Top 10 upstream oil and gas deals in Q3 2023: U.S. dominates

The largest upstream deals of Q3 2023 were almost exclusively in the United States, where four of the five Q3 deals valued at over $1 billion took place.

While a major asset sale in Oman, LNG investments in Australia and corporate mergers in Africa, Canada and Europe also cracked the top 10 this quarter, the U.S. continues its long-term domination of the upstream M&A space.

In fact, Evaluate Energy data shows that 70% of Q3’s global upstream M&A spending was focused on U.S. assets.

Evaluate Energy’s full review of Q3 activity is available now. It includes more on these regional trends, detailed analysis of ExxonMobil’s acquisition of Denbury, and shows how recent activity stacks up against the past five years of deal-making.

 

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ConocoPhillips building out global LNG business

ConocoPhillips advanced its LNG strategy in the first half of 2023, completing the acquisition of an equity interest in Qatar’s North Field South project, agreeing to an offtake deal with the planned Saguaro LNG export facility in Mexico and securing regasification capacity at the Gate LNG Terminal in the Netherlands.

At its analyst and investor meeting in April, the company said it sees robust LNG demand growth well into the middle of the century, led by Asian importers. It aims to expand its LNG supply portfolio from six million metric tonnes per annum (mtpa) currently to over 12 mtpa by 2028.

Qatar acquisition

ConocoPhillips completed a deal making it one of three international partners, alongside TotalEnergies SE and Shell plc, in QatarEnergy’s North Field South (NFS) expansion project. The NFS project is two liquefied natural gas (LNG) trains with a combined capacity of 16 mtpa.

ConocoPhillips will have an effective net participating interest of 6.25 per cent in the NFS project, in addition to its existing 3.125 per cent stake in the 32 mtpa North Field East project.

Source: Evaluate Energy

QatarEnergy and ConocoPhillips will deliver LNG to Germany from the region in 2026, with the company also announcing it has secured 2.8 mtpa of regasification capacity at a planned terminal in Germany.

“That supports our two mtpa offtake from our LNG SPAs with Qatar and leaves 0.8 million mtpa to be supplied by our commercial LNG business,” said chief financial officer William Bullock.

Mexican waves

ConocoPhillips has also signed a 2.2 mtpa offtake agreement from the proposed Saguaro LNG terminal on the west coast of Mexico, which is well placed to supply Asian markets by avoiding Panama Canal fees. The project has yet to take FID.

“From a supply perspective, it really does complement our offtake from Port Arthur very nicely, creating some excellent optimization opportunities,” said Bullock.

The company has 5 mtpa of LNG supply from Phase 1 of Port Arthur LNG on the Gulf Coast, with FID already taken and startup slated in 2027. It also has access to excess uncontracted volumes from Phase 1 of the project and options for equity and offtake on future phases.

The company is planning a mix of long-term contracts, short-term contracts and spot sales across its portfolio to optimize pricing.

“We are actively developing placement into Europe. We’re developing long-term deliberate opportunities into Asia. And we’re considering some sales FOB at the facilities that are in the money right now,” said Bullock.

ConocoPhillips also has a partnership with Origin Energy Limited for Australia Pacific LNG (APLNG). It is comprised of a coalbed methane development operated by Origin Energy and an LNG production project operated by ConocoPhillips.

 

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Finding M&A targets in Permian becoming difficult

A rush of deal-making in the Permian basin in the last year-and-a-half has resulted in private operators cashing in and while the acquirers consolidated assets, it makes further acquisitions a challenge, Diamondback Energy, Inc. chief executive officer Travis Stice said at the company’s second quarter 2023 conference call.

Diamondback acquired Lario Permian, LLC and FireBird Energy LLC late last year, which are now fully integrated into the firm’s operations, said Stice. He didn’t rule out further acquisitions going forward but added that the firm was being very selective with its deals.

“There’s just really few opportunities out there,” he said.

The US$1.5-billion Lario Permian and $1.6-billion FireBird deals were part of a wave of M&A activity over the last 18 months, making Diamondback the fourth biggest spender on Permian deals in 2022, according to Evaluate Energy data.

Activity in the first half of 2023 continued apace with US$23.3 billion of deals which involved Permian assets completed or in progress, compared to US$16.6 billion and US$13.2 billion completed in the first and second half of 2022, respectively, Evaluate Energy data shows.

For more on Evaluate Energy’s M&A database, click here.

Diamondback is being very selective about its M&A strategy going forward, Stice noted.

“There was a rush primarily on the private equity side to get deals into the market,” he said. “Going forward, it’s not important to win every deal. It’s important to win deals that make us not just bigger but better.”

ExxonMobil Corporation chief executive officer Darren Woods echoed this sentiment when he said in the firm’s second quarter results that the firm would continue to be “pretty picky acquirers” in the Permian and elsewhere.

ExxonMobil has been rumoured to be in talks with public Permian player Pioneer Natural Resources Company, but there were no updates on the potential deal during the company’s second quarter conference call.

ConocoPhillips chief executive officer Ryan Lance said the firm was now “mostly focused on the organic side of the portfolio,” with no current plans for acquisitions.

 

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Diamondback’s corporate culture key to drilling efficiencies

A corporate culture focused on driving down costs while driving up well productivity is allowing Permian oil producer Diamondback Energy, Inc. to drill more wells faster while keeping a lid on capital expenditures, chief executive officer Travis Stice said at the company’s second quarter 2023 conference call.

The improved cycle times resulted in Diamondback drilling 98 wells in the second quarter of 2023, a record for the company, and almost twice the 52 wells drilled in the year-ago quarter, as it integrated two large Permian acquisitions into its operations.

Source: Evaluate Energy Company Performance Data

At that pace, Diamondback would drill 400 wells this year, significantly higher than its annual guidance of ~340.

“We’re slowing down the drilling pace in the second half of the year and building a few DUCs,” said Stice. “If this was 2017 or 2018, we’d be stepping on the accelerator and spending more capital, but instead we’re focused on generating more free cash flow in the second half of the year and returning that cash to shareholders.”

The drilling productivity improvements are the result of a corporate culture focused on continuous incremental productivity gains, said Stice.

“I wish I could say it was one individual piece of technology that’s transferable across our entire rig fleet, but it’s much more subtle than that,” he explained. “It’s the culture that we have that has an extreme focus on cost control and efficiencies.”

“And it’s not one or two items, it’s thousands of items that are decided upon [by] every one of these rigs,” he added. “They measure how long it takes to physically screw pipe together for 300 times for every trip that they make — that measurement of just simply screwing pipe together in five minutes versus the next rig over that was six minutes, you think it doesn’t matter, but when you do that several bit trips, bit runs, per well, it adds up. And that’s the level that our organization focuses on efficiency.”

Measuring operational metrics

“What it boils down to is the teams measuring every little thing they can on the rig and measuring which way those operational metrics are trending,” said chief operating officer Danny Wesson. “When a metric is not trending in the right direction, they attack it with a fervor that is unlike anything I’ve ever seen. And that continues to [produce] year-over-year improvements in execution.”

This summer the company drilled two record wells with 7,500-foot (2,300 metres) laterals in under five days, said Wesson. “Those results are remarkable, and we don’t talk about individual well results a lot, but those are the things that we continue to do in the day to day of the company that continue to drive our execution downward.”

“We have a healthy competition among our rigs and completion crews that we incentivize monetarily for efficiency and cost control measures,” added Stice.

Diamondback completed and turned 89 wells to operation in the quarter compared to 62 in the year-ago quarter, a number that Stice said was likely to come down to around 80 for the next two quarters. It expects to complete 330-345 gross wells during the year. The company is running four simulfrac crews which can complete about 80 wells each a year.

The average lateral length for wells completed during the first six months of 2023 was 10,889 feet.

“In this new business model of capital efficiency and profitable value over volumes, we’re focused on running the most efficient plan possible,” said president and chief financial officer Kaes Van’t Hof. “Absent a major change in commodity price, that’s the plan and that allows the teams to plan their business and also allows us to execute at the lowest cost from a capex perspective, so kind of that 15-ish rigs and four simulfrac crews feels like a really good baseline for us.”

Source: Evaluate Energy Company Performance Data

Net production guidance for 2023 has been increased slightly from 430,000–440,000 boe/d to 435,000–445,000boe/d, due to production outperformance year-to-date.

Diamondback had Q2 net income of US$556 million, down from US$1.42 billion in the year-ago quarter, on lower commodity prices.

 

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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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EQT looks to hit net zero targets by 2025

The U.S.’s largest natural gas producer, EQT Corporation, says it is on track to achieve its goal of net-zero Scope 1 and Scope 2 greenhouse gas (GHG) emissions in its production segment by 2025.

EQT plans to achieve the goal largely through operational improvements, rather than the use of offsets. The company made noteworthy progress in 2022, reducing Scope 1 and 2 emissions by 19.8 per cent on 2021 levels to 433,450 tonnes of CO2e, according to Evaluate Energy data.

These figures do not include emissions from the assets acquired in the third quarter of 2021 from Alta Resources Development, LLC, which EQT is reporting separately this year.

EQT has overseen a steady reduction in Scope 1 and 2 production-segment emissions since 2018 (see chart below), despite acquiring some Chevron Corporation upstream and midstream oil and gas assets in the fourth quarter of 2020, which are included in its performance towards the 2025 target.

During 2022 the firm completed a $28-million initiative to replace 9,000 natural gas-powered pneumatic devices in its production operations with electric units. These devices set thresholds and manage liquid levels in vessels such as separators, scrubbers and filters and accounted for 47 per cent of EQT’s Scope 1 production segment GHG emissions in 2021.

The replacement program took two years, but the benefits will not be fully realized in its emissions inventory until EQT reports its 2023 data due to the way emissions from pneumatic devices are calculated under the EPA’s reporting rules, meaning it expects to report further emissions reductions in 2023.

EQT has published a whitepaper highlighting its learnings from the program so that other operators can leverage its experience and implement the processes in their own operations.

Alta assets

The pneumatic drive replacement program was also carried out across the acquired Alta assets, although again the full benefits have not yet been reflected in emissions reporting data.

Production segment Scope 1 and Scope 2 GHG emissions from the Alta assets were cut year-on-year by just two per cent to 107,901 tonnes of CO2e in 2022, far less than the 19.8 per cent cut in the historical assets.

A change in the way emissions from pneumatic devices were reported in the Alta assets following the purchase — from an assumption-based model to a full inventory — led to a year-on-year increase in emissions in the division in 2022. As with the historical assets, the benefits of the replacement program on emissions will not be seen until 2023, when the firm expects a significant reduction below both 2021 and 2022 levels.

Methane emissions intensity

EQT also has a goal to reduce its Scope 1 methane emissions intensity to below 0.02 per cent by 2025.

Between 2018 and 2021 it made good progress on cutting methane emissions intensity (see chart below) due to its combo-development strategy. This strategy focuses on developing multiple multi-well pads simultaneously, reducing infrastructure and therefore opportunities for methane loss.

In 2022 the firm achieved a figure of 0.038 per cent, only a marginal improvement on the 0.039 per cent figure reported in 2021, but EQT expects this figure to improve in 2023, again thanks to realizing the ongoing benefits of the pneumatic device replacement program, and maintains confidence in hitting its 2025 goal.

Unlike the Scope 1 and Scope 2 emissions figures, the methane emissions intensity figure does include emissions and production from the Alta assets.

In November 2022, the Oil and Gas Methane Partnership 2.0 (OGMP) — a multi-stakeholder initiative launched by the United Nations Environment Programme — awarded EQT a “Gold Standard” rating, the highest reporting level under the initiative, in recognition of its reduction targets and commitment to accurately measuring, reporting and reducing methane emissions.

EQT was among 14 upstream companies globally qualifying for the Gold Standard for 2022.

LNG production argument

In recent months EQT has been advancing a climate-centric argument for leveraging U.S. natural gas to replace international coal. For more on EQT’s LNG plans, click here.

“We believe this to be one of most important initiatives available to the world in addressing climate change,” says chief executive officer Toby Rice.

“We’ve got a plan to reshape the world’s energy mix by increasing U.S. LNG exports to connect our affordable, reliable and clean natural gas to the world’s coal consumers.”

The firm says a quadrupling of U.S. LNG capacity to 55 bcf/d by 2030 to replace overseas coal use would reduce global emissions by 1.1 billion tonnes CO2 per year.

 

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EQT Corporation begins testing LNG market

EQT Corporation, the biggest independent U.S. natural gas producer, is dipping its toes in the LNG export market.

EQT has signed a non-binding preliminary agreement with Energy Transfer to sell one million metric tonnes per annum of LNG via the proposed Lake Charles terminal in Louisiana.

The 15-year tolling agreement was signed after EQT spent 18 months evaluating the best way to reach international gas markets.

“This strategy allows us to creatively structure deals with downside price protection, obtain visibility into global downstream markets, and interact with a wide array of potential customers,” said EQT president and CEO Toby Rice during the company’s second quarter conference call.

EQT delivers 1.2 bcf/d, or around 25 per cent of its production, to the Gulf Coast. Around 135 mmcf/d would go to supply the Lake Charles LNG deal.

“We’ve spent the last year and a half studying the nuances of LNG export opportunities and believe the strategy we are pursuing provides the best combination of upside exposure with downside risk mitigation relative to the netback structures that are commonly being signed,” said Rice.

The exact structure of the deal wasn’t revealed but it will give EQT some exposure to international LNG prices rather than selling on a Henry Hub basis, where prices have historically been much lower.

Source: Evaluate Energy Company Performance Data – find out more here.

Getting the deal in place with Lake Charles is the first stage in the process of selling to international buyers. The second stage is to sign a sales and purchase agreement (SPA) with the buyers themselves, where the firm will also seek 15-year deals to match the tolling agreement.

“We plan to pursue signing one or more SPA with prospective international buyers and have additional opportunities to increase our tolling exposure,” said Rice. Talks with buyers are already underway and EQT is seeking a deal with a price floor and ceiling to provide “energy security” to prospective customers, he added.

LNG Facility Investments

The firm initially considered taking an equity investment in an East Coast LNG facility as the best way to gain exposure to international markets, but eventually decided that a tolling agreement was a better option. However, it did not rule out an equity stake in the future.

“We’re not looking to make investments … but there could be opportunities where, from a risk mitigation perspective, it makes sense for us to make a small investment in an LNG facility,” said Rice.

EQT has not set any targets on the proportion of its gas it will sell via LNG but aims to be opportunistic with deals depending on market conditions. In his concluding remarks Rice said the Lake Charles deal represented an “initial step” in EQT’s LNG strategy.

Earlier this year the firm launched a campaign calling for the U.S. to quadruple its LNG export capacity to 55 bcf/d by 2030 to replace overseas coal use. Modelling by the firm showed such a scenario would reduce international CO2 emissions by 1.1 billion metric tonnes per year.

Lake Charles Developments

Energy Transfer signed two other agreements for Lake Charles earlier this month.

  • Under the first deal a Japanese consortium would purchase 1.6 million metric tonnes per annum for a 20-year term.
  • Under the second deal Chesapeake Energy Corporation would supply one million metric tonnes per annum to Lake Charles for 15 years, which trading house Gunvor would purchase at a price indexed to the Japan Korea Marker (JKM).

Lake Charles has an authorization from the Department of Energy (DoE) to start non-FTA LNG exports by December 2025.

In April this year, the DoE declined a request from Energy Transfer to extend the deadline to start exports to December 2028, and last month declined a rehearing request.

Energy Transfer has not yet made a final investment decision (FID) on the Lake Charles project.

 

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EQT pushes well performance boundaries at Appalachian shale play

U.S. natural gas giant EQT Corporation continues finding ways to drive drilling and completions productivity levels higher at its Marcellus and Utica shale gas development.

A benchmarking exercise carried out by EQT during the quarter found the company’s recent southwest Appalachian wells were being drilled 68 per cent faster than the average of its peers, the company reported at its second quarter conference call.

Source: EQT Q2 Results Presenation. For more on Evaluate Energy Documents, watch a short video here or click here for more information

“A horizontal EQT rig drilled roughly 300,000 more lateral feet per year relative to our peer average,” said EQT president and CEO Toby Rice.

One rig crew set a new world record by drilling 12,318 feet in 24 hours on a well in Greene County, Pa., Rice added. Meanwhile EQT’s completions team stimulated a record 20,880 lateral feet on a separate well.

“At nearly four miles this is one of the longest completed laterals in the history of U.S. shale development and an internal record,” said Rice, noting that completion efficiency was up 20 per cent against the year-ago quarter.

The drilling and completions performance helped EQT achieve a total sales volume of 471 bcfe during the second quarter, towards the top end of its 425–475 bcfe production guidance, according to Evaluate Energy data.

The achievement came despite lower-than-expected liquids volume from downtime at a Shell plc ethane cracker and other third-party issues which negatively impacted production by 12 bcfe compared to the forecast.

Back on track

EQT production is on track to return a 500 bcfe quarterly rate in the third quarter as third-party issues are resolved and drilling and completions continue apace. The company has maintained its expectation of 1,900–2,000 bcfe total sales volume for 2023.

It also hopes to complete its US$5.2 billion acquisition of the Tug Hill and XcL Midstream assets in the third quarter, following Federal Trade Commission (FTC) approval in the next month.

The assets will add an estimated 800 mmcfe/d to EQT’s production in the Appalachian region, as well as 95 miles of midstream gathering systems connected to long-haul interstate pipelines in southwest Appalachia.

The deal was initially announced in 2022 and has been under FTC review since then. Our review of the deal can be found here.

“It’s been a long process, but we see light at the end of the tunnel,” said Rice. “One of the guiding principles for us as we were going through this process is to make sure that we preserve the economics of the deal that we signed off, and I feel like we’re going to be able to deliver that and also preserve strategic flexibility going forward.”

The assets are expected to lower EQT’s pro forma corporate free cash flow breakeven price by approximately $0.15/mmBtu until 2027.

EQT’s production guidance does not include the impact of the Tug Hill and XcL Midstream acquisitions.

 

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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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