Massive global LNG infrastructure build out under way

The Ukraine war has brought energy affordability and security to the forefront, with countries around the world looking to lock-in long term supply for industrial feedstock and electricity generation.

With its lower carbon dioxide emissions compared to coal, natural gas demand is growing in Europe as countries look to replace Russian supply while managing climate change commitments. In the Asia Pacific, demand is increasing for petrochemical, fertilizer, steel, and cement production to meet economic growth targets, along with increasing public demands for reliable, affordable electricity.

Increasing gas demand is resulting in a boom in LNG related infrastructure construction, according to a new Evaluate Energy Briefing Note entitled: Linking North American LNG Supply to Asia-Pacific Markets.

Construction of regasification facilities saw a major jump in Europe in 2022, with 20 mtpa added as Russian gas was removed from the market, according to Evaluate Energy data.

EU import capacity is set to expand by one-third by the end of 2024, according to the U.S. Energy Information Administration (EIA). Germany expects to have six terminals operational by the end of 2023 capable of processing 3.7 bcf/d. Another 4.9 bcf/d of capacity is planned or underway across the EU.

Asia-Pacific is expected to add around 230 mtpa in regasification capacity by 2030, an increase of almost 42 per cent. In China, 8.5 bcf/d of new regasification capacity is being built. India expects 1.3 bcf/d of capacity to be online by the end of 2023.

About 80 per cent of new LNG supply between now and 2030 will be from Qatar and the U.S., with Qatar adding 48 mtpa of liquefaction and the US adding nearly 96 mtpa, according to Evaluate Energy data. Other countries adding liquefaction capacity include Mozambique (20 mtpa), Canada (16 mtpa) and Australia (12 mtpa), assuming all active projects reach completion according to current plans.

By 2030 North America will have almost 40 per cent of global LNG production capacity, positioning it to be the major supplier of gas to Asia.

“This new supply will reshape global trade flows,” said report author Tom Young. “Portfolio players and trading houses will look to optimize their portfolios by taking a multi-basin approach, meaning that they will use sources of supply from various contracted volumes around the world to meet both short- and medium-term demand, minimizing the number of long journeys taken by vessels without cargoes, rather than the more traditional approach of point-to-point contracts.”

 

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Permian deals pass $400 billion since 2014 after Exxon mega-deal

Record-breaking productivity levels and low-cost production have seen the Permian Basin attract major M&A activity in the U.S. upstream sector.

In fact, following ExxonMobil’s $64.5 billion mega-deal to acquire Pioneer Natural Resources, Evaluate Energy data shows that the basin has now passed $400 billion in new deals agreed over the past decade.

For comparison, U.S. deals agreed without any Permian assets now account for $375 billion combined after Chevron’s own $60 billion mega-deal to acquire Hess Corp. was announced this week.

Deal values approach $100 billion in 2023 alone

Deals involving Permian assets account for 52% of all U.S. activity since the start of 2014 by value.

  • ExxonMobil’s acquisition of Pioneer means that 2023 is a record year for Permian-related spending, with deal totals approaching $100 billion for the first time.
  • The previous annual record in 2019 was also primarily down to one mega-deal that included Permian assets, when Occidental Petroleum won a bidding war with Chevron to acquire Anadarko Petroleum for around $55 billion.

Both years would have been below $40 billion in deals agreed without the two major deals boosting totals.

Production of over 6 million boe/d traded

The same ~900 deals that included Permian assets saw 6.1 million boe/d change hands since 2014*. This represents 40% of all U.S. production involved in M&A deals over the same timeframe.

We can attribute the large volumes traded in 2019 and 2023 to the Occidental/Anadarko (743,000 boe/d) and ExxonMobil/Pioneer (711,000 boe/d) deals, which alone comprise approximately half of the annual totals in those years.

Without those mega-deals, 2020 is arguably the “most active” year for Permian Basin M&A.

This was a year characterized by many mergers taking place across the U.S. for depressed values and low premiums.

Permian-related deals at this time included:

  • ConocoPhillips acquiring Concho Resources for $13.3 billion
  • Devon Energy acquiring WPX Energy for $5.7 billion
  • Chevron acquiring Noble Energy for $13.0 billion (although DJ Basin assets were the focus for Chevron)

Permian unsurprisingly dominates the top 10 U.S. deals by value in the past 10 years

Source: Evaluate Energy M&A 

*Full production from all basins in any deal including Permian production is included in this total. This does not represent purely Permian basin production traded.

 

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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Chevron boosts oil and gas reserves by 11% with Hess deal

As Chevron doubles-down on future, sustained oil and gas demand, its acquisition today of Hess Corp. increases Chevron’s proved reserves by 11% to approx. 12.5 billion barrels of oil equivalent, based on latest annual figures available via Evaluate Energy.

Source: Evaluate Energy

Global production of the combined entity is 13% higher than Chevron’s latest production rate, based on Q2 data analysis today by our London team at Evaluate Energy. The new total production worldwide is 3.3m boe/day. Of that, US production will total 1.4m boe/day – a 17% increase for Chevron based on Q2 production.

Source: Evaluate Energy

Chevron’s all-stock deal equates to $53 billion – plus $7 billion of debt for a total enterprise value of $60 billion. It follows ExxonMobil’s recent $64.5 billion deal to acquire Pioneer Natural Resources.

Source: Evaluate Energy M&A 

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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Q3 upstream deal values drop 34% below five-year average

Q3 upstream oil and gas M&A spending was 34% below the five-year quarterly average and 42% down on Q2 with $21 billion in new deals announced.

Full deal details are available within Evaluate Energy’s M&A database. Click here for details.

Key Q3 observations

  • Eight of the top 10 deals by value were oil-focused.
  • Payback multiples remain low: median EBITDA multiples were 2.9x compared to 7x over the past decade.This indicates the market has little faith in the current high earnings environment continuing in the medium- to long-term.
  • 78% of deal activity by value focused on U.S. and Canadian assets.
    • ExxonMobil agreed a $4.9 billion deal to acquire Denbury in the largest deal (more below).
    • Permian Resources Corp. will acquire Earthstone Energy for $4.5 billion to create a $14 billion premier Delaware Basin operator.
      • For more on the Permian Basin, click here for why Diamondback Energy’s CEO thinks M&A targets are getting tougher to find
    • Strathcona Resources acquired Pipestone Energy in Canada’s largest deal, valued at around C$1 billion.
  • Approximately 400,000 boe/d changed hands; the lowest quarterly volume since Q2 2020.

While deal activity was down, prices were up

  • WTI ($80.83) rose 10% on Q2 2023 levels
  • Henry Hub gas prices ($2.50) rose 19% since Q2, although this represents the second lowest quarterly average since 2020

ExxonMobil secures carbon capture assets with Denbury

In many ways, Denbury’s oil and gas production in the Gulf Coast and Rocky Mountains regions represents a perfect bolt-on acquisition to ExxonMobil’s U.S. upstream portfolio.

While this remains Denbury’s predominant business, its extensive carbon capture infrastructure and future storage potential – currently reported at around 2 billion metric tonnes – is very attractive.

The $4.9 billion deal equates to an EBITDA multiple of nearly 8x – a sum far more in line with corporate mergers of years gone by that shows just how much value ExxonMobil attributes to this carbon capture asset base.

The deal will instantly improve ExxonMobil’s ESG rating and open up an extra revenue stream; the new U.S. Climate bill provides tax credits of $85 per tonne of carbon stored permanently or $60 per tonne of carbon used in enhanced oil recovery.

ExxonMobil followed the Denbury deal with two more carbon capture agreements:

  • Extending a carbon capture technology collaboration with FuelCell Energy Inc. (July).
  • Securing four licenses in the U.K.’s first carbon capture licensing round (September).

Top 10 deals by value – Other supermajors in low carbon or renewable sectors

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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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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