US February Oil Production Marginally Higher

120 thoughts to “US February Oil Production Marginally Higher”

1. Rig Report for the Week Ending May 2

   This week’s rig count is the first sign that low oil prices are affecting the count. However the combined rig count of the 4 big Permian counties was up by 1. Eagle Ford and Ohio were the biggest losers by dropping 3 each. NG was up.
   – US Hz oil rigs were down 6 to 437.
   
– New Mexico rigs were unchanged at 90 while Texas dropped 4 rigs to 228. Texas Permian was down 2 to 184.
   

– In New Mexico, both Eddy and Lea were unchanged at 45 and have held there for 4 weeks.


   – In Texas, Midland added 2 to 23 while Martin dropped 1 rid to 25. Midland is down 4 rigs over the last 6 weeks.
   
– Eagle Ford dropped 3 to 38.


   – NG Hz rigs added 3 to 85.

   

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2. Frac Spread Report for the Week Ending May 2

   The frac spread count dropped by 4 to 201. It is also down 51 from one year ago and down by 40 spreads since October 11.

   

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   1. https://x.com/MrGlobal2025/status/1918708456992682420

      “Oil Markets to Collapse Monday” ???

      https://youtu.be/Fzefz-_ywqg

      Reply

      1. https://www.zerohedge.com/commodities/we-are-tipping-point-shale-giant-diamonback-says-us-oil-output-has-peaked-slashes-capex

         Low prices have bad consequences… on the industry…

         Reply

3. Almost 400kbarrels/day under the projection and no serious increase in price…?

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   1. Svaya,

      Oil prices are determined on the World Market which seems to be oversupplied,especially with recent OPEC announcements to increase output and a possible Worldwide Recession that many expect due to Trump Tariffs which will reduce World Oil consumption.

      Also keep in mind that most oil analysts realize the EIA STEO is often wrong. It will be interesting to see the EIA revisions in May to the STEO, though in a Trump executive branch one wonders if these will only become worse in the future as pressure may come from the White House to alter forecasts to their wishes. The independence of agencies from political pressure seems to be at a low point.

      Something to watch.

      Reply

      1. DC

         Of course numbers are fake or messaged at the very least for political or economic gain. Biden’s jobs being created in an election year overstated by some 815,000 jobs is a prime example.

         This type of shit goes on everywhere under every politician. China’s GDP is fake and to a certain extent so are the GDP numbers in the US.

         Which is why using GDP numbers to calculate or forecast anything is meaningless. Because the numbers aren’t real to begin with.

         Oil producers overstating their reserves is another prime example of what is happening for political and economic gain.

         Corruption is widespread. We don’t have any honest folks in power anywhere.

         Reply

         1. HHH
            Only the gullibles believe the numbers.

            Reply

      2. >Also keep in mind that most oil analysts realize the EIA STEO is often wrong.

         Ok but that doesn’t change the fact that it’s >300Kbarrels/day under the December 2024 peak. But then the markets are chaotic anyway so I wouldn’t be surprised if it increases next weeks and month.

         Reply

         1. Svaya,

            The price of oil is screaming recession. The economic background doesn’t support higher oil prices.

            OPEC gave up on their supply cuts because they didn’t work to keep prices higher. Contrary to popular belief OPEC isn’t in the driver’s seat controlling oil prices. Though they can send prices even lower by increasing production during a global recession.

            What we are going to get is interest rates cuts and back to QE everywhere. Not that either of those things matter but that’s the direction we are heading. The fact that they will be doing both is just an acknowledgement of how bad the economic background actually is.

            Low to no growth environment.

            Remember that the dollar denominated debt that exists outside the US in the Eurodollar market isn’t owed to the US. The banks outside the US created all that dollar denominated debt. The rest of the world owes those dollars to themselves collectively.

            Got dollars? Because absolutely everyone outside the US needs dollars to repay the debt. They don’t need gold or bitcoin or their own local currencies. They need dollars.

            What’s it going to look like outside the US if the banks in Japan lending the dollars into China get defaulted on?

            The world can’t leave the dollar system without defaulting on themselves.

            The scramble for dollars outside the US will continue. And sometimes that scramble for dollars will involve the selling of US dollar denominated assets.

            De-dollarization implies the value of the dollar going through the roof.

            Re-dollarization implies the dollar going back to 2008 lows.

            If you pull out a long term chart of both WTI, Brent and DXY you’ll see that oil prices at their all time highs coincided with the dollar being at an all time low.

            It was because credit in the Eurodollar market was flowing freely prior to 2008. Not so freely ever since 2008. Credit is still flowing but the cost of obtaining credit has gone much higher since 2008. Not talking about just interest rates. Talking about collateral and what it cost to actually borrow money. And a lot of the time collateral is borrowed in order to obtain credit in REPO.

            Dollars are just more expensive to obtain now than they were in 2008.

            Reply

            1. HHH, I don’t understand since the banks originated the loans, why can’t they just tell their customers that they will accept a different currency instead of us dollars in repayment (a kind of bank-customer currency swap deal at rates both parties can live with), and at least circumvent a scramble for dollars?

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               1. Phil S,

                  You can go into the FX market and sell Yen or Euro’s or whatever currency you have in order to buy dollars. It’s more costly to do than just borrowing. But banks will generally do it. At least for most of the major currencies that aren’t the dollar.

                  And since all those other currencies are in fact loaned into existence instead of printed. It will create a shortage of their local currencies which will create problems in their local economy’s. Because they are creating bank liabilities in their own currencies that have to be repaid in their own currencies. But are buying dollars.

                  Banks want to be repaid in a currency that is accepted everywhere as money. The Chinese yuan isn’t money globally. Eurodollars are money globally.

                  If banks accepted other currencies for dollars denominated debt directly it’s no different Then selling Yen or Euros or whatever and buying dollars.

                  It will create Yen and Euro and whatever currencies shortages. Because of the liabilities of bank balance sheets when money is loaned into existence.

                  The idea of a free lunch by just printing money to repay debts is a false idea.

                  Government debts aren’t really ever paid back. They are just expanded. Rolled over with new debt at maturity.

                  However private debts are repaid every month. Which shrinks the actual money supply. So we need economic growth in order to repay debt and energy in order to grow.

                  Without private growth tax receipts fall. And government’s income get cut.

                  Government debts are financed through money created on the balance sheets of commercial banks. There is a bank liability somewhere on some banks balance sheet that has been used to purchase those government treasury securities.

                  All loans are liabilities on one bank balance sheet and deposits on another banks balance sheet.

                  People think money is free and clear from any debt because they went and earned it. No! There is a bank liability on some banks balance sheet where the money used to for your paycheck is owed to a bank by someone.

                  It might indeed be free and clear for you to use but it’s still owed to some bank somewhere because it was loaned into existence.

                  I subscribe to a relatively fast collapse of BAU as we know it because the debts aren’t payable in a energy contracting world.

                  It doesn’t matter if we still have a lot of oil, coal and natural gas. It doesn’t matter if we can build solar panels and windmills to produce electricity.

                  What matters is can we grow or not. And governments are hiding issues by overstating GDP numbers and job numbers and so on.

                  In a true energy transition. Solar and wind energy would have to repay all the debts incurred during the time before the energy transition took place when FF were what was used.

                  I’m not buying that idea.

                  There will be no growing our way out from under our debt. Mass insolvency and hyper-deflation is the future.

               2. Banks can do that but that doesn’t change anything. The dollar deposits were created when the bank made a loan and the only way to “uncreate” the deposits is to pay off the loan. So it doesn’t really matter who holds the deposit – it exists and there is no other way to get rid of it except for repayment.
                  rgds
                  WP

4. Great job Ovi,

   I would note that the claims that breakeven prices in the Permian are around $40/b are very different from my own estimates for average Permian wells. If we assume the average Permian well has full capital cost of $12 million (includes plugging at end of life, overhead, and land cost), at a nominal discount rate of 12.5% per year the discounted net revenue over the life of the well is about 10 million at $60/b at wellhead , NGL at 35% of crude price at wellhead and NG at $3.20/MCF at wellhead (this is a very optimistic price for Permian where WAHA spot prices have been under $2/MCF).

   In short breakeven prices are not $40/bo, that might be LOE for a flowing well, but nobody makes money in the Permian at that price for their entire portfolio of wells. There might be 5% of all Permian wells drilled to date that might have been profitable at $40/b and $3/MCF, maybe only 1%.

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   1. Hmmmm,

      “If we assume the average Permian well has full capital cost of $12 million”

      Yesterday I posted this link from Reuters-

      “Exxon is the largest producer in the Permian basin, the top U.S. oilfield, and operates the lucrative Stabroek block off the coast of Guyana. Cost of supply in the Permian is less than $35 per barrel, the company has previously said, allowing it to make money even at lower oil prices.”

      Not sure both of you are talking about the same costs. But, one thing for sure Dennis is that you don’t know what Exxon’s costs are. If you are using numbers on the cost of pipe for example from guys like Shellman or Shallow Sand. I can tell you for sure that’s not the cost Exxon is paying for it. That would be like comparing GM’s productions cost to build a car to yourself in your garage or your local convenience store costs to Costco.

      I wouldn’t be suprised if Exxon’s average capital costs to complete and cap a well in the Permian is less than $8 million.

      Reply

      1. Huntingtonbeach,

         You can look at 10Q to get an idea of capital cost for a well. You may believe XOM’s costs are lower, but I would say there is a lot of hype in investor presentations, including those by XOM. You are correct that I don’t know what XOM’s costs are, but only a fool would believe the numbers that are in an investor presentation, read the fine print which says in a nutshell, don’t believe these numbers.

         Also my analysis is based on the basinwide average, it is possible that XOM only drills above average wells, and has costs that are 66% of the average producer. If you believe that, I have a bridge in Brooklyn I can sell you.

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         1. ExxonMobil And Nabors Test Fully Automated Drilling Rig In Permian

            As the U.S. rig count continues a slow rise in a somewhat muted response to higher prices for crude oil and natural gas, two giants of the industry announced last week that they are partnering in an effort to make the drilling process safer and more efficient through automation. In an industry first for a land drilling rig, ExxonMobilXOM subsidiary XTO Energy and Nabors Drilling have reached total depth on the first of a planned three horizontal wells in the Permian Basin using an innovative Nabors drilling rig with a fully-automated, unmanned rig floor.

            Anyone who has ever worked in the oil patch proper knows that the floor of an active drilling rig has long been one of the most dangerous places in the business. Whether drilling downhole, changing out drill bits or pulling strings of drill pipe out of the hole, the labor intensive activities necessary to drill these deep holes into the earth have always accounted for a significant percentage of reportable, lost-time accidents that companies incur every year.

            In its Oct. 7 press release, Nabors announced that the technology now exists to drill these horizontal wells in the Permian Basin – and presumably any other oil and gas producing region – with no employees having to be present on the rig floor, where the action takes place.

            https://www.forbes.com/sites/davidblackmon/2021/10/11/exxonmobil-and-nabors-test-fully-automated-drilling-rig-in-permian/

            Nabors Announces World’s First Fully Automated Land Rig Has Successfully Drilled Its First Well

            The PACE®-R801 concept rig has safety and efficiency at the core of its design, purpose-built to showcase Nabors technology and to push the boundaries of industry performance and possibilities

            Nabors Industries Ltd. (NYSE: NBR), a leading provider of advanced technology for the global energy industry, today announced its PACE®-R801 – the world’s first fully automated land drilling rig – has reached total depth on its first well, a horizontal well for ExxonMobil in the Permian Basin.

            Combining Nabors proprietary Smart Suite of automated drilling software with Canrig® robotics on the PACE®-R801 creates an unmanned rig floor that removes crews from red zone areas and delivers consistent, predictable drilling performance.

            https://www.nabors.com/nabors-announces-worlds-first-fully-automated-lan/

            Oil Drilling Automation: Revolutionizing the Industry for Efficiency and Safety
            Overview
            Oil Drilling Automation: Revolutionizing the Industry for Efficiency and Safety
            Drilling automation has become increasingly relevant in the oil industry. The integration of advanced technologies and computer-controlled systems has led to more efficient, safer, and cost-effective drilling operations. With the rise of automation, companies are able to maximize performance while minimizing human exposure and environmental impact.

            The adoption of automation technologies in drilling operations includes the use of machine learning, robotic systems, and real-time data analysis. These technologies enable the drilling process to be optimized, improving the overall productivity of oil extraction. The growth and improvements in drilling automation also have the potential to enhance worker safety by reducing the need for manual labour in hazardous environments.

            As the industry looks to the future, continuous research and development will be crucial in pushing the boundaries of drilling automation technologies.

            Key Takeaways

            Automation leads to more efficient and safer oil drilling operations
            Advanced technologies such as machine learning and robotics play a key role in drilling automation
            Addressing challenges and staying ahead through research and development are crucial for the future growth of the industry
            Overview of Oil Drilling Automation

            Evolution of Drilling Automation

            In the past, drilling operations were manually intensive, requiring significant human intervention and expertise. With time, the oil and gas industry has witnessed a shift towards the adoption of automated solutions to enhance safety, efficiency, and data-driven decision-making. The development of drilling automation technologies has been driven by advancements in AI, control systems, and digital transformation, enabling companies to optimize drilling processes and reduce human error.

            Key Benefits of Automation in Drilling Operations

            Performance improvement: Drilling automation can maximize drilling operations and improve overall consistency. Automation technologies help ensure consistency in performance, regardless of operator skill level or environmental challenges.
            Enhanced safety: The integration of autonomous systems reduces the need for manual operations in high-risk environments, minimizing the potential for accidents and injuries. Advanced visualization and monitoring tools enable real-time supervision, fostering a safer workplace for drilling personnel.
            Data-driven decision-making: Modern drilling automation solutions are equipped with sensors and data collectors, enabling efficient data processing and analytics. These data insights, combined with AI-powered algorithms, allow drilling operators to make informed adjustments and optimize drilling performance.
            Cost-effectiveness: Automation systems reduce manual processes that have a high level of variability so that crews can more effectively run the drilling operation. Moreover, optimized drilling practices can reduce wear and tear on equipment, contributing to lower maintenance expenses.
            Environmental impact: Drilling automation promotes sustainable practices by limiting resource consumption, reducing waste, and enhancing overall efficiency. Improved precision and consistency can lead to a reduction in days on location.

            https://www.helmerichpayne.com/resources/product-highlights/oil-drilling-automation-revolutionizing-the-industry-for-efficiency-and-safety

            Like you said Dennis, you don’t know the cost.

            Reply

            1. Huntingtonbeach,

               For people in the industry, they are very dubious of the XOM claims, but you are right I don’t know, I rely on others in the business that know far more than me.

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               1. Whenever this wank from California uses my name in his comments I feel the incessant need to go outside and rinse off with a garden hose.

                  Last I looked there was only one Nabors R801 IN the entire Permian and I have no idea if its working anymore; its day rate was 2 times a normal 2000 HP, semi-automated rig working in the Permian. Rig automation is not helping Exxon one ioda.

                  Exxon is a poor tight oil operator. It uses its “power” to bully service providers into lowering costs, which in turn hurts other smaller operators in the play and RAISES costs for everyone else. That hurts America.

                  Exxon has $40B of long term debt and pays almost a $B a year in interest. Its 1Q25 profits are lower and going way lower 2Q25 when <$60 oil kicks in. Trump was in office only 2/3rds of the entire quarter and the price of oil did not get near $60 until THE BEGINNING OF THE 2ND QUARTER! Everybody waiting for rigs to fall after 30 days of $60 oil is nuts!

                  Its amazing a far left, progressive socialist like this guy from Californy is defending Exxon earnings; that must be about…let me guess…personal dividends. I thought you folks were anti-oil?

                  Nony, I got the reference. I am flattered. I am too smart to have operated tight oil wells, but too dumb to never have had working interest in them. It was the only time in 65 years I ever lost money in an oil play. Have you ever even seen one?

                  Your hero, Permian Resources, drills horrible wells. 55% gas in their Delaware production stream? In 2024 it GROSSED 80 cents an MCF for its gas, AFTER hedge protection.

                  It has 4.2 billion dollars in long term debt and only 312,641 MM BO of PDP reserves GROSS of royalty (SEC 10K). Net of royalty it therefore has to have an additional $18 per BO breakeven price, just to pay off its long term debt. Then there is retirement costs, or don't you have the ability to understand that.. oil extracted from a well is burdened by all the costs and liability of the company that extracts that oil?

                  You don't seem to understand well economics at all. That the U.S shale sector keeps drilling wells that don't make sense to us "peak oilers" is the exact same reason it has lost $400B already in the 14 years of its existence, with another $200B yet to be paid off. Plus the cost of plugging its wells and cleaning up its mess. Everything the shale sector does going forward is based on…more indebtedness.

                  I don't like this place anymore. If y'all are going to continue to rag on me, get your shit straight, at least.

                  I am trying to help my country understand the oil and gas business better, to be better prepared for the future, in the face of qazillions of people who will lie to, to your face, for the sake of a lousy dollar. Or because they falsely believe they have the intellectual, and moral, highground over you, They don't.

               2. I like you, actually. The Red Adair history is fascinating.

               3. Thanks Mike,

                  I realize now where you get the 12 to 13 million cost for the average Permian well from reading your blog, I appreciate the lesson. It is land cost and plugging cost (mostly land cost) that adds another 2.5 million to D and C cost, other overhead (tank farms, gathering lines and electric power lines, and 1000 things I don’t know about) might add another 0.25 million per well on average.

               4. To add to Mike’s comment – XOM in 2024 spent 19.3bn of stock, paid 16.7bn in dividends for a total of 36bn – just in 2024. Pretty close to the 40bn in debt. It’s a game of pushing up the stockprice by reducing the float and increasing the dividend.
                  rgds
                  WP

         2. The above is so true. I have drilled many many many wells in the Permian and I will not drill there again at these prices. Investors are just trading dollars. I can tell you it is an uneconomic venture. The Majors do get services cheaper as they can prepay for services which vendors love. I have drilled with the Majors and their well costs are over $11 million dollars per well.

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            1. Thanks LTO Survivor. Am I correct in assuming the $11 million is just D & C or is that full cycle costs, including land cost?

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      2. I haven’t been giving Dennis the cost of steel or anything else for a long time.

         I’ve maybe given him what our costs are in the past few years? I don’t really remember.

         I haven’t studied 10k and 10q for upstream companies for a long time either.

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      3. Huntingtonbeach,

         XOM capital and exploration expenditures for US upstream in 2024 were $11.252 B and about 546 net wells were completed in the US in 2024, so upstream capital spending was over $20 million per well, based on the 10k for 2024. In 2022 when there were fewer aquisitions, US capital spending per well was 13.32 million for XOM. This pretty close to the oilystuff.com estimate of 12 to 13 million per well for full cycle costs in the Permian.

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         1. Thanks Dennis, but I really don’t think 20 million is a good number from the 10K. To many other expenses could be in there distorting the well cost. I did ask the question to Google AI and got this:

            what is the break even point for the cost of oil in the permian basin

            The break-even point for oil production costs in the Permian Basin varies depending on several factors, including the specific sub-basin (Midland vs. Delaware), the type of well (existing vs. new), and the individual producer’s operational efficiency.
            Here’s a general overview:
            1. Existing Wells vs. New Wells:
            Existing Wells: The Permian Basin boasts some of the lowest break-even prices in the United States for existing wells, often below $50 per barrel.
            New Wells: Break-even costs for new wells are typically higher, reflecting the initial investment in drilling and completion.
            2. Midland vs. Delaware Basins:
            Midland Basin:
            Existing Wells: Reportedly around $38 per barrel.
            New Wells: Reportedly around $62 per barrel.
            Delaware Basin:
            Existing Wells: Reportedly around $31 per barrel.
            New Wells: Reportedly around $64 per barrel.
            3. Average Break-Even for New Wells:
            Average across Permian Basin: Data from a Dallas Fed Energy survey indicates an average break-even price of $65 per barrel for drilling new wells in the Permian Basin.
            Regional Average for New Wells: Another source suggests the average break-even price for drilling new wells in the Permian Basin is around $62 per barrel.
            Important Considerations:
            Fluctuating Costs: Break-even prices can change over time due to factors like technological advancements, operational efficiency improvements, and fluctuations in service costs.
            Company-Specific Costs: Individual companies may have different break-even points depending on their specific circumstances, drilling techniques, and asset quality.
            Full-Cycle Costs: Full-cycle costs, which include exploration, drilling, completion, and operating expenses, can be significantly higher than just operating expenses for existing wells.
            Oil Price Volatility: The break-even point is highly sensitive to changes in oil prices, and companies may adjust their production plans based on current market conditions.
            In conclusion, while the Permian Basin is known for its low break-even costs, especially for existing wells, it’s crucial to consider the specific factors influencing these costs when analyzing the profitability of oil production in the region.

            *****
            Existing wells must mean workovers. This is probably were the $35 number from Exxon is coming from. I noticed AI goes behind paywalls to get some of it’s information. Might be useful. Also, I thought it was interesting that Shellman responds to me and I think he is a policial ****** ****. But you, really go overboard trying to be nice and work with him. Yet he still calls you just as bad as thing as me and won’t respond to you. Maybe you’re using the wrong approach. Anyway, look out below because I used his name again. I really don’t care anymore, my life is to short for that. That’s the next generation problem. I live in Trumpland and see it everyday I visit the club. The business guys are starting to figure it out and are getting pissed at Trump. On the other hand, the religious idiots I don’t think will ever come around. Last week a guy wore a t-shirt that said – “Transsexual are just retarded gays”. One more thing, I guess we have a local election coming up here soon. When you drive around town there are signs that say – “Protect our children from pron Vote No on A & B”. I guess now the parents are having to explain what porn is to their young kids and not happy about it. Can you imagine. Their trying ban books for children like “Everybody poops” because it’s pornographic. God help us, we’re going to need it. LOL

            A general ballpark number for breakeven is all that is really important anyway.

            Reply

   2. Dennis

      Thanks.

      I was surprised to read those low cost Permian production numbers. Two things to note.

      The New Mexico rig count has been very steady at slightly over 90 rigs/wk since October. Also Midland and Martin seem to be settling in close to 25 rigs/wk each since October. If this continues then that lower breakeven price may have some credibility.

      On the other hand if your numbers are closer to the truth, then the companies face the question of not drilling and having their quarterly report show a production drop, which share holders won’t like. On the other hand they could drill and report a smaller profit/loss but show steady production.

      I was wondering if you could run your Permian model and then suddenly in early 2025 drop the number of monthly completions by 10% for say 6 months and then back up to the original number, I am assuming prices rebound back to $70 six months later. I ask this because I am wondering whether the production drop that occurs with the drop in completions ever gets recovered in three or 4 years.

      Attached is an article which shows the cost pressures Chevron is facing.

      “The Permian Basin, a key area for Chevron, will see a reduced budget of $4.5bn–5bn as the company shifts its focus from production growth to enhancing free cash flow.”

      This statement lends more credence to your breakeven oil price and possibly slower growth in US production. We will have to keep watching the weekly rig count and Frac spread for the next few months to get a better idea of how the oil price affects rigs and fracs,

      https://finance.yahoo.com/news/chevron-plans-reduce-2025-capex-102326434.html

      Reply

      1. Ovi,

         This is the scenario you requested. I simply modified my scenario in the way you requested.

         

         Reply

         1. Dennis

            Thanks

            What was the completion rate pre-drop?

            There is a production drop but not as big as I expected and it recovers much more quickly than I expected.

            Reply

            1. In Dec 2024 it was 487 completions, it falls to 438 completions from Jan to June 2025, then increases to 482 in July 2025 (as that was my initial scenario rate).

               Reply

      2. Here is anothet article that mention 60 usd/bbl WTI. Think the tarrifs will inctease cost level for imported equipment and spare parts.
         https://finance.yahoo.com/news/cheap-crude-tests-u-shale-220000404.html
         Actual I had exspected about 75 – 80 usd/bbl. Think there have been a positive impact on cost by use of simultaneously
         fracking. I read that they frack 3 wells simultaneously fracking. This might also they do with drilling horizontal wells. Higher utilization of equipment and pepole, reduced transport cost reduce cost each foot well. But I believe productivity improvement goes slower now.

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         1. Freddy,

            Productivity is decreasing when normalized for lateral length, this has been the case since 2016 in the Permian Basin. I am convinced that $60/b or lower will be a problem for tight oil producers in the US.

            Reply

            1. There is also several other issues that is a growing challange in shale buisiness. The higher utilization of a field means more chield well interference. Beside that it seems more wells became gasier. There is also a growing water production. Thoose 3 elements together with the fact that geology are getting more challenging as the best area is already drilled Tier 1 Area. Think now they operate Tiere 2 and 3 area. If it had not been for improved drilling, fracking processes break even price would have been much higher. But this tecnology requires huge capital and Area and the smaller Company have significant higher break even price than Exoon.

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         2. some of the lowered EUR/ft numbers are delayed because the decline tail is 3 years behind, the IP/ft might be just as good or looks slightly higher with longer laterals and more proppant/liquid loading.
            The EUR estimates or EIA/USGS reserve estimates all might be over estimating for shale oil by 30~>50% based on higher IP and a slower decline curve; while underestimate shale gas, especially in Marcellus, where the decline tail also scales up with longer lateral, higher IP.

            Reply

      3. Ovi,

         Slight variation with DPR completion rates for Jan 2024 to Feb 2025 used, then 10% drop (from 443 to 399) from March to August 2025, then back to 443 wells in Sept 2025, I assume an annual rate of decrease in new well productivity (EUR) of 2% starting in Jan 2025 for this scenario. I also assume the completion rate is 443 wells per month from Sept 2025 to Dec 2028 and then completion rate decreases falling to zero by August 2035.

         

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5. On the rigs in Louisiana, my guess is that most of the oil is condensate from gas wells. Chart with C+C and wet natural gas for Louisiana from 1997 to 2025 below.

   

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6. Lousiana Horizontal Oil and Gas Rigs, HOR=horizontal oil rigs, HGR=horizontal gas rigs

   

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   1. Dennis

      Thanks. Looks like Louisiana is mostly condensate.

      Reply

7. Ovi:

   TLDR: Most OH reported oil would be considered “lease condensate”. Most LA reported oil would not.

   EIA used to report crude gravity by state, at every ten API points (LT30, 30-40, 40-50, GT50). I could not find data more recent than FEB2024, but as of that time, ~80% of OH crude was higher than 50 API gravity, a threshold that almost anyone would consider marketing as “condensate”. In contrast, only about 20% of LA oil was above 50 API gravity.

   Basically, I think the story of LA oil is that it is mostly legacy (declining) conventional crude from onshore and state GOM waters. It’s not like nobody will ever drill another oil well in LA, but mostly what is going on now is drilling of the Haynesville (which is very dry gas, with almost zero condensate, often not even processed for NGLs…but placed directly into dry gas long haul pipes!). So, overall the state is more of a mix of active drilling for dry gas (almost zero associated crude/condensate) and just declining conventional crude oil (with negligible drilling) and occasional up/down from weather, especially hurricanes.

   Ohio is a different story. Almost all the drilling is going after the Utica or Marcellus and, in OH, these wells produce significant amounts of BOTH gas and associated lease condensate. They are truly “in betweener” wells. In contrast, LA where it is more a story of different populations.

   But even in OH, it’s not as simple as “gas was growing and oil (lease condensate) grew with it”. This is because if you look at the changes over time, oil has been growing FASTER than gas in OH.

   In general, you can expect gas to oil ratios to grow over time, because oil decline curves are steeper than gas decline curves. So, for a prospect like ND, where they drill enough to essentially keep crude production flat, they see gas grow. But in OH, it has been the opposite, gas production has been essentially flat, while oil quixotically grew!

   Consider that in SEP2021, OH oil production was only 48,000 bopd. And it has almost tripled since then. Meanwhile, over the same time frame, gas production slightly declined (from 6.1 to 5.5 BCF/d). So…yes, there really is sort of a little “oil play” within OH. I wouldn’t overdramatize it. It’s not NM. But it is not just EOG spin machine either. It’s happening.

   As for the BH data on “oil directed” or “gas directed” rig count, I would maybe not read too much into it. First of all, BH data is not perfect (not to slam it, very happy we have something). Second for OH, I suspect these wells need both oil and gas revenue to be NPV+. So, it’s really kind of arbitrary what you call the rig–it is actually drilling for both. I suspect there’s more than one rig in the “oil play” of OH. I think EOG has one and so does Encino. They just don’t care what they call the “directed” field on the BH data.

   Reply

   1. Nony

      TLDR: I try to let the charts tell the story.

      Thanks for the detailed info on OH and LA.

      As for BH data, maybe the numbers themselves are not as important as the trend. While the numbers are dropping, there is no info on how to compare today’s rigs with those in January 2023. Do the new rigs have double or triple the power of the January 2023 rigs. If so, not as many are required to drill the same number of wells. Difficult to interpret those number without more info.

      Bottom line. we really need to know how many wells are being drilled every month. Novi Labs used to provide that info but it is not available for free now. In 2023, the last year of significant rising US production, Novi Labs was reporting an average of 460 new wells per month. Production and Rig counts have been flat since the end of 2024 to today. What has changed?

      Reply

      1. Agreed. And cool, man. Yes, per rig productivity has gone up. Even leaving out lateral length increase (which helps by spreading setup and vertical), you just have an aspect of speed. They have gotten faster over the years, even within the lateral.

         There is also an issue of high/low grading. This happens not only with the land, but with the crews and equipment. So, the best crews/rigs tend to be concentrated more during a bust. (Conversely of course, when we have a boom, then more marginal equipment and greenhorn drilling crews are mobilized.)

         Also, of course there can be an effect of cost deflation. If very few rigs are drilling, the rig rates tend to be low. (During a bust.) During a boom, they rise rapidly. Can be a 2x difference across the cycle. (And yes, there are many inflationary aspects also: tarrifs, inflation itself, etc. But during a bust, you will see capital costs to drill a well go down…this happens every cycle.)

         One small note: if you want to look at number of wells, than the relevant metric is per well production, not normalized by length. If you decide to look at normalized (by foot) productivity, than you also have to know how many feet were drilled, not how many wells!

         Reply

      2. Oh…and if you just want a “chart story” for LA and OH crude density comparison, here is the relevant data:

         https://www.eia.gov/dnav/pet/PET_CRD_API_ADC_MBBLPD_M.htm

         I would do a double column 100% comparison, for FEB2024. Not a time series.

         https://d2mvzyuse3lwjc.cloudfront.net/doc/en/UserGuide/images/100_Stack_Column_Graph/100_Stack_Column.png?v=38773

         Reply

   2. here is a chart from EIA (https://www.eia.gov/petroleum/production/#ng-tab) of gross gas from WV, PA and OH, and I combine the WV PA together to show a 4th plot.
      Details: most gas from WV and PA are from Marcellus, and Utica only has about ~0.8 and ~0.5 BCFPD for PA and WV respectively. Therefore, one could see the total Marcellus gas is still increasing and clearly not peaking yet, e.g. from ~24BCFPD Feb2020 to ~29BCFPD in Feb 2025; while the PA Marcellus has been flat since Feb2020 mainly due to wellhead prices way lower than HH. And total production to date for Marcellus only is already ~100TCF since 2010.
      OH gas is mainly from Utica, and because lower GOR ratio and drilling targeting only condensate to oil, the gas production has been falling.

      

      Reply

      1. Marketed natural gas production from PA, WV, and Ohio. The OLS trend from March 2022 to Feb 2025 (36 months) is an annual increase of about 0.51 BCF/d. Unless pipelines are built to NE or to Gulf Coast or a new LNG facility is built in Maryland we are not likely to see a big increase in Appalachian Natural Gas output (includes both Marcellus and Utica Formations).

         

         Reply

         1. Dennis,
            Nony’s comment down below about ‘trying to at least know what you don’t know’ may be particularly apt when it comes to the Gas World … specifically App Basin future production.
            As you have focused primarily on oil these past many years, it is understandable that you have limited familiarity with all things gas.
            The possibility of more pipe to serve NYS and New England is growing stronger, but it is the data center build out that will greatly boost App Basin natgas output.
            The Homer City operation alone will consume close to a Billion cubic feet (~800) when it is fully online in a few years’ time.
            The current backlog from Siemens, Mitsubishi and GE Venova for large natgas turbines is approaching 5 years, despite a ramping up of production capacity.
            It would not be surprising to see App Basin increase output of natty by 5 to 10 Bcfd in a decade’s time if current plans come to fruition.

            Reply

            1. Coffeeguyzz,

               Perhaps output will increase, depends on prices and demand. The future is difficult to predict.

               Reply

8. I would caution talking about normalized per foot production in the context of well go nogo investment decisions. When you are deciding to drill or not, you look at the capital cost versus the production. At the well level.

   Yes…for a peak oiler, it may be interesting that rock productivity is down. But for an investment decision, it is not the relevant metric. Even if you just think of it as a capital efficiency increase, longer wells can help. Essentially more feet for the same 12 million or whatever initial capex.

   The benefit of a longer well is the vertical and the move setup cost being spread over a longer lateral.

   Of course there are tradeoffs. We have very few 4 mile wells for instance. But we have very few 1 milers any more either. It’s been a gradual evolution of capability to allow economic drilling at longer lengths. Steering. Lease boundary trading. Etc.

   Reply

   1. Nony,

      I only look at productivity per foot to get an idea of utilizing the productive area of each formation, so for example if an operator claims they have 30000 locations left to drill, it makes a difference if they are talking about 10k wells or 15k wells. For my models I just use well productivity that is not normalized for lateral length, future productivity is a guess, but I simply assume lateral lengths will remain what they were for the most recent well that I have the data to do a decent well profile estimate (currently for 2022 wells) and assume productivity may decline at a rate similar to the rate we have seen normalized productivity decline in the Permian since 2016 (about 2% per year). The guess is likely to be incorrect, but I don’t have any new data at the average well level.

      Reply

9. I think with capital budgeting, it’s important to know that you don’t know. I don’t place too much stock in either a flashy press release or the industry veterans that habituate this blog comment section (very few in number and not shale operators).

   I looked for a public pure play Permian operator to estimate average capital costs and got this:

   https://permianres.com/operations/

   They are Delaware focused, so probably a bit deeper (more expensive) than a Midland subbasin operator.

   If you look at their 2025 capital budget it is $2B (1.9-2.1B), to drill 214 net wells (285 gross, 75% WI). So that implies 9.4 MM/well. Their expected average lateral length is 10,000 feet (i.e. “two miles”).

   They actually say that only 80% of the $2B is for well-level D&C, the other 20% is for central facilities and workovers, but I’ve been conservative and just allocated 100% of the total capex to the overall (net) well count.

   See: https://permianres.com/permian-resources-announces-strong-fourth-quarter-2024-results-and-provides-full-year-2025-plan-with-increased-capital-efficiency/

   Of course, you could look at more companies or even interview someone from Halliburton or the like.

   But…if you see a bunch of wells getting drilled that don’t make sense to you, but the industry continues to do so…I would at least consider that your model (or the assumptions within it) are at issue. Not that all these operators are just trying to make peak oil blogs look bad by wasting their money.

   Reply

   1. Nony,

      Thanks.

      Based on 10k for 2024 for Permian Resources the average capital cost per well was about 10 million. If we assume this is average cost for all producers in the Permian Basin, and use their average sales price in 2024 for crude, NGL and NG then the well pays out in 37 months and would be profitable. If we assume prices drop to current level for Oil and NG and NGL sells at about 30% of crude, then the average well pays out at about 90 months. Also keep in mind that with tariffs, pipe will become more expensive which will tend to increase costs. This might be offset with lower costs for rigs and frac spreads due to lower levels of activity.

      Reply

      1. See comment further downthread where I still think 12 to 13 million is a better number when land cost is included.

         Reply

10. WTI currently at $56.16. Do we see $50 or sub $50 by the end of the week or next week? Not looking good.

    There some pretty strong support on the chart at about $38. But I feel if we reach that support it means things are bad. Really bad. Maybe $25 oil is in the cards. Maybe not. We shall see.

    Reply

11. HHH

    Do you think this price drop is part of an effort to convince Putin to settle the Ukraine war by starving him of income?

    Reply

    1. No I don’t think we are intentionally setting out to send the global economy into a recession just to bring Putin to his knees.

       Economic weakness was clearly visible before tariffs were put into place. Globally central banks were already well into the cutting rates cycle before the tariffs. Not that interest rate cuts matter but they are an acknowledgment by the central banks that they see the weakness in the economy.

       The tariffs obviously piled onto the weakness that was already there.

       Oil prices are kinda like interest rates in China. Their interest rates don’t lie. Their GDP isn’t even half of the official number they report. Oil prices don’t lie. The economy isn’t doing well.

       I don’t believe it’s part of some grand strategy to bring Putin’s war to an end.

       Oil at $25 would be a perfect time to go bomb Iran though if you want to think semi conspiratorial.

       Reply

12. Do the majors and large independents have high overhead? Do they figure in G&A in “breakeven?”

    One of the reasons tiny companies like ours end up with production that used to be operated by majors and larger independents is that we can do it cheaper.

    So, although LOE goes up as production per well drops, our G&A can be cut to the extreme. We don’t pay ourselves, we don’t make distributions (pay dividends).

    I continue to be amazed by US shale. Nothing like it has happened in previous history. 5 million BOPD to over 13 million BOPD.

    Will be interesting to see how US production ends up this year assuming WTI is going to stay low.

    You guys might want to look at the shale play stock prices. I still own COP and XOM. Neither are pure shale play. COP is down 25% in the past year. XOM is down 9% during the same time frame.

    Some companies that I think are strictly shale upstream in the past year:
    FANG down 31%
    EOG down 16%
    CHRD down 47%
    SM down 52%
    CIVI down 59%
    NOG down 36%
    HES down 17%
    CTRA down 6%
    DVN down 38%

    The one I found that is up is EXE, formerly Chesapeake. Up 22% in the past year.

    Im sure there are others that maybe I should look at.

    Based merely on the various stock performance, I’d say that falling from $70’s WTI to $50’s WTI matters a decent amount.

    Reply

    1. It matters a lot to stock speculators. If you are in the midstream (pipelines), you take a more phlegmatic approach. These things (prices, recessions, wars) come and go. But the production will flatline for a while before it crashes.

       Look how long old man Bakken has hung in there. Remember Art Berman predicting inexorable decline?

       https://www.forbes.com/sites/arthurberman/2017/03/01/the-beginning-of-the-end-for-the-bakken-shale-play/

       It always surprising the shale h8ers how (even despite the massive decline rates), basin production manages to hang in there during price declines. There’s a lot of inertia in the system in terms of sunk costs (DUCs, lease bonuses, seismic shoots, pipeline contracts, drilling contracts). So even if production turns, it never seems to crash as hard as the Art Berman types expect. I remember Rockman talking about this over ten years ago.

       The other thing of course is high grading. The marginal wells don’t get drilled…of course. But the remaining ones are the better ones. We see this all the time, with rig productivity (even factoring out DUC effect) turning up during price declines. They just drill the best of the best.

       And then, there’s also an effect of day rates and pipe prices going down when there is less activity (and the converse of course during booms). Along with just general belt tightening (less G&A, R&D, exploration, consultants, Ruth’s Chris dinners, etc.).

       —

       But all that said, my gut says 60+ is coming. Total wild hunch, but I think as we head into summer some of the doomer feelings about Orange Man tariffs will die down and demand will pick up. And I totally get why markets freaked out. But I just think we will settle down. See a lot of my friends planning trips to Europe, buying boats, etc. Summer will get everyone in a better mood and the pump will get primed.

       Reply

       1. Nony,

          Yes Bakken has hung in there with roughly a plateau since pandemic crash with average completion rate over past 4 years at 75 wells per month, as far as high grading this has not helped a lot since the fall of 2023 with average annual decline rate of about 5% from Sept 2023 to Feb 2025 and 7.7% per year from Sept 2023 to Sept 2024. From Feb 2024 to Feb 2025 the annual decline rate was 4.8%. Eventually the sweet spots will run out of room for new wells and the average well productivity will decrease in the Bakken/Three Forks.

          Based on Novilabs data (last available is from March 2024), 2020 may have been the high point for average well productivity in the Bakken/Three Forks.

          https://novilabs.com/blog/north-dakota-update-through-jan-2024/

          

          Reply

       2. Nony,

          Rich folks won’t be affected by the Trump tax, it will be working class folks that probably aren’t buying new boats or making trips to Europe that will be hit by higher prices and the layoffs that will ensue when small businesses go bankrupt and big box stores cut back staff because there are fewer products to put on the shelves.

          You are deluding yourself if you believe everything will be fine.

          Reply

13. In my simple mind, USA is the only country that produces a lot of oil that wants low oil prices.

    OPEC doesn’t want low oil prices. Nor does Canada. Maybe Brazil and China are similar to USA in this regard?

    It looks like maybe in the 13 million BOPD is the high end for USA, and will probably hang in there for a while.

    Last time oil peaked in USA was 1970-71. Oil prices were low. Then they quadrupled in 1973? Think we see that replay, or something different?

    Oil production in the USA didn’t really fall off a cliff after the first peak. It stayed in the 8-9 million BOPD range for over a decade until after the 1986 price collapse.

    But, oil went from $2.90 in 1972 to $11.50 in early 1974, up to $38 in 1979, and was still in the $20’s until the 1986 collapse. Oil then stayed relatively low until 2003. It then ran up from the $20’s in 2003 to $147, then crashed, then high until 2014.

    I’m 55 and God willing hope to live to see 2-3 more decades of what happens to the oil price. I have a feeling during that time there will be at least one more rocket higher. But just guessing, of course.

    I do think another US peak will be a big deal, assuming it happens.

    Reply

    1. Shallow Sand,

       If prices remain low the peak for US may be behind us. If oil prices rise to $90/bo or more and NG returns to $4/MCF or more we might see a new peak. For current Permian average well, if we assume a full capital cost of $10 million per well and crude at $90/b at refinery gate ($85/b at wellhead), NG at $4/MCF and NGL at 30% of crude price the average well pays out at 16 months so we might see the completion rate increase if oil and natural gas prices rise in the future.

       Reply

    2. Permian scenario assuming higher oil prices (over $85/bo and natural gas over $3/MCF). Note the slow increase in Permian output may not be enough to offset declining output elsewhere in the US, the current STEO predicts a centered 12 month peak in December 2025 at 13630 kb/d, the current centered 12 month output is the high point so far at 13261 kb/d in August 2024 for US C plus C output. In my view the STEO forecast is likely to be optimistic, note that it was 390 kb/d too high for February 2025.
       I expect we might see revisions in the future STEO forecast, but also wonder if political pressure will make it even less believable.

       

       Reply

       1. Would not surprise me if EIA stops releasing production data this year.

          Reply

          1. Shallow sand,

             I hope you are wrong, but if the data is cooked that might be better than false data, my worry is that data will be published, but it will no longer be relatively unbiased.

             Reply

             1. SS/DC

                Remember that we will have access to production data from the three largest states. So we will here checking up on them.

                Reply

                1. Ovi,

                   Yes we have state data and we can also use the 914 estimates reported to the EIA for Texas and create our own estimates from those, if the data continues to be collected and reported, we could also try to sort out the pending lease file from the RRC which would improve the RRC estimates.

                   https://rrc.texas.gov/resource-center/research/data-sets-available-for-download/

    3. SS

       I still think that we will have an answer for you within six month. We will have a pretty good idea if the US is on a plateau.

       Reply

14. This is old news now, it is the reason oil prices have dropped below $60/b.

    https://oilprice.com/Latest-Energy-News/World-News/OPEC-Plans-Faster-Rollback-of-Output-Cuts.html

    Excerpt:

    The report, which comes on the heels of OPEC ’s latest meeting, this Saturday, at which the group agreed to add another 411,000 bpd to combined production in June, after a hike of the same size for May. Reuters calculations put the total amount of supply to be brought back over the second quarter at 960,000 barrels daily, or 44% of the 2.2 million bpd cut.

    It will be interesting to see if the May STEO (released tomorrow) drops their oil price forecast.

    Reply

    1. Dennis

       The June announcement is the second increase. The May increase was announced about six weeks ago. So we have to see if there is a change to their crude oil forecast and possibly the US’.

       Reply

       1. Ovi,

          Yes the May increase was probably accounted for in the April STEO, the June increase may affect the May STEO, if they have time to account for it (the report was finalized on Sunday and this OPEC increase was announced on Saturday, I don’t know if they can react this quickly as they have seen staff cuts.)

          Reply

    2. If Trump could choke off oil from Iran, Venezuela and Russia well, it could easily remove 2~5 million BOPD.

       Reply

       1. Sheng Wu,

          The US has been trying to do that for many years starting in 2017 for Iran and Venezuela and since 2023 for Russia. China is not worried about US sanctions and will import all that they can ship to China’s ports. Also Trump is looking for low oil prices to offset higher prices due to sanctions so I doubt he does more than pay lip service to enforcing sanctions on oil.

          Reply

          1. D C,
             Sure, Trump does not want oil price too low either.
             Turmp 1st term was able to beat down Iranian and Venezuela oil pretty low at ~0.4 and ~0.3MBOPD, and only to see them bouncing back in the past 4 years to 1.3 and 1MBOPD.
             It appears that the Mid-con states gasoline price has been on the rise, I see ~25cents/gallon higher, while oil price has been down.

             Reply

             1. Sheng Wu,

                Iran and Venezuela now have improved their ability to avoid sanctions and China is now more confident that they can do without Trump’s approval and will buy all the Iranian, Venezuelan, and Russian oil that will make it to their ports. Trump thinks the oil price should be $30/b, he is not an oil man and does not understand economics it seems.

                Reply

15. On the $12 million cost estimate per well for Permian Basin, an expert explains this at link below

    https://www.oilystuff.com/forumstuff/forum-stuff/its-gonna-get-ugly

    In case this disappears (as sometimes happens when I reference this blog) some is copy and pasted below, but if it is still there read the link for the full story. All of the comments by MS are enlightening, well worth reading and learning from in my opinion.

    By stuff people send me, including final well costs (different than AFE’s) I consider these costs in the chart above roughly 10% lower than reality. And this was before tariffs and trade wars increased the cost of tubulars, which I don’t have a handle on yet. So I suggest a typical Midland Basin well to cost $10MM with three strings of casing, 12,000 feet of lateral, and no problems, which is rare.

    I choose to ignore “tie in” costs mentioned in this chart as most wells drilled in the Midland Basin are infill stuff on existing units with massive tank batteries and treatment facilities already in place and requiring only several hundred K to lay flowline, electricity or gas make up for gas lift, etc.

    What I choose NOT to ignore is “land costs.” Lots of internet experts consider leasehold, or land costs, sunk. So they are conveniently ignored in the economic analysis. I guess, however, that 65%-75% of wells being drilled in the Midland Basin now are on acquired acreage in an M&A, like Exxon and Diamondback, for instance and on a per location basis those M&A’s have run leasehold costs back up to $4 MM each per drilling location (Enverus). Each M&A contains compensation for existing production, deeply discounted; most of the value is in drillable locations, something the Permian Basin is running out of. Assuming each acquired drilling location has two benches that can be accessed from the same acre of land, total full cycle well costs in the Midland Basin are pushing $12-$13 MM each. And likely to go higher with steel costs.

    I agree 100% with all of this and would suggest $12.5 million is a good number to use for full cycle well cost for the average Permian Basin well, land cost needs to be included as well as plugging cost. Note also that costs are likely to rise due to tariffs.

    Reply

16. Lease acquisition costs are sunk, unless you are getting new leases. It’s irrelevant if you acquired a company in M&A or paid the leasehold bonus yourself. And irrelevant if it was a year ago or 50 years ago. It’s a sunk cost.

    The decision now is if you drill or don’t drill. That is based on the new investment you make to drill versus the new revenues you get from production.

    Land cost, for the vast majority of the PB is sunk, sunk, sunkitty sunk-sunk. Certainly on locations that companies call “our locations”, it is already sunk.

    ————

    https://en.wikipedia.org/wiki/Sunk_cost

    “In economics and business decision-making, a sunk cost (also known as retrospective cost) is a cost that has already been incurred and cannot be recovered.”

    If Exxon chooses NOT to drill their acreage, the guy they bought it from in M&A won’t refund their money. It is SUNK.

    P.s. Duh.

    Reply

    1. This is the single stupidest thing I have ever heard in 65 years of being in business for myself, much less the oil and natural gas business, Nony. Good grief. I can’t believe anybody actually believes a word you say.

       It would be helpful, of course, if we knew your name, what you did for a living, if you actually work, what your work experience was, what exactly makes you such an expert on shale oil and shale gas, but that is entirely the point in the anonymity, isn’t it? That we don’t.

       I’ve always wondered if posting on social media annonymously makes one feel less embarrassed when one says things one knows nothing about? I suppose it depends on WHERE you say them, uh? I mean really, would you say this stuff on a chat room at the JPT?

       Alimbiquated, you love to criticize America, and American politics from where, Europe, whenever you can…what say ye? You folks in Europe have your energy shit together, don’t you? Yeah, man. You guys have flat been on the ball.

       “Every BO extracted for a shale oil company is burdended by corporate overhead, dividend costs and debt… old, middle aged or new born BO. Stop drilling new wells and the cost burden of legacy wells increases as they assume greater responsibility for costs and liabilities. Liabilities don’t just vanish. Hee hee. If you stop drilling new wells in the shale biz you are sliding into the abyss.

       The shale oil sector loses money drilling new wells below $70, IMO. It muddles thru that with cash flow. But when cash flow gets whacked 30% things get bad, fast. The company has to reconfigure itself, change its model, tell its investors no mas on dividends, try to amend loan covenants at the bank, change drilling committment clauses in OG&M leases, cut staff, cut overhead, cease the stupid buyback programs, drop rigs, break more TRRC rules, sell shit, defer plugging, stop R&D, suspend recyled water projects, flare more gas in lieu of expensive tie-ins, downspace and keep kicking the debt can down the road for another day.

       The financial health of the shale oil sector is NOT determined on the economics of individual wells. That seems to be part of what I don’t understand about today’s financial engineers and internet analysts.” I said that.

       Oil and gas extraction is a business, all encompassing. In the end, all of a companies liabilities, including long term debt, and P,A & D have to be paid (it is stupid to say those “future” costs should be discounted when those annual costs escalate more than the discount rate. Plugging costs are going out of sight. A few more 5.5 earthquakes, and more water bubbling up out of the ground, and retirement costs are going to eat the shale oil industry up. Or, more likely, you, the American taxpayer, will pay for it all. All you boys in Europe feeling entitled to cheap American oil, relax; you won’t have to pay a thing.

       But for the insults I would not want to help here anymore;. In this particular case I agree with Dennis. Its sorta just common sense. Sunk is debt. If I borrow $13.2 billion to buy another company, that does not just vanish because the portion of that purchase attributable to undrilled acreage is “sunk.” Yeow ! The coon outside eating my bird food right now is smarter than THAT !

       I looked at Conterra, Permian R. and Matador today; just south of $12B in long term debt. At $60 not one of those companies are above water on debt, even IF they were telling the truth about PDP reserves. Which they are not.

       Maybe its not a good idea to listen to me. Am I truly biased toward shale oil, or am I more often close to being right, than wrong, because I have owned WI in shale oil wells and been in the oil business for over a half century? I don’t care one way or another… but Nony? Gimme a break.

       Listen to what T. Stice said today and yesterday. He’s right. He’s hauling ass a from his company at exactly the right time. Its pretty much over, that from the horses mouth. He’s blaming Trump, tariffs and OPEC rather than his own poor reservoir mangement and 8% recovery rates of OOIP.

       Reply

       1. Mr Shellman,

          I think it is always wise to listen to an expert like you. Thanks for sharing your knowledge here.

          Reply

17. Including the terminal plugging cost is a good practice. Kudos. However, your model needs to discount that back. Let’s say it costs 0.25MM to plug the well. You don’t have to pay that now. You pay it 20 years from now. Or whatever your estimate is on well plug time. But you’re not plugging it the same year you complete it! Big picture, it’s good practice and the way to build your FP&A model. But not a huge lever.

    Reply

18. 12.5% is not a realistic hurdle rate. EOG is paying 5-6% for debt. Permian Resources is paying 7%. Of course, you can’t finance a portfolio of drilling entirely on debt. Equity (which is higher risk because debt is “senior” in BK), will command more return. But still…12.5% is not reasonable for a blended average, a “WACC”.

    I would probably just use 10% to keep it simple. (May even be under that…after all there is minimal exploration risk, it’s price risk. You’re just doing infilling. It’s a resource play!)

    Now…you will SEE a lot of 12% on company models. That (not 12.5%) is very much a sort of CFO “norm”. But it doesn’t reflect true economics. It’s an artificially high hurdle that companies like to use because they know people will lie (high) about expected future profit. But if you’re building an objective view of the economics, you should use a more classical CAPM WACC. This will help explain why “wells you don’t understand why they get drilled” do get drilled. Money is sloshing around for a home. USAA isn’t paying jack on saving/checking account interest. 12% would be glorious. But in reality, projects will get done for less…yes, even if companies “say” they use 12% as WACC (they just compensate with optimism on other parts of the model).

    Reply

19. I would caution you to talk to MORE industry veterans. Cast a wider net. You’re going to the same exact industry veteran, you’ve been going to for years. Like exaaaaa…aaaactly they same one I thought you were. You’re single point safe. And your single point is pretty anti-shale. At least get multiple views.

    I have ZERO idea if Permian Resources is a good proxy or not. I had actually never even heard of them! Much less the being my “heroes”. Just came up as first pure play Permian Basin shaleco when I looked for one online.

    Again, I don’t know if 9.4 is right upfront capex or 12 is. But it’s not a no brainer, when you say 12…and the very first thing I find on line (and not by their statements, but by dividing yearly capex by yearly wells) suggests otherwise.

    Again, I don’t know which number is better. (I do know how to improve the estimate, but not willing to invest a bunch of time, now, in doing so.)

    I would just suggest a little more humility. Try to at least know what you don’t know. Just because you draw spaghetti diagrams on a peak oil blog, doesn’t make you an expert energy economist.

    Oh…and this isn’t even to $60 is an unreasonable breakeven. Fed survey suggested low 60s! If anything I think you are low on OPEX (LOE, G&A) and high on CAPEX, so it kind of washes out.

    But sunk cost fallacy for old M&A deals and lease bonuses!? Grrr….get off my lawn! 😉

    Reply

    1. Nony,

       I am an economist, we use opportunity cost. I do my model in real terms, inflation adjusted dollars, a nominal discount rate of 12.5% assumes an average rate of inflation of 2.5 %, this gives me a real annual discount rate of 10%. Running an oil business is not risk free. The opportunity cost is an investment in VOO which has a long term real rate of return of 8% per year. To earn a net of 2% on a high risk investment would not be worthwhile imho.

       Reply

       1. Dennis

          You might be an economist but that doesn’t mean you understand everything about how things work in practice.

          https://oilprice.com/Energy/Crude-Oil/Big-Oil-Isnt-Backing-Down-at-60-Oil.html

          It is obvious to me that very large companies that have very cheap to produce fields are able to withstand low oil prices. They will see small companies which only work in limited areas struggle and then go bust. The big companies will then be able to buy up all these bankrupt assets a bargain basement prices. Rockefeller springs to mind.

          Also if OPEC do start pumping the 2.2 million barrels per day cuts, it will get very interesting.

          The big companies will end up owning everything and be able to control the price better. The low price will boost the economy for a while and the 2018 peak is going to be beaten.

          Reply

          1. Loadsofoil,

             I have never claimed omniscience, the point of mentioning economics is that business majors probably look at things differently than an economist, the same is true between physicists and engineers. A business major thinks sunk costs should be ignored, this is very short term thinking in my view, when looking at a business as a whole one needs to consider all costs because at the end of the day a profitable company has to pay back all the money it owes.

             Yes some large companies may have lower costs than smaller companies due to their market power and due to economies of scale. Note however that as smaller companies go bankrupt some marginal wells will be plugged and we may end up with lower overall output. As Shallow Sand pointed out earlier the marginal wells are operated by smaller producers with lower overhead and their is a limit to how low prices can go before they also become bankrupt or simply close up shop (these operators usually do not have much debt if they are smart.)

             I agree the large companies will survive and pick up the better properties from smaller producers, if those not so good wells are shut in we will see output fall rather than rise.

             Low oil prices sometimes boost the economy and sometimes they are the result of low demand. The turmoil in international trade cause by Trump is likely to lead to a World Depression, it will be interesting to see the quarterly reports from the large publicly traded companies when Oil gets close to $50/b, which it may do as OPEC increases output. We aren’t going to see much increase from Canada, US, or Brazil with oil at $50/b and other nations may see a faster decline in output as investment stalls at these prices, maybe OPEC will increase by 2 Mb/d, some might be offset by Iran and Venezuela seeing more strict sanction enforcement as oil prices crash. It will be interesting.

             Reply

             1. Dennis,
                In business you have to ignore sunk costs once they are sunk. There’s nothing you can do about them anyway. You have to play the hand you have. Caring about sunk cost is what you do beforehand.

                Reply

                1. Alimbiquated,

                   I understand some costs cannot be recovered, it is not clear that the purchase or lease rights to land that has not been developed qualifies. Also if we are considering profit and loss, it seems ignoring sunk cost is a mistake. Lets say I am a builder and buy land and build a home on that land, the cost to build the home is 500k and I sell it to a prospective buyer for 700k, do I now claim 200k profit because the land purchase is a sunk cost? I don’t think so unless I paid zero for the land, though even in that case only if I could only sell the land at a price of zero.

                   Typically this is not the case unless the land is in a very poor location (maybe on the moon).

                2. Sunk costs are sunk. If a company has “10,000 locations”, the leasing cost is sunk. If someone needs to contort themselves into a snail to call those non-sunk, then they are economically silly. This is like the easiest thing in the world to look at.

                   If you did a bad acquisition…and you don’t drill the wells, do you get the M&A payment back? No. No…no…no.

                   This is massively silly. If you’re dealing with someone who “isn’t sure” that lease bonuses (or M&A buys) are a sunk cost, than you are dealing with someone who can’t be trusted on much else. This is low hanging fruit!

                3. Nony,

                   One can do a point foward analysis that ignores sunk costs, or a full cycle analysis that looks at all costs to evaluate a firm, point forward is used when deciding to proceed with a project or not. Full cycle analysis answers a different question, such as why the hell is my firm not making any money? If we ignore past mistakes they will continue in the future.

    2. Nony,

       If I buy a piece of land or pay for the rights to access a lease, but I have not yet developed the land, there is no sunk cost, I can resell the land or the rights, you seem to not understand sunk cost. If I have drilled a well, that would be a sunk cost. The rights to drill on a lease can be resold to another company for some price, that is called an opportunity cost, by not selling that right for some price and instead choosing to drill a well, the company has left that money on the table as it were and that cost should be included as part of the well cost. This is very standard microeconomics 101.

       Reply

20. Your WACC is whacked. How do you think EOG is getting debt at 6%?

    Oh…and sunk cost fallacy? Just go sit in the corner and put the dunce cap on.

    Reply

21. https://www.youtube.com/watch?v=T4An37GXb2k

    Rusty Braziel on Cramer. Not saying, I agree with his points, per se, just find him decent to listen to.

    1. $60 is “ok”. 50 is bad. 80 would be awesome. (For shale oil producers.)

    2. LNG export growth to continue.

    3. Market doesn’t like the tariff talk.

    4. “AI” is overhyped.

    Reply

    1. Our wellhead today is $53.50. I’m not sure where the price points are in various shale basins in relation to WTI.

       I assume few go broke at $60 and still not a lot go broke at $50, unless that lasts for a couple of years.

       I do think if we stay below $60 rigs and frack spreads will drop, several factors go into that as has been discussed here a lot.

       Reply

       1. Agreed, I was talking activity (and hence production), not “going broke”.

          Reply

22. Opps
    US oil production falling 120,000-170,000bpd this year.

    https://x.com/Kpler/status/1919355178756559254?ref_src=twsrc%5Etfw%7Ctwcamp%5Etweetembed%7Ctwterm%5E1919355178756559254%7Ctwgr%5Ea4f2a52d036850645219d1bd0930a0bd0995c48b%7Ctwcon%5Es1_&ref_url=https%3A%2F%2Fwww.zerohedge.com%2Fenergy%2Fus-crude-oil-output-peak-early-year-kpler

    Reply

    1. JT,

       It says they have cut their forecast by 120-170 kb/d, excerpt from the tweet below

       Kpler now expects US #crude production to peak in 2025 and gradually decline after that.

       Reply

23. I just read Diamondback’s CEO letter. Appears Travis Stice has called peak oil, US onshore.

    Also appears that he isn’t as MAGA as maybe he used to be. Says steel costs have risen 10% due to tariffs.

    Reply

    1. The price difference between domestic and import is not that large with transportation cost all factored in, only 10% rise in cost, steel is relatively easier to use tariffs to boost domestic steel makers.

       The other major cost rise in shale oil gas is the bridge plugs, a 50 stage lateral will use over 50 plugs, and10 years ago, China was importing from US at $10K/ea, and 50 plugs will cost half a million. Now, majority of domestic US plugs use OEM or almost finished plugs from China at $~2k/ea. That’s a price hike of half a million for each well.

       Reply

24. Thank you Ovi for this work! The most interesting graphs for me are without a doubt the STEO’s March and April forecasts. The cornucopian extra barrels are dwindling into reality. The same, IMO, will probably happen to world production. If there ever was a second and higher peak after November 2018, it will be buried under the weight of Trump’s trade war. The yearly average will be a closer call, but it is becoming more and more obvious that we are not at the left side of the peak, but on a long, ondulating plateau. May it be long and stable enough for a transition to other energy sources! Mankind already won a decade or two with fracking and unconventional oil. Maybe one more decade and we’ll make it without bloody resource conflicts all over the world.

    Reply

    1. Westexasfanclub

       Thanks

       Besides myself, I thought that some of our readers would be interested in that change. That change has shown a further drop in US production in today’s May STEO report. It shows US production peaking in December 2025. Chart attached.

       I still think there is still a bit of hopium in today’s STEO update. I just don’t see 464 kb/d of crude being added to US production between March and December. I think that my projection charts indicate that we are very close to being on a plateau. Unfortunately, the vagrancies of updated state data mask that conclusion but today’s news from the CEO of Diamondback makes me think that my estimate may be more realistic.

       “The head of the largest independent oil producer in the Permian Basin predicts US shale production has peaked and will likely decline from here as oil prices hover near four-year lows.

       “We have a very good view of what the US looks like. And right now that’s a business that’s slowing dramatically and likely declining in terms of production,” Diamondback Energy (FANG) CEO Travis Stice said during the company’s earnings call on Tuesday morning.”

       As I keep saying, a few more months of data should clarify the situation. Hopefully.

       https://finance.yahoo.com/news/this-oil-price-doesnt-work-diamondback-ceo-says-us-shale-production-has-peaked-154712764.html

       

       Reply

       1. Ovi,

          I agree the EIA forecast looks quite optimistic especially when we consider their price forecast for WTI. I don’t see output increasing by much after April 2025 with WTI at below $60/b as forecast in the May STEO. I also agree that a few more months of data will make this clear, though there may be many wells that have already been drilled that might be completed so there could be a 6 to 8 month delay before we see this hit hard.

          I am unsure how it will play out, plateau forecast seems more reasonable for 8 months followed by decline, we may see that in falling rig counts.

          

          Reply

    2. Texas- “more and more obvious that we are not at the left side of the peak, but on a long, ondulating plateau. May it be long and stable enough for a transition to other energy sources! Mankind already won a decade or two with fracking and unconventional oil.”

       Yes, and it would be most welcome to achieve a stable outcome.
       That will take both a monumental effort with fierce determination, and having the collective mind in the right place, with smart economic policies.
       Sorry to say that our country ( and most others) ranks very poorly on those aspects, acting as if oil and gas will be abundant indefinitely.

       Reply

25. The worst of all worlds

    https://oilprice.com/Energy/Energy-General/Saudi-Arabias-Budget-Deficit-Surged-Before-the-Oil-Price-Crash.html

    https://oilprice.com/Energy/Crude-Oil/Big-Oil-Isnt-Backing-Down-at-60-Oil.html

    Saudi Arabia is fed up with Iraq and Kazakhstan producing more than their agreed quotas. So they are intending to reverse most or all previous cuts. This could bring up to 2.2 mbpd onto the market by November. How far oil prices will fall is anyone’s guess. $40 oil or even $30 for a short while is possible.

    The price drop will hurt many and over the next months/ year, a good number will go bust.

    After that the big oil companies will buy up bankrupt companies and drilling rights at rock bottom prices. After that they will probably restrict drilling to ensure a higher oil price.

    That is of course the best of the worst cases. Iran will be very angry with these low prices, their economy will be close to collapse. So an attack on Saudi terminals is a real possibility.
    At that point the United States could not just sit back and bombing Quds barracks and others sights would be an obvious start. Probably with the hope that anti government groups will rise up.

    Reply

26. Coffeeguy/all:

    Do you have a link to a good overview on the Waynesville (Western Haynesville) play? I found a few articles, but they are more topical/newsy, not overviews.

    https://www.tgs.com/weekly-spotlight/11-25-2024

    A video or PPT would be ideal.

    Maybe I will go through the Comstock quarterly webinars and there was a sort of “revelation” style overview. Like when Apache made a splash with “Alpine High”. Or like the Deep Utica stuff. Or Novi’s webinar explaining the Uinta basin

    And that is not to say it will/won’t be a disappointment. But I’d just like an overview, to get up to speed. Not even to debate it, to start. Just to have a handle on it, first.

    Reply

    1. https://www.hartenergy.com/ep/exclusives/japans-mitsui-testing-western-haynesville-alongside-comstock-aethon-212420
       https://x.com/novilabs/status/1805620765741478030
       Saputra/Patzek had a Haynesville TTR estimate in 2021, only 40TCF in core.
       https://www.sciencedirect.com/science/article/pii/S187551002100247X?via%3Dihub
       Yet by Feb, 2025, Haynesville already produced 40TCF and waiting to do another peak.
       https://www.eia.gov/petroleum/production/#ng-tab

       Reply

       1. Sheng Wu,

          When I look at that Saputra et al paper on Haynesville there seems to be little difference between core and non-core areas for EUR so the best forecast is the core plus non-core (URR=90 TCF), excerpt from paper below

          Ultimately, the 4684 existing wells in the Haynesville will give an EUR of 30 Tscf. By adding 923 wells in the core areas, EUR will increase to slightly above 40 Tscf. By adding another 5023 wells in the noncore areas, EUR will increase to above 90 Tscf. The wells in the outer Haynesville are so bad that adding 11,198 new wells increases EUR only to 105 Tscf.

          Expensive wells at 30 million each, yikes.

          Reply

          1. D C,

             You are right that their core and non-core area well have the close EUR estimate at 11BCF (Core) and 10BCF(non-Core).
             Again, Saputra/Patzek used outdated EUR data,
             ” By adding 923 wells in the core areas, EUR will increase to slightly above 40 Tscf” — or core EUR at 11BCF,
             while the fact is that the new completion wells should easily have EUR over 12BCF core and non-core average combined, see
             https://www.youtube.com/watch?v=CVqkN6YjVSc&t=673s
             and refrac of old design could also bring up the old wells EUR.
             Conservative/shale bashing Art Berman gave each lateral in Haynesville at even ~ 20BCF for 2018~2021 wells, which obviously Art distorted the data to show the sudden deterioration of 2023 wells — see figure attached, and I added the white arrows to show the realistic EUR.
             The 30million dollar cost is for West Haynesville wells, and the East Haynesville probably costs ~$15million. On average in the core, the East Haynesville wells have EUR (12 BCF) similar to a Marcellus dry gas shale well at under $10million. In the West Virginia shallow Marcellus, the cost of a 15K foot lateral is only ~$8million.

             

             Reply

             1. Sheng Wu,

                My guess is that Saputra used the data available at the time, the paper was published in 2019, probably only enough data to estimate 2017 wells at the time. For average 2018 well for Haynesville I get an EUR of about 10.6 BCF. In 2020 to 2022 the wells were a little more productive, likely due to increased lateral length, probably not a huge increase to URR perhaps a 20% bump in the URR of the play to 110 TCF.

                I agree the Berman EUR estimates do not look reasonable, Enno Peters had Haynesville wells up to 2022 at no more than 13 BCF.

                Reply

                1. I actually had a copy of the Saputra Haynesville preprint PDF, and the data plots are updated to 2020. The paper was received Jan.8 2021, and Accepted May 2021.
                   My guess is that their paper was basically using the pre 2017 parabolic decline curves in Haynesville, but actually post 2017 decline curves became linear. Similarly, they probably used a decline curve for Marcellus post 2016 well that has all tails collapsed.

                2. Sheng Wu,

                   Yes the terminal decline rate of the 2017 average well seems to be about 40% per year, so exponential decline at much higher rates than Marcellus (about a 10% annual rate of terminal decline). If we assume the 2018 well has about a 38% annual rate of terminal decline we get about 9.2 BCF for EUR and about 10.3 BCF for the EUR of the average 2020-2022 well.

                   Based on Novilabs data from

                   https://novilabs.com/blog/haynesville-update-through-april-2023-4/

                   The Saputra et al estimate seems pretty good and a URR of 90 TCF seems reasonable.

       2. Thanks. I wonder if it ends up being like the Deep Utica (too expensive to currently compete….but massive resource). At least it doesn’t have the constraints that the anti-infrastructure Democrats have created for the App gas production.

          Reply

    2. Nony,
       I know little of the Western Haynesville other than what Comstock has been describing in their quarterly conference calls.
       However, a short ‘Waynesville’ article popped up on my newsfeed the other day that was similar to the one that you linked in your comment.
       The geologic/operational parameters are simply jaw dropping.
       10,000/13,000/17,000 psi???
       350/400 degrees Farenheit???
       These guys will need to incorporate some of the cutting edge techniques/hardware of the deep water boys if they are going to jump into that pool.
       Reported depths of 19,000 feet already drilled with permits to 25,000???
       If the reporting is not misconstruing TVD with TMD, that would seem to be scarcely believeable.
       I know of a few Tuscaloosa wells landed at over 16,000 feet and one Rogersville well that was even deeper, but 19,000 feet down and building a lateral out from there?
       Wow.
       That 25,000 footer – if true vertical depth – might simply be an exploratory effort like the Rogersville effort.
       The weight on the rig to land casing would be extreme.
       One interesting aspect, however, might be the future knock on effects on the Deep Utica (and other potential ultra deep prospects).
       There were 3 Deep Utica wells with pressures in the 10,000 psi range and this caused a lot of (understandable) caution.
       If the ‘Waynesville’ boys continue to advance and produce natty in these VERY challenging circumstances, the eventual development of the Deep Utica should be able to evolve with great efficiency.
       The few Utica wells that are on the same pads as the shallower Marcellus wells have MUCH greater output.
       Lots and lots of natty in the USA.

       Reply

       1. There are still a few of us around who remember when the sign went up in Elk City, declaring it to be the Deep Gas Capital of the World. That was 1981 and America had been absolutely petrified that it was running out of natural gas–until the Bertha Rogers #1 drilled down to ~22,000 feet and was followed by a 24,000 ft well. Production was wild for a few years, until the fear of running out became utterly awash in oversupply, and then those super-deep wells became history. A new company named Chesapeake, under the tender care of Tom Ward and the late Audrey McClendon, drilled many of those wells, with damned little experience, running mostly on cockiness that only the very young possess. Some of those old wells are still producing, because there are five depths there in the deep part of the Anadarko Basin that produced commercial quantities of NG and oil. Hydrocarbon source rock went as deep as seven miles, the seismics said. As is often the case with very deep and complex geology, there had been created a wonderful oil and gas trap–and this one was as unique as any. Thick layers of pink and grey granite underlies that area. If you drive south of the north fork of the Red River you will see massive granite chunks lying on top of the ground, like nature’s junk heap. They are the size of Volkswagen Beetles. You don’t have to quarry this granite; it is piled up in giant stacks. A town was named Granite; as you might surmise they make tombstones there. This unusual deposit was due to a massive eruption deep underground millions of years ago. You can lease that acreage for peanuts, because the hydrocarbons were belched up when that eruption occurred. On the north side of the north fork of the Red River you won’t find granite lying on the earth, because here, farther from the epicenter, the force of the eruption merely turned the granite on its side, in every imaginable angle. In a narrow streak of land it is possible to bend the drill bit and get between the granite slabs lying askew, thus tapping into a magnificent reservoir of natural gas that is being slowly but continuously repleted by lower sources of reservoir rock. At the time the field was being flushed out the pipelines ran full, satisfying several large gathering stations along the way. The entire Stiles Ranch was purchased by a major oil company, just so they could work in peace without having to quibble about where a service road could be constructed. In this “Deep Gas Capital of the World,” the memory of that eighties gold rush is waning, as other places snatch up the catch phrase as the newest hottest thing (“Waynesville”). In the wake of the frenzied development over forty years ago lie many dormant areas that possess commercial quantities of natural gas, and the infrastructure is still in place. You are exactly right, sir, there’s “lots and lots of natty in the USA.”

          Reply

       2. Coffeeguyzz,

          The Utica wells produce more at first and then decline faster, after about 60 months the average PA (mostly Marcellus) and OH (mostly Utica/Point Pleasant) wells have similar cumulative output for 2017-2020 wells.

          Reply

27. West Haynesville is like an entire separate play, Dennis. It’s literally not even on the map of the entire Haynesville that Patzek drew. (Not his fault, it wasn’t being developed yet.)

    It’s not the west part of the existing (what Comstock call “legacy”) Haynesville. But several counties over and with a gap in between. Maybe think of MT and ND Bakken as examples.

    See: https://csv-storage.forexpros.com/slides/c0a8cb4e69814a4d35084dbbb02ac7c81abf181fccf907b8edeb49d357374e3b.png

    It is WAY far away. (The blue in lower left of picture.)

    Reply

    1. Nony,

       Yes I see that.

       Reply

28. You are full of it, Dennis. Breakeven for drilling wells was the question. Cost of the well versus expected returns, at different price points. Land cost is sunk*, and varies by operator anyways. Should we have a different breakeven, for the exact same project, with different owners, based on the history of what lease or M&A costs were? No…it is SUNK.

    *With the exception of a very tiny amount of new leasing.

    Reply

    1. https://bsky.app/profile/beachmagoo.bsky.social/post/3lok4oeqqf22v

       risk of becoming stranded assets due to high production costs.

       

       Reply

    2. Nony,

       The question is how we define breakeven, to maximize profits a point forward estimate is used, to evaluate a business a full cycle analysis is best in my view. A lot of poor decisions have been made in the tight oil business, point forward estimates hide this fact.

       Reply

29. Paul

    Not sure of the source for the Canadian data. Attached is a table that shows the operating costs posted by Suncor last night in their Q1-25 report. The $ are Cdn so multiply by 0.725 to convert to US. Realize Cdn companies collect US$ and pay Cdn wages which may be lower than those in the US.

    First Quarter Highlights
    • Generated over $3.0 billion in adjusted funds from operations(1) and $1.9 billion in free funds flow(1)
    • Returned $1.5 billion to shareholders, with $750 million in share repurchases and $705 million in dividends.

    Not sure how these numbers change with WTI at $58/b.

    https://www.suncor.com/-/media/project/suncor/files/investor-centre/quarterly-reports-2025/2025-q1-suncor-energy-quarterly-report-en.pdf?modified=20250506205438&created=20250505143316

    

    Reply

30. Permian scenario that assumes rig counts fall due to low oil prices as forecast by May STEO. The slight increase in Permian output in 2025 will be offset by falling output in the rest of the US. I expect US C plus C output will be flat or decline slightly over much of 2025. CTMA=centered twelve month average.

    

    Reply