US February Oil Production Rebounds

46 thoughts to “US February Oil Production Rebounds”

1. Thanks Ovi – Interesting article about the near term Permian peak:
   Alarming Trend (I’d say it echos a lot of the discussion here)

   https://seekingalpha.com/article/4688683-an-alarming-trend-is-developing-in-us-shale-oil-production

   1. Kangeo

      One of the issues with gassier counties is knowing what to plot.

      Attached is a chart for Reeves county which has a lot of Gas wells. The green graph is total gas divided by C plus C.

      The orange graph is oil well gas divided by oil well crude. Both charts are indicating that Reeves county is heading towards the bubble point. Which one is more relevant. In NoviLabs, January update, Enno posts a GOR chart. Not sure what variables are in the ratio.

      

      1. Ovi,

         Pretty sure Enno uses C C (from all wells) for “oil” and total gas (associated with oil production and gas from gas wells) for “Gas” in his oil and gas ratio. More similar to your green plot.

         1. Dennis

            Using total gas is not the best way to do things if the objective is to determine if the oil wells are peaking. NM only gives oil and gas, no disaggregation into oil wells and gas wells.

            1. Ovi,

               I disagree, the oil and gas wells are together in the same counties you are analyzing and often what is classified as a gas well and what is classified as an oil well is determined by the GOR, essentially it is an artificial distinction, most wells produce both oil and gas. New Mexico does this correctly and to compare the Texas data to the New Mexico data on an apples to apples basis, one would be wise to follow the New Mexico model in my view. Use crude plus condensate for Oil and Gas from both oil and Gas wells for Gas output.

               Perhaps Enno’s thinking is similar and he may want to keep the data comparisons consistent. Also for EIA data you will notice that there is no Oil from oil wells category, all the oil and condensate from all oil and gas wells is lumped together as C plus C.

               The peak will be determined by the rate of completion and the economics. The falling level of Appalachian output and more pipeline capacity to LNG export terminal and perhaps completion of more LNG export capacity may lead to higher natural gas prices which may make Permian output more profitable. If profits are higher more wells will be completed each month and output may continue to rise.

               My very conservative scenarios for the Permian basin assume that the completion rate remains at about the 2023 level, even with an assumed decrease in new well productivity of about 4% per year, output continues to rise until 2026 (but quite slowly increasing from 5719 kb/d in March 2024 to 5912 kb/d in Sept 2026, which is the peak for this scenario). I doubt that output is much lower than this scenario (this would be an F90 scenario). Chart in next comment below.

            2. Permian scenario

               

      2. Reeves County using Novilabs data Jan 2021 to December 2023

         

         1. RRC Reeves Data up February

            Similar

            

            1. Ovi,

               Yes fairly similar, though data after December 2023 is likely not very accurate. Even the data from March 2023 to December 2023 may not be accurate, but the most recent data is the furthest from being correct (as you clearly know, but some readers may not be aware). Also the Novilabs data focuses on horizontal tight oil wells, the RRC data includes all production (though most output currently in Reeves county is tight oil from horizontal wells, so this may not affect the data much),

               1. Dennis

                  I hear you but NoviLabs is showing 435 kb/d for January while NM is showing 408. Somehow NoviLabs has more up to date info.

                  

               2. Ovi,

                  Not clear why that is, but Enno Peters is very good, there might be some data out there we are not aware of, also he may have access to Enverus data and perhaps some proprietary data from producers, my guess id that the Novi data is about as good as it gets, but the most recent few months are probably less than perfect.

                  For some reason I get a different result for NM for Novilabs in Jan 2024, 1762 kb/d for Permian basin NM.

                  https://public.tableau.com/shared/BK6MJ9CRN?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y

               3. Ovi and Dennis,

                  I don’t think proprietary production data in Texas is legally possible. All operators are legally obligated to report their accurate production data to the Texas RRC.

                  So, Novilabs is just using Texas RRC data, just like Enverus uses. They all do a massive data dump every month. The operators can’t legally give out different proprietary production data to folks at Novilabs, otherwise they would be in violation of many laws. If Novilabs wants to spin the public Texas RRC data through their proprietary AI algos, go for it, but the real raw data is best and available free from the Texas RRC. Or, recycled in a pretty good format on Enverus. But all the same data.

                  There are no proprietary production data sources for Texas, just the Texas RRC.

               4. Dennis

                  What I put up was Reeves county. I mistakenly said that data was from New Mexico govt. My bad.

               5. Gungagalonga,

                  Not sure there is anything illegal about sharing data, you are correct that operators give their data to the RRC, eventually, though the data often comes in 12 to 18 months after the fact. One place that the RRC falls down is it reports output only at the lease level and often there are many wells on a single lease. Novilabs supposedly get the individual well data from some of the operators and can check their algorithms for accuracy and likely can improve upon them useing such data. It is also possible the data can be processed in a more timely manner by Novilabs than by a government bureaucracy.

                  There is also data from the pending lease file which can be used to fill in data.

               6. Ovi,

                  Enno may be using the pending lease file, but that file only defines things to the district level, so not clear why the RRC data is different from Novilabs. Enno may use past data on the percentage of output from various counties that make up a district to estimate county output from pending leases, or that is how I would do it, he may have a better method as he scrapes a lot of the data from the RRC and may be able to figure out which pending lease data belongs in which county, perhaps by looking up well numbers and permit data.

                  If we look at the percentage of district 8 output from Reeves in Jan 2024 it was 13.8%, if we assume the pending lease output in district 8 from Reeves county was also 13.8% we get 57 kb/d of pending lease output from Reeves county. If we add that to the 408 kb/d reported in the PDQ we get 465 kb/d which is higher than reported by Novilabs. So they use a more sophisticated approach or there may be 30 kb/d of conventional output (and tight output from vertical wells) that I have not accounted for.

               7. Dennis, my point was that the operators would not sell or give out production data to a private entity that is different than what they report to the TX RRC. If the data is reported differently to the TX RRC vs. Novilabs, then it exposes the operator to all kinds of scrutiny, lease violations, lawsuits and fines, etc…. would be chaos and not worth the risk to the operator. This is the “illegal” part.

                  If Novilabs gets the same TX RRC data and then massages it somehow to make it project in a proprietary way, so be it. But Novilabs is also subject to the same lag times and revisions as reported to the TX RRC as there is only one stream of initial data… operator to TX RRC. Then it spreads out to all the data users to explore.

                  Novilabs may have select sampling operator partners to test projections with, which is fine and may help with their accuracy, but they start with the same data as everyone else.

               8. Gungagalonga,

                  There is the pending lease file which has production reported for leases that have not yet been assigned a number by the RRC, only leases with a lease ID # are reported in the PDQ from the RRC. Note that it takes time for reports to filter through to the PDQ part of the website, if the same data was reported to Novilabs and the RRC by an operator, it is very likely that Novilabs would process the reported data far more quickly than the RRC and we would see it sooner, especially those that subscribe to the service.

                  If you download a statewide PDQ now and save it on your computer and then do the same in 6 months and compare, you will see the data filters through the RRC bureaucracy very slowly. Eventually the data is complete, but it takes about 18 months.

                  My point is simply that the availability of reported data on public websites will be different, in some places it will be reported more quickly than others. That is part of the reason that people are willing to pay for the data.

               9. Dennis,

                  Assuming Novi received the raw data at the same time as the RRC, perhaps they could process a bit quicker than the Texas RRC, I agree. Novi probably presents the data better too. But what’s the point? Novi would still be subject to the same lag time for revisions and late data. Yes, you can assume an average typical revision/late reporting projection and get close. I used to attempt to model this at a previous position on the financial side of energy… we kept tract of the near months RRC revisions over time and logged in all iterations over time to get a pattern. Sometimes we were close on projections, other times the RRC surprised us and went rogue. Hardly useful for commodity trading!

                  Not sure where this discussion is going, which is likely my fault. My original point was simply that Novi is subject to the data as reported to The TX RRC as operators are obligated to report volumes in a timely and accurate manner to the RRC. I can’t see how Novi has proprietary data from every Texas lease, they likely don’t have the scale. Novi and Enverus wait in line to receive their raw data from the RRC, but may handle the data better. I subscribe to Enverus/DI, but have never used Novi since I have no use for it in my business, so you likely have more wisdom here.

                  Thanks

               10. Gungagalonga,

                   The only important point is that the pending lease file will give additional insight, also the EIA estimates based on 914 survey data (data comes directly from producers with about 90% of total Texas output) and an estimate of the remaining 10% of output is surprisingly accurate. So in my view that is the best approach to estimating Texas output. To estimate Texas Permian output simply take the percentage of district 7C, 8, and 8A output to statewide output and multiply by EIA estimate, that will include some conventional output, the Novilabs data can then be used to sort out the percentage of conventional oil and vertical well tight oil output.

                   Basically the Novilabs estimate is the best I have access to, I do not have access to Enverus data.

                   As to how timely and accurate the data is reported to the RRC is not known by me, I only see what data the RRC provides and the PDQ data is not very good and the pending lease file is difficult to work with, though if I were proficient with SQL or other database applications it might be less of an issue.

                   Enno Peters is an expert software engineer, I am not.

               11. Dennis.

                   I read the discussion regarding RRC data.

                   Crude oil purchasers sell their data to IHS Global, etc., who then sell the data to others (like our company).

                   Our oil sold during the month of April will be posted by IHS Global in June, so very timely.

                   It is sales data, which differs from production data, but should smooth out over time.

                   Doesn’t Enno Peters use a lot of algorithms in his work? I think he is constantly making adjustments, so his data ahead of RRC official data is very close.

                   He may incorporate the sales data in this? I’m just speculating.

                   I do know years ago I compared his data to IHS Global data we paid for and he was spot on. That was 2015-18. I suspect he’s gotten even better as time has went by.

               12. Thanks Shallow sand. I don’t know the details of Enno Peters methodology, but he may incorporate sales data. I agree his estimates are quite good, when I look back at earlier estimates and compare with the most up to data I have available there is a small adjustment to the most recent 6 months of data reported in the older reports, but as I said earlier this is probably the best tight oil focused data available IMHO.

               13. This is my response to your comment on oilystuff.com.

                   As an actual P-5 verified opertor in Texas for over 50 years, your comments about the Texas Railroad Commission, its production reporting (now corrected 90% in 90-120 days) is grossly inaccuarate, extremely bias and a disservice to people who read social media for real information. Novi is no longer run by its originator and is just another data-sell company trying to keep the party going. Its AI and ML learning dung heap is algo created and subject to great bias; neither it, nor the EIA, or DPR, or NCAA, or PETA, have any insights into oil and gas that the State of Texas does not completely resolve over time.

                   Only the State of Texas knows its oil and gas depositions; if you can’t wait for that to occur I suggest something like pickle ball.

                   https://www.oilystuff.com/forumstuff/forum-stuff/chevy-in-eddy/dl-ec02890d-39ae-4d22-b5e5-fab2b0d4e4c5?postId=663416f86378bd0010a0a26e

               14. Mike,

                   the link you posted goes nowhere, 90% is not very good after 120 days. As I understand it Enno Peters still works at Novilabs and does excellent work. He wrote the Permian Blog post on April 26, 2024.

                   In that post he says:

                   The current level of drilling & completion activity should be enough to further expand the production capacity of the Permian Basin, all else being equal:

                   The very simple supply projection assumes current levels of completion rates and average new well productivity continue from March 2024 to December 2029, clearly neither assumption will be correct. Any scenario of future output is certain to use incorrect assumptions.

                   As far as the poor estimates of the EIA the chart below uses the Texas 914 estimate from

                   https://www.eia.gov/petroleum/production/xls/comp-stat-oil.xlsx

                   and compares with PDQ data from the RRC from Jan 2015 to December 2022. Note that the EIA actually underestimates RRC output especially in 2022, but mostly the estimates are pretty good, this is simply the fact of the matter. Note that this is not the EIA final estimate (which uses RRC data after about 22 months in the most recent compstat spreadsheet) it is the initial monthly 914 estimate based on the 914 survey and an estimate of the remaining 10% of output not covered by the 914 survey.

                   A simple way to compare the RRC and EIA data over this period is to take the sum of each. The EIA sum is about 99.89% of the RRC sum from Jan 2015 to December 2022.

                   Also it is quite difficult to extract the tight oil data from the RRC, Enno Peters does an excellent job of that in my view, also it is not easy to figure out the well profiles for multiwell leases as the output is reported by lease rather than by well. A sophisticated software engineer like Mr Peters is able to sort that out and present the data in a very usable fashion which is impressive.

                   Don’t some producers share their data with IHS as Shallow Sand stated? Isn’t there a pending lease file which a good software engineer could incorporate with the PDQ data to get a more up to date estimate?

                   

               15. Dennis.

                   To clarify, our crude oil purchasers sell data to IHS and others. We, as operator, don’t.

                   That’s our experience. Cannot speak for others.

               16. Shallow sand,

                   Thank you for the correction, purchasers share the data, as you stated earlier this is not the same as producers, though when all the purchases are added up it should be fairly close to the oil produced (there could be some stock changes which would account for small differences).

               17. Ovi,

                   Check out pending lease file, you can get a bit more up to date data for Texas statewide by adding this to PDQ data.

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

                   See “Production Report for Pending Leases” under “Production data” at page linked above. You want to filter out the “is deleted” column data that has the “Y” flag so you don’t double count data that is already in the PDQ (leases that now have a Lease ID# assigned and are now no longer “pending” leases.) Enno Peters may use this data to get a better Texas estimate (though this is a guess on my part.)

               18. As a Novilabs subscriber, let me weigh in on Novi’s proprietary data

                   Producers do keep track of individual well production but it is aggregated by lease when it is reported to the RRC. This is the operators’s proprietary infomation.

                   Novi has negotiated an arrangement with “some but not all” operators to obtain access to individual well production records.

                   These records/production data is used to improve Novilabs algorithms to directly report individual well production and to “smooth out” the production type curves and data for operators that do not share individual well production data.

                   These companies perceive their production data to be a competitive advantage.

                   I know from inquiries made to Novilabs that EOG and Mewbourne do not share production data with Novilabs.

                   I hope this helps the discussion

2. Made a comment on the non oil thread that was marked as spam. Just wanted to see if this comment would also be marked as spam.

3. Permian Basin estimates from Drilling Productivity Report (DPR, includes tight and conventional oil from Permian Basin Region), from Official EIA tight Oil estimate (Permian estimate includes only Spraberry, Wolfcamp, and Bonespring Formations), and the Permian tight oil estimate from Novilabs through December 2023 (includes only tight oil output from horizontal wells that started producing after 2000). In my view the Novilabs estimate is likely to be closest to actual Permian basin tight oil output. For December 2023 the Novilabs estimate for Permian horizontal well tight oil output is 5700 kb/d, output in December 2021 was 4581 kb/d. Data presented in Chart below is from March 2021 to December 2023.

   

   1. The estimate below uses state data from TX RRC and NM OCD and the EIA 914 estimate for Texas and New Mexico to estimate Permian region output. This estimate is compared with the Novilabs Permian estimate where we find an average difference of 502 kb/d over the June 2020 to May 2023 period between the state data for the Permian region and the Novilabs Permian tight oil estimate. This 502 kb/d estimate represents conventional and vertical well tight oil output from the Permian region and also output from wells that started producing before 2001 in the Permian region (RRC Districts 7C, 8, and 8A). I assume the conventional and vertical tight oil output remains at the 502 kb/d level from March 2021 to December 2023 and subtract this amount from my Permian region estimate to arrive at the Permian tight oil estimate presented below. The red diamonds are my estimate and the blue line is the Novilabs Permian estimate presented for comparison. The data presented below starts in March 2021 and ends December 2023.

      

4. The price for natural gas in the Permian is around -$2.72. That’s a negative. The rising gas oil ratio is coming at a time of lower gas demand and pipeline maintenance. I can’t imagine this, along with a deteriorating price for WTI over the last few weeks, is doing much good for horizontal well economics. If we are going to have increasing quantities of natural gas over the next 5-10 years from these tight oil plays it’s hard to imagine the gas price situation will improve dramatically. I guess that’s the desire to export it. Of course all that liquefaction infrastructure will last a long time and these tight oil plays will likely be ghost towns within a decade leaving a lot of stranded assets.

   https://oilprice.com/Latest-Energy-News/World-News/US-Power-and-NatGas-Prices-Plummet-to-Below-Zero.html

   1. Stephen,

      Large producers may have contracts with pipeline operators, EOG sold its natural gas at an average price of $2.10/MCF in the first quarter of 2024 according to the 10Q. NGL was sold at an average price of $24.32 per barrel and oil at $78.46/bo for 2024Q1.

      See page 23 of link below

      https://filecache.investorroom.com/mr5ir_eogresources2/332/2024 03.31 10-Q.pdf

      Occidental Average Prices for 2024Q1
      NG=$1.61/MCF
      NGL=$21.17/b
      Oil=$75.54/bo

      Diamondback average prices for 2024Q1
      NG=$0.99/MCF
      NGL=$21.26
      Oil=$75.06

      see page 36 at link below

      https://www.diamondbackenergy.com/static-files/657b3a69-373a-4a99-aaf2-73dc3f533bc8

      Devon Energy average price (unhedged) 2024Q1
      NG=$1.30/MCF
      NGL=$20.81/b
      Oil=$75.40/bo

      See page 24 at link below

      https://d18rn0p25nwr6d.cloudfront.net/CIK-0001090012/ea2ef245-d32b-41ca-81f8-8edcc3eca791.pdf

      For XOM (merged with Pioneer) for 2024Q1 US upstream
      NG=$2.22/MCF
      Oil=$74.96

      (they do not break out price for NGL)

      see page 4 of link below

      https://d1io3yog0oux5.cloudfront.net/_78625fd669a00aa37b1285d9b3404898/exxonmobil/db/2288/22249/supplement/1Q24 Supplement Website.pdf

      Eventually more pipelines will be built to move the gas, there is a risk of stranded assets if the LNG facilities are overbuilt.

      1. Interesting, good for them. But someone is losing money somewhere. The last thing you want is the pipeline operators to go bankrupt or the party will be over for sure.

         1. Stephen,

            The price for natural gas becomes negative when there is not enough pipeline capacity to move the natural gas so the operators are essentially paying someone to store the gas. Probably smaller producers are getting stuck with gas that has no place to go and they will cut back on starting new wells and perhaps shut in some production if that is what makes sense financially. It is a rough business during the shoulder season when there is less demand for energy.

      2. Using the average of these prices in comment above and assuming the average 2024 well is a bit less productive than the average 2022 well (EUR=425 kbo over 177 months, with 166 kb NGL and 2002 MMCF of NG over that period of 15 years) The cumulative net revenue over 36 months is 10.95 million and reaches 12.1 million at 48 months and 13 million at 60 months. At a 10% annual discount rate the discounted net revenue reaches 13 million at 112 months. At 177 months cumulative net revenue is $15.8 million and cumulative discounted net revenue is $13.3 million.

         At these prices this is not a very profitable venture.

         Average realized prices for Permian producers are:
         NG=$1.64/MCF
         NGL=$21.89
         Oil=$75.88

         1. Like you suggest, the bigger players have probably negotiated better deals and are sitting on better acreage, and are coming out alright. But marginal producers have to be getting squeezed in this environment.

            1. Stephen,

               Yes that is why I do not expect the completion rate will rise and at these prices evn the scenario below may be optimistic because a fall in the completion rate might be a more reasonable scenario (the scenario below assumes the completion rate remains at about the 2023 average level until 2029 and then starts to fall.

               The scenario below assumes the completion rate falls by 1 well per month starting in Jan 2024 and increases to 3 per month at the end of 2032. Peak is in mid 2025 at about 5800 kb/d for this scenario and URR=43 Gb with 113 thousand total wells completed (at the end of 2023 about 49 thousand tight oil wells have been completed in the Permian basin and in mid 2025 for this scenario it will be about 55.5 thousand wells completed).

               For this scenario over Dec 2023 to June 2025 period the average annual rate of increase in output is about 67 kb/d.

               Click on chart to zoom in.

               

   2. Scenario (red dotted line) after December 2023 has Permian output growing more slowly. (At an average annual rate of about 80 kb/d over the next 2.5 years). Peak is about 5900 kb/d in mid 2026.

      The rate of growth slows from 567 kb/d per year from March 2021 to December 2023 to 80 kb/d per year over the next 2.5 years which is about a 7 times lower annual rate of growth than the previous 2.75 years.

      

5. Gasoline demand in US falls to pandemic levels.

   https://oilprice.com/Latest-Energy-News/World-News/US-Gasoline-Diesel-Demand-Hit-Seasonal-Low-Not-Seen-Since-COVID.html

   At sub $80 WTI, there is no call for more oil or drilling at present. Oil markets seem balanced in $80-100 range. We are tipping into a peak demand scenario, probably from the rapid uptake of EVs in China. China is far ahead of US manufacturers in EVs, even Tesla, who has completely stalled out as a company. Read this amazing essay:

   https://insideevs.com/features/719015/china-is-ahead-of-west/

   1. Two other factors may be also be moderating gasoline demand, due to decline of consumer affordability-
      Inflation is widespread. Higher costs for everything not called gasoline leaves less cash in peoples budget for optional travel.
      Secondly, strong us dollar results in lower emerging market country purchasing power.

      1. Real Gasoline prices in 2015 US$ for US.

         For real median income see

         https://fred.stlouisfed.org/series/MEPAINUSA672N

         

6. https://www.reuters.com/world/europe/ukraine-drone-hits-russian-oil-facility-record-1500-km-away-source-says-2024-05-09/

   Ukraine hit Russian oil facility 1500km deep inside Russia.

7. The Rig report for the week ending May 10.

   – US Hz oil rigs decreased by 4 to 454. This is the first big drop, 4, in many weeks.
   – Texas Permian was down 2 to 200 while NM was unchanged at 102.
   – In New Mexico, Lea and Eddy counties were unchanged at 49 and 53 respectively. In Texas Martin dropped 3 to 35 and Midland dropped 1 to 21
   – Eagle Ford added 2 to 48
   – NG Hz rigs were unchanged at 93. (Not shown)

   

   1. Moving rigs from the Permian to the Eagle Ford. That’s interesting!

8. Frac Spread report for the week ending May 10.

   The frac spread count increased by 6 to 258 and is down 14 from one year ago. The chart continues to indicate the frac spread count is range bound between 250 and 275 going forward.

   

9. A new update to World and Non-OPEC oil production has been posted.

   https://peakoilbarrel.com/january-non-opec-and-world-oil-production-big-drop/

   A new open thread Non-Petroleum has been posted.

   https://peakoilbarrel.com/open-thread-non-petroleum-may-11-2023-2/

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