Author: Tom Young

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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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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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

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.

Shell

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

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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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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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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Chevron back on track to push Permian production toward million barrel a day target

U.S. supermajor Chevron Corporation achieved record Permian Basin production of 772,000 boe/d in the second quarter of 2023, up 11 per cent compared to the same quarter of 2022 and up five per cent from its previous record quarterly production of 738,000 boe/d in the final quarter of 2022.

The company addressed ongoing issues with well interference in the Delaware Basin area of the Permian in the quarter, helping to get production back on track towards its goal of surpassing one million boe/d of production by 2025.

“We expect Permian production in the next quarter to be flat before growing again in the fourth quarter, on track with full-year guidance,” said chief executive officer Mike Wirth.

Chevron’s full-year guidance is for 745,000 boe/d, an over five per cent increase from last year’s production of 707,000 boe/d.

At its investor day earlier this year, Chevron said it expects its Permian assets to produce one million boe/d by 2025 and plateau at 1.2 million boe/d later this decade, accounting for around one-third of its total production.

Despite the healthy production levels, Chevron reported a 48 per cent fall in net earnings from the year-ago quarter, primarily due to lower oil and gas prices. Net cash flow from operating activities fell to US$6.3 billion from $13.8 billion in the year-ago quarter.

Meeting guidance

The record production from the Permian offset lower production in other parts of Chevron’s portfolio, helping keep the firm on track to meet its full-year guidance.

Evacuations because of wildfires in Canada and an accident at the Benchamas oilfield in the Gulf of Thailand that suspended operations negatively impacted production.

“Those two things are the ones that are pushing us down, both unexpected,” said Wirth.

Chevron expects upstream turnarounds and downtime to reduce production by about 110,000 boe/d across its global portfolio in the third quarter.

It plans to increase its production in the United States with the recent acquisition of PDC Energy, Inc., which closed in August.

The company expects the PDC acquisition to grow production in the Denver-Julesburg basin to 400,000 boe/d from 140,000 boe/d.

Chevron reported annual production of three million boe/d worldwide last year. It forecasts production to be flat or to increase by three per cent annually from those levels annually through 2027.

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

 

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