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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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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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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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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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 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.
  • View the top 10 deals of Q3 at this link.
• 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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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 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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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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