European and U.S. upstream firms diverge on low-carbon technology deals

Europe remains the focal point for E&Ps investing in M&A power deals that utilize low-carbon solutions such as solar and offshore wind.

E&P companies engaged in 231 power deals between 2021 and 2023. This represents around 10% of all power deals worldwide, according to Evaluate Energy data. Only 13 of these power deals involved fossil fuel-based technologies.

Ninety-nine deals were targeted in Europe, followed by North America with 45. The data illustrates that many EU firms have moved into renewable power while U.S. firms focus on renewable fuels, hydrogen and CCUS.

The five leading E&Ps executing power deals were all European: TotalEnergies (38), Shell (27), Eni (26), Equinor (21), and BP (15). Only seven deals of North America’s 45 were agreed by U.S.-based E&P companies – and three of these were by one firm, Genie Energy, a provider of green and conventional electricity and natural gas supply plus solar energy solutions.

Regional spread

Not all deals done by European firms were EU focused. Firms’ net zero targets require them to reduce carbon intensity across their entire portfolio. This means renewable schemes in any geography count towards the overall target. Regions outside Europe often have cheaper construction costs and more abundant solar and wind resources.

Of the 38 deals done by TotalEnergies, only 12 were situated in Europe, with the rest in Africa, Central Asia, or Asia-Pacific.

Of the 27 deals by Shell, only 10 were in Europe. The rest were in Central Asia, Asia-Pacific, North America, or Latin America.

Eni was more European-focused, with 19 of its 26 deals taking place in Europe, with the remainder in North America, Central Asia, or Asia-Pacific.

Technology mix

Solar is by far the largest investment segment, with just under a third of all E&P power deals (78). They are spread mainly across Europe (26), North America (15) and Asia-Pacific (15). There are notable deals outside those regions – including BP’s 40.5% equity stake in the Asia Renewable Energy Hub (AREH) in Australia.

Offshore wind is the next largest segment with 51 deals. Offshore wind is often a good fit for oil and gas firms using marine and project management experience to add value.

Onshore wind has seen less interest with 31 deals.

Electric vehicle charging infrastructure saw 16 deals by E&Ps. Notably six of these were done by BP. One of the biggest BP deals involves a joint venture with Spanish utility Iberdrola to invest €1bn ($1.08bn) in 5,000 EV charging stations in Iberia by 2025 and 11,700 by 2030.

Shell is also looking at EV charging with three deals in the space, two of which involve working with original equipment manufacturers — China’s Nio and GM in the U.S.

The geothermal sector saw 12 deals – two by Chevron. There is growing geothermal interest amongst U.S. E&Ps after development funding was released by the Biden administration. The U.S. House Energy and Commerce Committee last month passed a bipartisan bill to streamline geothermal project permitting.

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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Diamondback will almost double production base in $26bn Endeavor deal

The $26 billion acquisition of Endeavor Energy by Diamondback Energy is the fifth multi-billion-dollar corporate merger already in the U.S. this year and takes U.S. upstream deal spending to over $45 billion, according to Evaluate Energy data.

Diamondback says the deal will almost double its Permian Basin production base to over 800,000 boe/d by 2025, as well as provide:

  • A combined asset base of 838,000 net acres in the Permian Basin
  • 6,100 pro forma locations with break evens at under $40 WTI
  • Annual synergies of $550 million representing over $3.0 billion in NPV10 over the next decade

Last August, Diamondback had finalized the integration of assets acquired for a combined $3.1 billion in late 2022 and early 2023. “Going forward, it’s not important to win every deal,” said Diamondback CEO Travis Stice at the time. “It’s important to win deals that make us not just bigger but better.”

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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CCUS deal-making by upstream oil and gas firms is rising

Global interest among E&P firms in Carbon Capture, Utilization and Storage (CCUS) project deal-making is starting to ramp up.

95 CCUS-related deals have been announced over the past three years involving upstream companies based on Evaluate Energy data. This represents around 53% of all CCUS deals worldwide since the start of 2021, and 2023 saw the ratio increase to 63%.

Equity financing and interest in project finance for CCS projects has increased significantly over the past 12 months, as national funding strategies start to emerge, according to the Global CCS Institute’s ‘Status of CCUS report’. A U.S. CCS tax credit regime was established in 2023 and an EU strategy is due this year.

Majors lead the way

Malaysia’s Petronas is the most active with ten CCUS-related deals. All were co-operation deals, as the firm looks to evaluate its involvement at various points in the value chain. Two involve evaluating storage sites, four evaluating the potential of CO2 shipping, and one the development of a storage hub in the Java Sea. The remainder relate to an interest more broadly in investigating the technology.

Chevron is the second most active with nine deals. One involves a 50% equity stake in the Bayou Bend CCS project in Southeast Texas, where Talos Energy and Equinor also have stakes.

Chevron also has interest in the firms Carbon Clean and Svante, as well as Blue Planet Systems, a building material CO2 sequestration developer. Chevron’s other deals signal broad co-operation in investigating the technology, albeit with a wide geographical footprint — the firm has deals in Australia, Indonesia, Kazakhstan, and the U.S. Chevron already runs a significant CCS project at its Gorgon LNG plant in Australia.

ExxonMobil is the third most active in the sector with eight pure CCS deals, which rises to nine if the company’s $4.9 billion deal to acquire U.S. oil and gas producer Denbury Inc. is included, due to CCS potential forming a huge part of ExxonMobil’s motivation for the deal.

ExxonMobil has entered into two deals on capture testing projects, both in the U.S. The first is a partnership with technology firm FuelCell Energy assessing the latter’s capture technology, and the second is a partnership with steel firm Nucor assessing a full CCS value chain at Nucor’s manufacturing site in Convent, Louisiana. Unlike Chevron, ExxonMobil is yet to take an equity stake in CCS technology firms.

Shell is the next most active company with seven deals. One involves participation in the same UK licensing round as ExxonMobil to investigate North Sea storage locations. Shell will work with ExxonMobil on three locations and evaluate a further two, while ExxonMobil won the license for a further location of its own. Shell’s remaining CCUS deals involve co-operation across various parts of the value chain.

Around the world

The U.S. has seen 29 deals by E&P firms over the past three years, reflecting the dominance of U.S. firms in CCS deals and the U.S. CCS tax credit regime, put in place last year.

Asia-Pacific has seen 27 CCS M&A deals. The region has significant potential for growth and a number of projects are being developed. This includes the Arun project in Indonesia, which has potential to sequester one billion metric tonnes of CO2 and may include open access storage, paving the way for a network of capture projects.

Europe is the next most popular region with 22 deals, which includes 12 E&P companies awarded licenses for storage locations in the UK’s first license round. The EU doubled funding for CCS to €3bn in 2022, and issued its second call for projects last year, meaning there is likely to be a further uptick in activity as the value chain develops.

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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Creating a sustainability-ready workforce within oil and gas – New whitepaper

Securing and nurturing a qualified, sustainability-ready workforce is more crucial than ever amid the dynamic changes in the oil and gas industry.

Many operators and services companies face a shortage of professionals equipped with the necessary skills and knowledge.

Fortunately, innovative training programs are available today that can help build a workforce ready to meet the sustainability challenges and opportunities ahead.

Evaluate Energy ESG Learning has released “Creating a sustainability-ready workforce within oil and gas” – a new whitepaper highlighting the vital role of training to attract and retain talent.

“Our work with the industry over the last few years has demonstrated that there is a genuine need to think differently about the human capital and talent development strategy for the industry,” said Bemal Mehta, Head of Evaluate Energy ESG Learning. “We are hoping that the whitepaper helps foster an essential conversation. We’re going to need an immense amount of talent to achieve major goals such as Net Zero.”

Download this whitepaper to gain insights into:

  • Why this training/skills issue matters so much today, and the impact of inaction
  • Equipping your new sustainability-ready workforce
  • Key factors driving the retention and training of skilled professionals
  • The impact of innovative sustainability training programs on reshaping the perception of the energy industry
  • Sustainability training options for your new workforce

Download Creating a sustainable-ready workforce within oil and gas here.


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Europe and US dominate hydrogen deal-making by E&Ps

Europe and to a lesser extent the United States remain focal points for hydrogen project deal-making by E&P companies.

Evaluate Energy data shows that E&P companies were involved in 112 hydrogen sector deals between 2021 and 2023, which represents around 33% of all hydrogen sector deals worldwide over the three-year period.

The mix of deals is interesting – a blend of production-focused plays and downstream technologies. TotalEnergies, Shell and Chevron led the way. Hydrogen deal volume has slowed, however, and was noticeably light in 2023.

Over half the deals took place in Europe or the United States.

Deal locations reflect the reality that Europe and North America are more advanced in their hydrogen strategies and subsidy regimes. The US instigated its tax credit subsidy regime last year. The EU published its hydrogen strategy in 2020 and held the first pilot auction under its Hydrogen Bank subsidy scheme at the end of last year. These are vital in helping firms reach final investment decisions (FID) on production projects.

Of the 112 deals:

  • 67 reference hydrogen production
  • 23 mention co-operation on specific pilot projects
  • 10 involve collaborating with companies in the midstream to develop hydrogen distribution or storage solutions
  • Nine revolve around hydrogen re-fuelling solutions or downstream fuel cell development.

For those that involve establishing pilot projects, once these are running it will be another couple of years before firms reach FID on a commercial scale project.

Only one deal so far — Abu Dhabi state oil company ADNOC acquiring a 25% stake in H2 Teeside — outlines a concrete equity stake in a project, signaling ADNOC’s confidence it will get to FID.

A recent report by the Hydrogen Council notes that just seven per cent of announced investments into hydrogen projects have passed FID to date.

“Projects are expected to commence first in mature markets, before large greenfield installations integrated with renewable energy sources gradually…become another important market segment,” reflected Norwegian electrolyzer manufacturer Nel in its Q1 2023 market outlook.

That wave of activity may lead to a second round of M&A deals as E&P companies take further equity stakes in hydrogen production projects, although many will also be looking to raise finance via debt.

M&A activity further down the value chain for hydrogen — whether that be supporting infrastructure such as storage and pipelines, shipping and transport or downstream applications such as mobility and fuel cells — could also be expected to pick up from 2025 as FIDs on hydrogen supply projects, the key enabling factor, trigger firms to form JVs or transform MOUs into equity stakes in the downstream.

Most active acquirers


TotalEnergies was the most active E&P company in the sector in terms of deal making over the three-year period with 13 deals. Alongside a series of co-operation deals, the French major agreed deals to acquire interests in companies active in both India’s green hydrogen sector and Europe’s hydrogen vehicle space.


The E&P company with the next strongest M&A interest in the sector was Shell, with 12 deals. All but one were co-operation deals. Shell’s single corporate deal was to invest in Hydrogen Mem-Tech, a firm that has developed a technology to produce clean hydrogen from biogas and natural gas.


Chevron did nine deals in the same period. Four relate to hydrogen production. The rest address downstream technologies. Of the four corporate deals agreed by the U.S. supermajor, three relate to downstream: an outright purchase of storage firm Magnum Development, a stake in refuelling firm OneH2, and a stake in distribution firm Aces Delta.

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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Europe leads oil and gas M&A activity beyond the U.S.

Europe saw almost $20 billion in new upstream oil and gas deals agreed in 2023. This leads all regions outside of the United States, according to Evaluate Energy data.

A December agreement between Harbour Energy and Wintershall Dea was the highlight. Harbour will acquire substantially all of Wintershall’s upstream assets and European CCS licenses for just over $11 billion.

Canada was the other non-U.S. ‘region’ to see more than $10 billion in new deals. This was driven by:

  • TotalEnergies’ decision to sells its Surmont oilsands interest to ConocoPhillips and its remaining Canadian business unit to Suncor
  • Two Montney-focused deals by Crescent Point Energy.

For more on global M&A activity and a focus on U.S. deal-making in 2023, click here.

* The Middle East has numerous deals where transaction details are not disclosed.

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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Global M&A tops $200 billion – largest upstream deal spend in over a decade

Mega mergers involving ExxonMobil, Chevron and Occidental Petroleum in Q4 skyrocketed 2023’s upstream deal value to $234 billion, based on Evaluate Energy data.

That equates to the largest annual spend in over a decade, and just $2 billion short of the largest recorded since Evaluate Energy’s M&A database launched in 2008. It is only the fourth time since 2008 that spending has topped $200 billion.

Deal counts point to a down year without Q4 activity

2023 spending was driven by three individual deals to a far greater extent than we have seen historically:

While each of the banner years 2009, 2010 and 2012 included at least one upstream deal valued at over $25 billion, in each case deal volume played a much more significant role in generating over $200 billion in M&A spending. 2023 managed to hit a comparable deal value despite a vastly reduced number of deals valued at over $100 million and $50 million.

U.S. predictably dominates

With the ExxonMobil and Chevron mega deals approximating a combined $125 billion, the U.S. dominated global deal values in 2023.

Excluding these two deals, the U.S. upstream sector still saw over $25 billion more in M&A deals agreed in 2023 than the rest of the world combined.

Much of this activity was focused on the Permian Basin – which has now amassed over $400 billion in new deals in the past 10 years.

Eight of the ten largest upstream deals were U.S. focused, including smaller deals for both ExxonMobil and Chevron. ExxonMobil completed the $4.9 billion acquisition of Denbury in November. Chevron finalised its acquisition of DJ-Basin focused PDC Energy for $7.6 billion in August.

Top 10 upstream oil and gas deals in 2023

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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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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Low supply costs key in emerging LNG export markets

Asia-Pacific gas demand is forecast to grow by at least 50 per cent by 2040, but only the lowest cost LNG suppliers will win a piece of this demand, according to a just released Evaluate Energy Briefing Note: Linking North American LNG Supply to Asia-Pacific Markets.

Because Asia-Pacific countries have sustained demand, they want to enter or renew long-term contracts to ensure lower cost supply, rather than taking the European approach of shorter-term contracts or relying on spot cargoes from portfolio players.

As of 2023, 146 long-term contracts, covering 195 mtpa of volume, exist in Asia. These totals will drop to 96 contracts and 146 mtpa by 2030.

“This will create an interesting moment for pricing as Qatari, U.S., Australian and Canadian capacity comes online during this period,” said Tom Young, author of the Briefing Note. “Qatari and Australian sellers seem committed to oil indexation, despite the increasing disconnection between oil and gas markets. Asian buyers will want the cheapest prices possible, and to avoid getting caught in a repeat of the scramble for expensive spot cargoes that took place in 2022.”

One recent bellwether is the deal signed between QatarEnergy and Sinopec, said Young. The 27-year deal is for 4 mtpa, one of the longest contract durations in the sector.

There are other price-sensitive buyers in Asia that are likely to become increasingly significant LNG importers, including India, Vietnam and Bangladesh.

“Traditionally India has been an opportunistic buyer, only willing to enter the market at US$10/mmBtu or below,” said Young.

While industrial demand provides a base for LNG imports in Asia, the power market will provide most growth going forward. LNG exports must be competitive with other energy sources including coal and renewables. The analyst consensus is LNG is competitive in emerging markets at under US$10/mmBtu.

Suppliers like Canada will compete on cost

LNG supply costs depend on facility capital costs, upstream gas supply costs, midstream liquefaction costs, and transportation costs. Most exporters are advantaged or disadvantaged in at least some of these areas.

“For example, Canada has higher upfront costs than a comparable facility on the U.S. Gulf Coast. It also has significantly higher upstream transportation costs to pipe gas to liquefaction facilities,” said Young. “However, Canada’s liquefaction costs are lower due to its cold climate, and it also has a geographic advantage in reaching Asian markets (see graph below).”

A recent Canadian Energy Centre study shows Canada in the middle of the pack when it comes to upstream natural gas supply costs. The Canadian natural gas sector had a weighted average breakeven gas price of US$2.31/mcf in 2022, fifth lowest among major natural gas producing countries, behind Saudi Arabia ($1.09/mcf), Iran ($1.39/mcf), Qatar ($1.93/mcf) and the United States ($2.22/mcf).

However, the Montney play where LNG supply will be sourced had a breakeven price of $1.49/mcf, lower than the largest LNG exporters in the world — Qatar and the U.S.


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