Baker Hughes Rig Count down 2 rigs w/w to 734.  February was down 22 rigs month/month.


Source: DEP/Baker Hughes



WSJ- Energy Industry Wrestles Over Going Green Too Fast- Link

WSJ- How Gas From Texas Becomes Cooking Fuel in France Link

FT-Why Germany has blocked the road to banning EU combustion engines-  Link

FT-How Citadel harnessed the weather to claim hedge fund crown-  Link

FT-BP insists it is not slowing green transition to cash in on high oil prices-Link


DEP Update:  We are officially now on Spring Break, writing this note from the slopes of Steamboat.  Therefore, expect a short note next Sunday as we begin our chill (literally and figuratively) starting in 15 minutes.  Several items on the networking/research docket – let us know if interested or attending:


  • DUG Haynesville – March 27-28th – will assemble a small-group dinner on 3/27 in Shreveport if anyone is going.
  • Midland Dinner/Reception – March 28th 
  • OKC/Tulsa – April 3-5th
  • Post Q4 earnings CFO/IR dinner/reception (public company friends) – targeting April 6th – location TBD in Houston
  • Houston Golf Outing – April 10th – Kingwood Country Club
  • Midland Dinner/Reception – April 19th
  • Bynum School BBQ – April 20th – got cookers lined up.  Could use some small donations for things like water, tea, sides, etc.  Will focus on finalizing this in two weeks post spring break.
  • Astros Seasons Tickets – we broke down and bought six tickets – good seats – clients, let us know if you ever need tickets.  Don’t be shy.





E&P Observations: Earnings continue to straggle in, and the themes have been relatively consistent: Costs are plateauing for rigs, completions, and tubulars, and there’s plenty of hope that price concessions are in the offing as activity wanes thanks to natural gas plummeting.  Despite this, most folks have targeted 10-15% year-over-year inflation for their budgets.  When compared to annualized Q4 run rates, full-year capex guidance is running about 9% higher for the companies who have reported so far (see table below).




CVX hosted its analyst day this week, and the presentation was divided into three parts: Higher Returns, Lower Carbon, and Winning Combination.  Most notable to us was the commentary on the Delaware basin, where results fell short of internal forecasts due to horizontal interference and “long-sitting DUCs”.  The DUCs in question were drilled in 2018 and 2019 in multiple benches.  Their new plan is based on their non-DUC wells from last year, drilled in single benches and in some deeper zones.  Pursuing this path going forward should improve results in the Basin—even with more rig moves per section impacting cycle times.   Chevron also highlighted inflation expectations in its budget:  5-7% overall, with the Permian in the “low double digits.”  CVX intends to run four grid-powered rigs this year and one natural-gas-driven frac spread.  For CVX’s Other Shale & Tight development, activity is also growing, with 8 rigs this year growing to 11 by 2025, spread between Argentina, Haynesville (1 rig), DJ Basin (expect to POP 2x more wells this year), and the Kaybob Duvernay.  On the financial front, management acknowledged that it can’t forecast oil prices, but given what it can control on the cost side, the company is raising its annual share-buyback guidance to $10-20B a year:  $10B at $50 Brent, higher above that.


Canadian producer Baytex is acquiring ROCC for ~$2.5B, or 2.9x EV/EBITDA.  The transaction is expected to close in late Q2.  Baytex has ~78K EF acres (mostly Karnes Co.) with an average 25% working interest.  Ranger will add materially to this position, with a proforma total of 267K gross acres with an average working interest of 68%.  Combined production will be >95 MMBOE/d (68% oil).  Baytex believes the combined acreage has more than 740 undrilled locations—a runway for 12-15 years of development activity using a 2-rig program.


Random Observations:


  • Pure Frac announced via social media that it would take delivery of its first Tier 4 dual fuel fleet in Q3’23.  Another private Permian frac company will also take delivery of its first Tier 4 dual fuel fleet around the same time.  Companies with legacy equipment are now upgrading, a trend to watch.
  • Texas Pacific Land Corporation announced on its Q4 earnings call on 2/23 that it would build four “proximity” mines.  The company noted sand sales would total nearly $20M which, to state the obvious, means the sand is going to someone else, presumably a large E&P.  Meanwhile, as we did channel checks on this, we learned another private E&P is purportedly preparing to pursue its own proximity mine.
  • A small private E&P in the Haynesville market reports concessions from well service contacts happening now and further reports a noticeable increase in rigs sitting in the yard.
  • A land driller reports customers asking for price concessions, but none have been made yet.  In one case, a private E&P requested a concession to which our drilling contact declined.  As a result, the rig will be released.  Our drilling contact is opting for margin vs. market share (as well as dividends vs. capex).  The contact did note an expectation that one E&P will drop two rigs in the Bakken, but it’s not clear if those rigs will be moved to another region in which the E&P operates.
  • In the Permian this week, an E&P noted it signed up a tier 1 rig at $34k/day, which is higher than the $28k/day they were paying, but lower than the $40k/day the contractor was asking for.
  • A well service contact with exposure in multiple basins reports no change in utilization yet.  In fact, rigs coming out of refurb expected to go to work soon.  However, price concession requests are coming in.  In one case, our contact politely declined; however, in another case, a price concession was made, but is subject to the customer allocating more work to the well service contact.
  • A second well service company reports no price concessions yet and still plans to seek some modest increases this year.  Discussed prospects of M&A.  Contact understands value of consolidation, but also understands better to pay oneself a dividend than enrich a potential seller.  Similar view as a few other contacts which implies some likely consolidators on paper might be likely consolidators in reality.
  • Not everyone experiencing efficiency gains. One private operator said they expect efficiency gains to get harder as quality equipment and people are tight. In 2021 they drilled and completed 144 wells with five rigs, in 2022 they drilled and completed 134 wells with 5 rigs.  Not sure about differences in laterals, so not entirely clear if this is an apples-to-apples comparison.
  • At Thrive, one E&P noted some relief on casing costs.  However, in Midland this week a private Permian E&P claimed casing costs 12-18 months ago was $300k/well vs $1MM/well today.  Casing costs for this particular E&P are not coming down but finding casing not as bad as last year.


SOI:  Announced an increased dividend by 5% and $50M stock buyback authorization (roughly 11% of shares).  SOI was able to navigate the 2020/2021 downturn without cutting its dividend and this represents its second dividend increase.


U.S. Land Rig Count: Declined 2 rigs w/w to 732 rigs.  We will be cleaning up the DEP rig count forecast next Sunday.  It will move lower.  No surprise to DEP readers.


EIA Monthly Report Takeaways (Authored by Bill Herbert): The EIA released its 914 monthly production data on Tuesday February 28th. The 914 data is the highest quality domestic production data and has a three-month lag. Thus, the following summary pertains to data as of December. US oil production in 2022 largely performed in-line with EIA projections (11.9 MBD) while nat gas outperformed (dry gas ~98 BCFD). As expected, Dec US oil production contracted sequentially (by 276 KBD) due to weather gremlins. Exit-rate 2022 production averaged 12.1 MBD. EIA oil production projections for 2023 (12.49 MBD) look doable but increasingly ambitious (2023E +610 KBD y/y) ‒ y/y growth optionality will be fueled, in part, by easy 1H comps (1H’22 avg production ~11.6 MBD vs. pre-weather disrupted Nov output of ~12.38 MBD).


E&P cash flow has been meaningfully squeezed due to the collision of lower commodity prices (particularly nat gas – HHUB has been sub-$3/MMBTU since late-Jan and is currently down ~35-40% YTD and ~60% from the Dec peak; Waha has been sub-$3 for most of 2023 and frequently sub-$2) and markedly increased well costs (starting to moderate). Notwithstanding, Jan weekly US oil production data averaged 12.2 MBD, and Feb has averaged 12.3 MBD. Should the monthly data align with the weekly, US oil production is in the process of recovering from weather-afflicted Dec – the question is how quickly it will grow from a weather-normalized baseline, which will be a function of the pace of E&P cash flow expectations and reinvestment.



  • Dec US Oil Production:  12.1 MBD vs 12.375 MBD for Nov, down 276 KBD m/m and up 467 KBD y/y (Nov +587 KBD y/y). In the event the EIA weekly data proves prophetic, production should be up m/m in both Jan and Feb.
  • 2022 Avg US oil Production:  11.88 MBD, +636 KBD (2021 = -80 KBD, 2020 = -988 KBD, 2019 = +1.4 MBD, 2018 = +1.6 MBD, 2017 = +510 KBD).
  • Dec L-48 Onshore Production: 9.9 MBD, -263 KBD m/m, +380 KBD y/y. ND (-135 KBD) witnessed the largest production decline at the state level, followed by TX (-65 KBD).
  • 2022 Avg L-48 Production: 9.7 MBD, +603 KBD.
  • TX and NM Dec Oil Production: TX (largest US oil producer, by far, with over 50% of L-48 production) Dec production of ~5.15 MBD was down 65 KBD m/m and up 156 KBD y/y. NM (3rd largest producer behind TX, GOM ~1.78 MBD) production of~1.77 MBD was up 46 KBD m/m and 405 KBD y/y.
  • 2022 US Oil Production vs. Beginning of Last Year Forecast: 2022 US oil production of 11.88 MBD landed near the January 2022 CY’22 forecast of 11.8 MBD – not too shabby.
  • EIA 2023 US Oil Production Forecast (Feb STEO): 12.49 MBD, +610 KBD y/y.  The EIA is projecting monthly production of ~12.4-12.5 MBD through October and Nov/Dec production of ~12.6 MBD. The Jan/Feb projections, at this stage, look ambitious and we’ll see about the rest of the year.  EIA 2023 projection in the event of flat commodity prices from current levels = no way; EIA projections in the event of higher commodity prices propelled, in part, by a China pent-up-demand surge = doable. The current 2024 average production estimate is 12.65 MBD (Jan-Oct ~12.6-12.66, Nov/Dec ~12.75-12.8 MBD), flattish with exit-2022 and up 160 KBD y/y.


Nat Gas

  • Dec US Nat Gas Production: 119.9 BCFD, – 2.8 BCFD m/m +1.2 BCFD y/y.
  • Dec Dry Gas Production: ~99 BCFD, – 1 BCFD m/m, +1 BCFD y/y.
  • 2022 Avg Dry Gas Production:  ~98.1 BCFD, +3.6 BCFD.
  • 2022 US Dry Gas Production vs. Beginning of Last Year Forecast: 2022 avg dry gas production of ~98.1 BCFD was ~2 BCFD higher than forecast in Jan of last year.
  • 2023 Dry Gas Production Forecast (Feb STEO): ~100.3 BCFD, +2.2 BCFD y/y. 2024E ~101.7 BCFD


Refining Observations:  Good news for gasoline, as apparent demand is growing and inventories are declining.   Gasoline cracks have responded, too, jumping 17% on average this week.  We’re still in the camp that demand can’t run unfettered, given lower available US capacity overall and inventories at multi-year lows.


The quality of government data continues to be questioned.  On its conference call, DINO management stated that “the EIA data is confusing…on the product side, we’re seeing strong demand in our markets.  On the gas[oline] side, I would say we’re seeing demand that’s 98% of what our 2019 peaks were…On the diesel side, we’re seeing demand maybe 10% higher than what we saw in 2019 in the areas we operate in.”


On a positive note for capacity, CVE completed its acquisition of BP’s 50% stake in the Toledo Refinery, which was impacted by a fire last September.  The 160KB/d refinery has been shuttered since, but CVE is planning to return the facility to full production by May.


Mea Culpa – Thrive Conference:  Someone very close to the DEP team rightfully pointed out that a comment I wrote from last week’s note seemed too harsh.  Notably, the section on Attendee Feedback.  As a result, I went back and reread what my comments, and yes, I see our critic’s point.  That is, the note highlighted critical feedback vs. not properly emphasizing the positive feedback and thanking companies for their support.  Therefore, I apologize.  The truth is I thought Thrive 2023 went great and was thrilled with the tremendous turnout and support.  You have no idea how psyched the DEP team was post-conference.  Moreover, the substantial majority of feedback was extremely positive, so absolutely no complaints here.  Yet, right or wrong, this team sometimes tries to be perfectionists, thus we are always looking for ways to improve. This means we thrive on critical feedback (no pun intended).  Of course, after the whiff with last week’s note, I am once again reminded by the great oracle and philosopher, Hannah Montana that “everybody makes mistakes, everybody has those days”.  Such wisdom provides comfort in troubled time, serving as a reminder that I am not the only one who blows it occasionally.  Having said that, the DEP team did our initial internal debrief and these are some of the ideas/changes we may make for 2024.


  1. We will make the opening reception a bit more family oriented.  Therefore, we will allocate two hours to kids batting practice and one hour towards adults.
  2. We will eliminate the cash bar at the opening reception and DEP will eat that cost.  Making guests pay is cheesy.
  3. We will open a concession stand each day so people who don’t go up to the suite level can buy something as opposed to being forced to eat free granola bars.
  4. We will likely end our panels early by 30 minutes on Day 1 and an hour on Day 2.  This gives a bit more time for networking at the bar, particularly given so many company folks like to go offsite for company-sponsored dinners.
  5. We will do fireworks, if allowed, at the end of the opening night reception.  This way the kids can see them.
  6. We may have more than one BBQ cooking team, although the winner of our Permian BBQ Cook-Off will get the spot for free.
  7. We had some concerns about logo placements and the size of the logos.  There’s not much we can do about the logos on the big screen.  We give a bit more time on the screen to larger sponsors, but given the volume of sponsors, we can’t add too much additional time for each logo display.  As for indoor signage, we will look to add a bit more.
  8. We will likely tweak lower the price of outdoor displays, but tweak higher the price of suites.  Two reasons: (1) supply/demand on the suites and (2) most people stay inside, thus outdoor booths don’t get as much traffic, so it’s not fair to charge too much.  Nothing dramatic with the change, but an effort to remain revenue neutral.
  9. Attendance.  Funny thing is we had some initial feedback that attendance was too high.  We wrote about that last week and then we had a bunch of feedback that attendance felt just right. Honestly, the feedback was quite balanced.  Not sure what to do other than do a better job monitoring conference walk-in’s (next bullet).
  10. Conference walk-in’s.  One reason attendance was higher is people showed up during the conference and registered as walk-in’s (about 300+ people).  According to our third party working the desk, most walk-in’s claimed they were a sponsoring company or guest of a sponsor.  As we used a third party, they didn’t push back too much.  What does this mean?  More people who the DEP team couldn’t vet were able to gain entry.  That irks us a bit as we don’t want to become OTC. To guard against people sneaking or walking in next year, we will have someone from DEP at the desk with a credit card machine.  If someone is truly a client or a sponsor with remaining unused passes, we will assess them, show grace and allow them in.  If they are not entitled to passes, it will be a rich price to gain entry.  Yes, those who are “tire kickers” will be offended and will walk away.  We can live with that.


Q4 Earnings Observations:



  • Production of 524 MMBOE/d (50% liquids), up 1.4% sequentially.
  • Full-year 2022 production of 510 MMBOE/d (51% liquids).
  • Q4 capex of $358mm.
  • 2023 capex guide of $2.15-$2.35B, up 23% from 2022, using a 10 rig program: Permian 3, Montney 4, Bakken/Uinta 2, and Anadarko 1.
  • US spend expected $1.55-$1.85B, up from ~$1.5B in 2022 ($850-950mm Permian, $500-600mm Bakken/Uinta, $200-300mm Anadarko.
  • Montney $500-600mm in 2023 vs $334mm 2022.
  • OVV plans $61mm in base dividends in Q1, as well as $238mm in share repurchases.



  • Production of 1,230 MMBOE/d (54% oil), up 4.2% sequentially.
  • Q4 Permian production of 565 MMBOE/d.
  • 2022 production of 1,159 MMBOE/d (53% oil). 575 MMBOE/d Permian.
  • Guide for 1,180 MMBOE/d in 2023, with Permian +62, Other Intl. +12, and declines in the Rockies, Algeria (change in PSC), and GoM.
  • Oil and gas capex of $1.2B in Q4.
  • Q4 FCF of $2.6B, with $562mm of share repurchases.
  • Capex of $4.5B overall, $3.8B O&G.
  • 2023 capex guide of $5.4-$6.2B, $4.3-$4.7B O&G.
  • Expected Permian spend of $2.3-$2.6B, Rockies $0.7-$0.8B.
  • Oxy running 26 gross rigs:  23 Permian, 3 PRB/DJ.



  • Production of 2.2 Bcfe/d (69% natural gas), up >3% sequentially.
  • Full-year 2022 production of 2.12 Bcfe/d (69% natural gas).
  • 2023 guide is for flat production, 2.12-2.16 Bcfe/d.
  • Q4 capex of $109mm brings full-year 2022 to $492mm.
  • 2023 capex guided to $570-615mm.
  • Planned TILs in 2023: 31 SW PA Wet, 24 SW PA Dry, 3 SW PA Super-Rich, and 3 NE PA Dry for a total of 61 vs 55 in 2022.
  • RRC forecasts its FCF breakeven at <$1.50/MMBtu, and will generate single-digit FCF yields at $2.50/mcf.



  • Production of 315 Mmcfe/d (34% liquids), up 5.4% sequentially.
  • Full-year production of 270 Mmcfe/d (28% liquids).
  • 2023 production guided to 325-345 Mmcfe/d (40% liquids).
  • Capex of $102.7 brings full year 2022 to $327.5mm.
  • 2023 capex guided to $450-475mm—maintaining a 2-rig program, but focusing on oilier acreage given natural-gas prices.
  • Elected to DUC eight Webb County wells awaiting higher gas prices.
  • Seeing costs plateau, and expect some selective cost deflation in 2H.



  • Revs = $73.8M vs. $71.6M in Q3
  • Adjusted EBITDA = $10.7M
  • Volumes increased 6% q/q to 1.175M tons
  • Bought out Clearlake’s 11% ownership stake for implied price of ~$1.70/share
  • Stock trades at ~$2/share as of Friday.
  • Guided Q1 volumes in the 1.0 to 1.2M range.
  • Contribution margin guided to low double digits
  • 2023 capex = $20-25M vs. $19M in 2022.
  • SND will incur some capex with the reactivation of its Blair mine, noting it has a contract to support the mine.  Not clear what the committed volumes are and/or price of the mine, but would suspect the mine will ultimately sell north of 1M tons/year once fully reactivated.



  • Revs = $162M with adjusted EBITDA = $15M.
  • Generated $83M in FCF in 2022
  • Used 50% of FCF for share repurchases (bought back preferred stock).
  • Previously announced two 5-year contracts.  These contracts represent market share wins with the customer.
  • Debt = $132M, down $43M from YE’21.
  • Full year 2023 revenue guidance calls for revs = $630-$650M (vs. $697M in 2022).
  • Full year 2023 EBITDA guidance = $85-$95M (vs. $113M in 2022).
  • 2023 capex = $25-$30M.
  • FCF guided to $43M-$58M.
  • The  y/y guidance decline is largely the result of the wind-down of construction activity associated with the Coastal GasLink pipeline project which contributed $36M of revs in 2022.
  • Moreover, adjusted EBITDA guidance is burdened by $13M of estimated de-mob costs.
  • CVEO also completed the sale of its US offshore accommodations business in Q3’22.



  • Throughput of 628 MB/d (~93% utilization), down 2.7% sequentially.
  • Gross margin of $23.47/Bbl, up from $8.70 Q4 ’21.
  • Refining EBITDA of $864mm, up from $25mm in the year-ago period.
  • Total company adjusted EBITDA of $1B, nearly 8x the prior year.
  • Other segment EBITDA:  Lubricants $75mm, Marketing $23mm, and Renewables -$7mm.
  • Renewables sales volumes of 54mm gallons in Q4 were impacted by unplanned downtime.  DINO expects normalized run rates by 2H 2023.
  • Regarding the EIA: “the EIA data is confusing…on the product side, we’re seeing strong demand in our markets.  On the gas[oline] side, I would say we’re seeing demand that’s 98% of what our 2019 peaks were…On the diesel side, we’re seeing demand maybe 10% higher than what we saw in 2019 in the areas we operate in.”



  • Throughput of 280 MB/d (85% utilization), with unplanned downtime at the Big Spring refinery during Q4.
  • Q1 guide of 250-260 MB/d.
  • Tyler TX turnaround is complete, and management has no planned downtime until late 2024.
  • Q4 refining margin of $15.68/Bbl in Q4.  $18.22/Bbl full year.
  • Adjusted EBITDA of $221mm, compared to $33mm in Q4 ’21.
  • Dividend raised 5% to $0.22/share (~3.3% annualized yield).
  • Management expects cost-savings of $30-40mm in 2023, with annual run rates of $90-100mm once all initiatives are complete.
  • Capex in 2023 budgeted at $351mm (58% refining) vs $343 for FY ’22.


Product Inventory, Demand, and Margin Charts

(Shaded areas show the 5-year range 2017-2021)



Source for Inventory and Demand Charts:  Energy Information Administration, Bloomberg, LP





Source for Margin Charts:  Bloomberg, LP



John M. Daniel

Managing Partner, Founder

Daniel Energy Partners, LLC




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Daniel Energy Partners is pleased to announce the publication of its first market research note. In this note, we reached out to executives across the oil service and E&P sectors to gauge leading edge sentiment.

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