

“The fact that other alternatives and other solutions — that, frankly, at the time we were advocating for and, in fact, trying to develop internally — weren’t considered, or actually weren’t accepted, has slowed society’s progress,” he said.

ExxonMobil emissions declining

ExxonMobil’s 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.

It 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 versus 2016 levels.

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

 

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TotalEnergies stepping up renewables spending in 2023

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 curbs emissions despite renewed gas, liquids commitments

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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ExxonMobil increasing CCS, hydrogen and biofuels investments

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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Pemex in fight to curb emissions amid rising output

Pemex is facing a critical period ahead as it seeks to reduce emissions at a time when production is climbing.

Mexico’s state-owned oil company has set ambitious new emissions-intensity goals, reflecting a renewed commitment to improve its ESG record.

The targets will see GHG intensity from oil and gas production fall sharply from 38.1 tCO2e/Mboe in 2022, down to 21.5 tCO2e/Mboe in 2025, Evaluate Energy data shows.

Pemex hopes to achieve similar intensity declines by 2025 from its refining and natural gas processing businesses.

The updated targets are an acknowledgment from the company that its ESG track record needs a refresh, partly to continue to attract affordable financing.

Pemex remains heavily indebted — in just a decade, its debt has ballooned from $64 billion in 2013 to around $108 billion — and is dependent on access to the financial markets.

Greater ambition

In a May 2023 ESG update, the company outlined a range of specific measures it plans to take to improve its environmental record.

These include the release of a long-term Sustainability Plan for 2023-2050, expected in the second half of 2023, which will offer greater visibility and transparency into forward plans.

Other measures include a 98 per cent gas use target by 2024, up from 95 per cent currently.

Pemex has long faced criticism for its flaring, even though Mexico is among signatories to a World Bank pledge to cut routine flaring to zero by 2030.

In 2021, approximately 35 per cent of Pemex’s total Scope 1 and Scope 2 emissions came from upstream gas flaring.

On a broader strategic level, Pemex also appointed its Sustainability Committee in March to help steer the group through its ESG transformation.

Production rising

At the same time, the company is seeing rising upstream production, which could make achieving its targets more challenging.

In March, liquids output reached 1.915 million bbls/d, with forecasts of 2.0 million bbls/d by the end of 2023.

Pemex is seeking to recover lost ground after output tumbled from 2012, when it stood above 2.5 million bbls/d.

The company is also scaling up refining and processing capacity in response to energy demand.

Crude oil processing capacity has similarly bounced back significantly after it plummeted by around 50 per cent between 2013 and 2018.

Major investments include the acquisition of Shell Deer Park Refining LP’s 340,000-bbl/d refinery in Texas in late 2021.

Trion sanctioned

How Pemex links its updated ESG strategy into the wave of new projects being unleashed to restore and rebuild output and capacity will be key.

Woodside Energy Group’s $7.2-billion Trion development, in which Pemex holds a 40 per cent interest, could be a marker of things to come.

The recent sanctioning of the ultra-deepwater field, located in the western Gulf of Mexico, may yield some clues as to how the state-owned company will translate its goals into reality.

While first output is not due until 2028, Trion is expected to have an average carbon intensity of 11.8 kgCO2e/boe over the life of the field, according to the operator, lower than the global deepwater oil average.

The project continues a trend of replacing ageing production from mature fields with new ones.

High stakes

Squeezed between high debt and the added costs of meeting ESG commitments, alongside the responsibility to meet the nation’s energy needs, cutting emissions intensity so drastically over the next two years will be a huge task.

Still, with more visible emissions targets in place, it seems as though a genuine effort is being made to get to grips with some of the many challenges faced by the company.

 

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Southwestern Energy battling emissions after M&A spree scales up production

Southwestern Energy Company is looking to rein in emissions from its dual-basin U.S. unconventional gas portfolio after its business expanded greatly in recent years.

Scope 1 GHG emissions are still some distance over pre-acquisition levels, at 1.55 million tonnes of CO2e in 2021. This compares to 516,000 tonnes of CO2e in 2019, Evaluate Energy data shows.

In 2021, it recorded a nine per cent reduction in GHG emissions intensity, with 2022 metrics as yet unavailable.

Methane intensity also spiked in 2020, primarily due to the acquisition of assets with higher methane leak/loss rates than Southwestern’s legacy assets, though this has now been brought down to earlier levels.

The company says it minimized the impact by integrating new assets into its own, rigorous methane emissions-reduction programs.

It also attributes some of this success on the low emissions intensity profile of the two core basins in which it operates, Appalachia and Haynesville.

Acquisitions trail

Southwestern, which holds predominantly gas-based assets with some additional liquids production, has been firmly on the acquisition trail for the past few years.

  • In September 2021, it acquired Indigo Natural Resources, expanding its operational footprint into Louisiana’s Haynesville shale basin.
  • A few months later, in December 2021, it extended this with the purchase of GEP Haynesville, LLC, making it a key supplier to LNG exporters on the Gulf coast.
  • Prior to that, in late 2020, SWN landed Montage Resources Corporation, which expanded its operations into Ohio, in the Appalachia Basin, where it also holds assets and producing wells in Pennsylvania and West Virginia.

This has seen output rise sharply, reaching 1.7 trillion cubic feet equivalent in 2022— including 4.2 bcf/d of natural gas and 97,000 bbls/d of liquids — up from a total production of 880 billion cubic feet equivalent in 2020.

Total proved reserves across both basins jumped significantly as well, reaching 21.6 trillion cubic feet equivalent in 2022, up marginally from 2021, but close to doubling 2020 figures of 12.0 trillion cubic feet equivalent.

ESG commitments

After the big spending spree, and then integrating its Haynesville acquisitions, president and chief executive officer Bill Way has been keen to bolster financial resiliency of late, paying down US$1 billion in debt during the past year.

There are also plans to moderate activity through 2023, he says, which will result in cost reductions, and slightly lower expected production, which may yield a dampening knock-on effect on emissions.

The company once again reaffirmed its commitment to lower-carbon, reliable energy in its latest set of quarterly results, published at the end of April.

Corporate responsibility and ESG is an area it has been reporting on for the past nine years, with the group making strong headway among its peers.

In 2022, the company announced a longer-term GHG emissions reduction goal consistent with a path to net zero by 2050.

Responsibly sourced gas

Southwestern has also been an early mover in its commitment to certify all wells as responsibly sourced gas (RSG) — a target achieved by the end of 2022 — and to continuously monitor for potential emissions on all well sites.

RSG is a distinct natural gas classification that is verified for low-emission attributes and environmentally responsible production, a badge of transparency that is gaining market interest.

In 2022, it signed a multi-year RSG sales agreement with the North American subsidiary of Uniper, one of Germany’s largest publicly listed energy groups.

Southwestern supplies Uniper with RSG for its U.S. midstream gas portfolio that includes domestic distribution to downstream customers, as well as natural gas to U.S. liquefaction and export facilities.

The Texas-based gas producer has also been a frontrunner in other areas, being among the first companies in the industry to achieve and sustain fresh water neutral operations.

In 2021, it achieved its sixth year of fresh water neutral operations, delivering nearly 16 billion gallons of fresh water to local communities — more than it consumed over those six years.

 

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