DEP Update: We will be participating at the Bank of America Energy Conference in Miami this week.  Rough job.  Next up, we’ll be attending the Piper Sandler Energy & Power Winter Symposium in NYC on December 1st.  On December 6th we will sit on a panel at the CapitalOne Energy Conference in Houston.  If you will be at any of those events, let us know.  Would love to catch up.  After the conference circuit, the team heads to Dallas for meetings on December 6-7th followed by the DEP Christmas Party in Houston on December 8th.   Finally, we’ll head to Denver and OKC the week of December 12th.  In between, we will squeeze in a few company updates and solicit folks for 2023 renewals as well as our sponsorships for our Thrive Energy Conference.


DEP Podcast: On November 7th Geoff, Sean and Bill sat down in the DEP offices to discuss Q3 earnings results and company commentary. Discussion focused on activity, M&A, recent E&P surveys and thoughts on the remainder of this year and 2023. Take a listen.  Give us feedback – good or bad.


Subscribe wherever you like to listen to Podcasts.  More podcasts will be coming, including two we recorded earlier this week while in Midland.  If you are willing to sit down and let us pepper you with questions, we’d love to have that chance.


Permian Basin Recap:  This week we returned to the Permian for company updates, field visits and our quarterly Midland reception.  Mood in the Permian remains quite strong, notwithstanding several isolated reports of expected Q4 seasonal/year-end effects.  Namely, a few companies expect some holiday-related softness with one frac company echoing PTEN’s Q3 comments that frac crews are bumping up against the drilling rig.  Consequently, a bit of short-term competitiveness for spot market work according to this contact.  This is not a consensus view, however, and is likely customer nuanced.  For those willing to see the forest through the trees, the more important picture is the strength of the market next year.  Nearly every single company reports full calendars to start 2023.  In fact, industry friends consistently claimed current visibility is the best of their careers.  For example, on the ProFrac (ACDC) Q3 earnings call this week, management noted the current environment is the best in the last 14 years.  From an industry leader, such a statement on a public call carries weight.  Other Midland executives with similar work history as the ACDC team concurred.  But the real enchilada came from a breakfast meeting with one of the Noah’s of the frac market who offered a similar view, stating that today’s visibility is the best in his ~40-year career.  Hard to dismiss this type of optimism and sufficient reason not to worry about any potential short-term flatness associated with Q4.


As with all trips, we discussed the topic of service pricing with our OFS friends.  There is some uncertainty as to how much pricing power still exists today.  Namely, activity levels, per the BKR rig count as well as our frac crew counts, appear to be leveling off, an environment where one would think pricing would begin to level off as well.  The BKR rig count, for instance, stands at 758 rigs, only ~20 rigs or 2.5% higher than the average in July.  OFS contacts contend inflationary pressures as well as robust demand together should allow for at least another bite at the apple as Permian contacts in well servicing and coiled tubing both see ~10% price increase attempts coming in early Q1.  An OCTG player noted a similar magnitude of expected pricing while price commentary on the NINE and ACDC calls would suggest further efforts to raise rates should be expected.


As loyal readers know, our research observations are largely centered on the U.S. land market.  Our research philosophy, to date, states if we can’t drive there and if there’s no Dairy Queen, we don’t want to cover it.  So, in keeping with that theme, we have another observation this week on the state of frac equipment.  Namely, the concept of newbuilds vs. attrition.  On this point, we are normally nervous Nellies as history clearly shows that when the OFS sector reaches newbuild economics, the desire to grow EBITDA and/or take care of one’s customer has ultimately resulted in capital destruction via too much building followed by a cyclical slowdown.  Yet, this cycle, industry leaders have fervently called out the attrition thesis as a reason to assuage overbuilding fears. Some companies claim the industry could see 5-10% attrition each year, more than enough to offset current newbuild plans.  This week, in fact, ProFrac proclaimed the industry has normally has ~15% of its equipment down for maintenance on any given day.  To put this into math, if the active fleet is 270-275 fleets and if attrition is 5-10%, that implies ~15-25 fleets need to go away each year.  As for newbuilds/reactivations, our working tally is north of 20 fleets over the next ~4-5 quarters.  Assuming our numbers are in the ballpark, one can therefore conclude the combination of attrition and higher maintenance as well as expected growing demand for more frac services should offset newbuild fears, thus keeping the U.S. frac market tight throughout 2023.  Based on what we know today, we concur, although we do note some companies still show newbuilds as incremental active fleets.


What is interesting with respect to the maintenance claims, however, is an observation from our Midland trip.  Specifically, we drove around yards in the Greenwood area where we found further validation of the attrition/maintenance thesis.  For example, as we did our yard drive-by’s, we came across two different maintenance shops which we had never heard of or seen before (typically we spy on Midland/Odessa yards, and we know where those maintenance shops are).  In the two Greenwood yards were multiple frac trailers which appeared to be waiting for maintenance.  This equipment included capacity from name-brand frac companies – we saw red, green, silver and fluorescent yellow.  Quick guess is the collective number of units between the two yards likely totaled upwards of 20 trailers.  So, not a ton of units, but for a firm who spends a lot of time on the road and likes to think we know where most of the rebuild/repair shops are, these two were new to us.  Further, these weren’t name brand national maintenance shops and the fact that name brand frac companies had equipment at these shops seemed somewhat revealing to us.  Further, based on the positioning of the equipment, it appears some of the units have been sitting there for some time.  Point being – the R&M burdens on the domestic frac fleets are real and visible, the volume of units down for repair on any given day remains significant, supply chain problems compound this issue which taken all together means a bullish frac market in 2023, particularly if E&P companies flex activity up.


Infinity Water Solutions Tour (Authored by Bill Austin):  This week we drove over to the Infinity Water Solutions’ Mills Ranch facility which is located just east of Loving, NM and west of a dozen food trucks and a bunch of dead coyotes, hoping there’s no correlation.  Infinity is focused on water infrastructure and recycling in the Permian Basin. Now fully operational, the Mills Ranch facility will be one of the largest produced water recycling facilities in the Northern Delaware Basin with processing capacity ~100,000 barrels per day and recycled water inventory or staging capacity of 3 million barrels. The company is building infrastructure for a recycling network in the northern Delaware to alleviate a surge volume of produced water.  Presently, Infinity has two facilities with another two contemplated near-term and potentially a total of seven facilities as further development is expected.  As E&P companies shift from single-well to pad drilling, significant additional permanent water infrastructure is required to both efficiently and safely transport higher, more concentrated volumes of produced water. This is not a new problem, nor is it new information for anyone tied to oil and gas.  Numerous companies such Aris Water Solutions (ARIS), Select Energy Services (WTTR) as well as others, have been building water transportation systems and increasing service capability for a while. And SWDs have been filling the need to dispose of produced water.  But recycled water volumes continue to see material demand increases as producers need to increase more “environmentally friendly” production. Further, the need to develop/treat and find reuse opportunities is top-of-mind.  Case in point, look at this week’s partnership announcement between ARIS, COP and CVX.  Presumably more will follow as the increasing appetite for redelivered/treated water for completions has opened the door for more capacity necessary in the basin.   The good news for companies like Infinity is the ability to secure long-term contracts, in many cases with high quality customers.  With respect to the Mills Ranch facility, Infinity already has at least one large E&P operator as a client.  More are expected.  For instance, a quality E&P operator also attended our tour, conducting its facility due diligence.


New Electric Tractor Tour and Ride (Authored by Bill Austin):  Our visit to Midland included a site tour of the Detmar Logistics facility in order to see its new CNG and Electric tractors.  By way of background, Detmar currently owns and operates ~120 traditional diesel trucks and hauls over 250 loads of sand per day. The company has placed an initial order of 60 Hyliion Hybrid Electric units in 1H 2023.  The company also has pre-orders for 300 Hypertruck ERX systems (non-binding) which helps them with first to market and preferred pricing.  The Hypertruck ERX is an electric powertrain that is recharged by an onboard natural gas generator for commercial trucks, the powertrain recharges itself by en-route charging.  Now this is not a “fully electric” truck but a hybrid.  Detmar is continuing more testing on the ERX, but the first locked in orders (24 trucks) should arrive in 2024.  It is our understanding that the advertised range for the Hybrid Electric truck is 600 miles while the Hypertruck ERX will have a range of 1,000 miles.


What does this mean? The aim for Detmar is to provide lower operating costs, emissions reductions, and superior performance relative to traditional diesel trucks. With diesel costs high, the effective cost to fuel the ERX is far less than a traditional diesel commercial truck with more fixed pricing and less volatility.  The tour included a ride in the cab, which was impressive.  Plenty of pickup with an empty sand trailer.  No gear shifting and near-total silence in the cabin as well as next to the tractor while it was running.  Then the team showed us this pretty cool video: Hyliion Drag Race  [watch from 2:44-3:30] vs a standard diesel truck to 60 mph (fully loaded at 50,000 lbs.) which we thought as petty impressive. As always, companies in the industry look for efficiency gains to reduce costs through technology and the Hyliion truck seemingly fits that bill.


E&P Observations (Authored by Geoff Jay):  We spent this week listening to earnings calls and meeting with folks in Houston.  Inflation is on everyone’s mind.  Permian Resources believes that the “lion’s share” is “behind us.”  Other companies we talked to share that optimism, seeing opportunities for casing, in particular, to come down as steel prices continue to move lower.  Others feel that prices don’t reflect the decrease in oil prices over the past few months, with one company saying it doesn’t sit well to pay the same prices they paid at $120/Bbl when oil is under $90.  On the surface, this makes sense; however, one must also then consider what OFS prices should be when oil goes from $20/bbl to $90/bbl.  It took nearly two years for the OFS sector to return to pre-Covid pricing and some sectors still aren’t quite there.  The reality is supply/demand drives OFS pricing and the only way for E&P companies to get price relief is to cut activity in order to create a supply/demand imbalance in their favor.


Of course, none of us likes to pay more than we have to, but are we really close to the breaking point?  Sure, well costs are up, but not many producers have guided activity lower and some still report well IRR’s near/over 100%.  One company we met with this week admitted—grudgingly—that rig rates likely had some room to run, given their smaller percentage of well costs.


The biggest frustration for the E&Ps we met with was their stock price.  A lot of people mused about what it will take to move the needle with investors.  Some wondered aloud if variable dividends were a good thing, worrying that investors might punish sequential declines necessitated by lower commodity prices.  Another management team was seemingly salivating at recent share weakness, seeing it as an opportunity for their buyback authorization.  We continue to think it’s a matter of duration:  Eventually the free-cash-flow generation can’t be ignored.


In terms of M&A, we heard that lots of deals are getting shopped, and some are better than others.  We asked if there were still deals to be done at <3x cash flow out there.  The answer was “yes,” but one management team said the important question is why the multiple is so low.  “There’s a seller as well as a buyer,” they cautioned.


Refining Observations:  Both HF Sinclair (DINO) and Delek (DK) reported this week, largely echoing the sentiments of their peers who have already released earnings.  Everyone seems to expect higher-than-normal margins going forward, given tight capacity.  DINO called out high run rates as a potential problem, given that the stress on the system will lead to more maintenance, both planned and unplanned going forward, adding to the stresses of lower capacity in the US.


PSX held an analyst day, announcing an increase to its share-repurchase authorization of $5B (total authorization outstanding is now $6.8B).  The company plans to return an additional $10-12B to shareholders from now until YE 2024 through a mix of dividends and share buybacks.  PSX also intends to increase midcycle EBITDA by $3B over the next three years, +1B uplift from taking in DCP Midstream, and the rest by increasing its refining-capacity availability, upping margin capture, and cost savings.


BKR U.S. Land Rig Count / DEP Rig Count Forecast:  +4 rigs w/w to 758 rigs.  In keeping with our comments from prior notes, we are tweaking our U.S. land rig count forecast.  We summarize the changes in the table below.  Key point is there is no parting of the Red Sea here.  E&P commentary regarding 2023 plans was somewhat light during Q3 earnings as most simply opted to push the formal guidance until Q4 earnings or once budgets are finalized.  Our survey from weeks ago indicated a flattish count, but we note our survey represented only ~50% of the U.S. rig count.  Comments from the land drillers would suggest we were too light as all drillers are guiding higher activity (look at prior notes for details).  To keep it simple and to refrain from sticking our neck out too far, we essentially split the difference from our survey, which would appear to be too conservative vs. our prior model which screens even more optimistic than the land driller commentary.  As a result, we now model the U.S. land rig count gaining ~70 rigs over the next 4-5 quarters (i.e., we assume a 2023 exit rate in the ~830ish vicinity).

Q3 Earnings Observations.


  • Revs = $697M, +18% q/q.
  • Adjusted EBITDA = $267M, +23% q/q.  Excludes Flotek.
  • Adjusted EBITDA/fleet = $34.5M.
  • 31 Active Fleets.
  • ACDC deployed its first electric fleet in Q4 and added 7 fleets from USWS, thus the company will finish the year with 39 active fleets.
  • Company sees active fleet count at 44 fleets in 1H’23 which would include the addition of four extra electric fleets, thus ACDC is adding fleets, similar to other large peers.
  • 2022 Capex = $330-$350M.
    • Includes $50M for Tier 4 DGB upgrades, $75M for three electric fleets and $45M for the new sand mine in Lamesa
    • Will take delivery of 10-20 Tier 4 DGB engines per month.
  • Company sees the largest top line opportunity will be vertical integration.
  • Pricing levels remain constructive in Q4 and all of 2023.
  • Management claims current calendar is the strongest in their 14-year career.
  • Post USWS deal, ACDC has $650M in net debt.
  • ACDC did note November/December activity levels are opaque, but comments seem to suggest October was quite strong.



  • Aris entered strategic agreement with Chevron and Conoco to treat produced water for reuse. Stay tuned as these companies combine their intellectual horsepower to accelerate technology around reuse of produced water.
  • Completed acquisition of Water Standard Management (US), Inc. (“Water Standard”) which support the beneficial reuse of produced water business.
  • Total water volumes over 1.4mm bbls/day +14% q/q.
  • Recycled produced water volumes of ~345k bbls/d +165% y/y and +16% q/q.
  • Since beginning of 2022, chemical costs are up 10-20% and contract labor rates are up 25%/ hour.
  • EBITDA $39M, +6% q/q.  Expect Q4 EBITDA in the range of $39-41M.
  • Capex $49M for 3Q and $97M YTD.
  • Expect Q4 capex to be between $45-53M.



  • Revs = $167M vs. $142M in Q2
  • Adjusted EBITDA = $32.6M vs. $18.9M in Q2
  • Q3 results beat company guidance.
  • Q4 revenue guided to flat q/q with growth in Q1 expected.
  • Interesting observation: NINE highlighted significant price traction from the depths of the 2020 downturn (i.e., CT rates +61%, wireline rev/stage +28%, Cementing +58%).  Yet, NINE consolidated EBITDA margins remain around ~20%.  Implication: pricing still has not moved enough as margins for capital intensive and/or cyclical businesses such as OFS should be higher at this point in the cycle.
  • Operational anecdotes:
    • Completed 1,130 cementing jobs, -2% q/q
    • Cementing revenue/day increased 18% q/q with total cementing revs = $64M.
    • Completed 5,701 wireline stages, +5% q/q
    • Wireline revenue/stage +6% q/q with total wireline revenue = $29M.
    • Completion tool stages = 34,214 stages, +17% q/q.  Revs = $41M, +21% q/q
    • Coiled tubing days +10% q/q with utilization = 54%
    • CT revenue = $33.4M, +21% q/q.
  • Cash = $21M.
  • Reduced debt by $13M in Q3.  Total debt now = $335M



  • Revs = $334M, +7% q/q.
  • Adjusted EBITDA = $48M vs. $51M in Q2.
  • Q3 results burdened by $17M of start-up/commissioning costs.
  • Q4 revs guided to $325M-$350M with adjusted EBITDA margins = 20%.
  • Notable in the release and transcript is a litany of new awards in various international domains.
  • Hard part, however, is to quantify the value of these awards, but the sheer number cited by the company screens impressive.
  • ~70% of XPRO revs tied to D&C activity and ~70% tied to Offshore.
  • ~80% of revs tied to International
  • Cash = $153M with no debt.
  • Q3 capex = $19M with Q4 capex guided to $30-$40M.
  • 2022 capex = $81-$91M.



  • Revs = $222M, +20% q/q
  • Adjusted EBITDA = $37M, +113% q/q.
  • Adjusted EBITDA margin = 16.7%
  • Impressive operating incrementals of 53%.
  • Cash = $41M; Total Debt = $312M.
  • Product/Service line anecdotes:
    • Directional drilling day charges +5% q/q
    • Fishing activity up 8% q/q
    • Accommodation rental days +5% q/q
    • Pressure pumping revenue +27% q/q (includes frac, cementing, acidizing)
    • BOP rental days +9% q/q
    • Tubular rental days +20% q/q
    • Coiled tubing days +19% q/q
  • Pricing characterized as up 5-10% q/q across most product lines.
  • Running two HZ spreads and one small spread
  • 2022 capex guided to $30-35M.
  • 2023 capex likely in the 5-7% of revenue (perhaps ~$50-70M? – our guess).
  • Q4 revs likely flat to slightly higher with Adjusted EBITDA margins in the 15-17%.



  • Revs = $182M, +6% q/q
  • Adjusted EBITDA = $18M, +15% q/q.
  • Orders of $198M; Q3 book-to-bill of 1.09x
  • Free cash flow = $17M.
  • Q3 revs driven by Completions segment (+9% q/q) and to a lesser extent, Production segment (+14% q/q).
  • Q4 guidance: Revs = $180-$190M with EBITDA = $16-$18M.
  • 2022 capex = $10M or less.
  • FET called out expected improvements with its Radiator business (for Frac) while International is 30-40% of FET’s total revs and the company’s recent ADIPEC visit was characterized as positive.  That was feedback from other non-FET DEP contacts who shared how upbeat and well-attend the conference was.
  • Path to deleveraging apparent as FET’s debt has a conversion feature.  Roughly 48% of the $257M notes can convert to common stock once the 20-day VWAP is above $30/share.  Stock closed on Friday at $30.11.  Assuming this happens, FET share count goes to ~10.6M while net debt becomes ~$125M.  Assuming Q4’22 is a run-rate for 2023, annualized EBITDA of $70M and reduced y/y interest expense, one would assume ’23 FCF is improved vis-à-vis 2H’22 FCF of ~$30-$40M, thus all else being equal, net debt further improves.
  • No stock opinion here as that’s not DEP’s business model, but FET has ~$8M remaining on its share repo plan.  One would think this could be used to support repurchases short-term to provide stock support in the hopes of quickly achieving the 20-day VWAP above $30/share.



  • Revenue $184.5M +8% q/q and EBITDA $62.7M +13% q/q.
  • US Product Share market remained strong during the quarter at 38.5%.
  • Capex $7.1M for the quarter and $21.2M YTD.
  • Paid quarterly dividend $0.11/share and increased cash balance to $321M.
  • 3Q included ~ $1M of professional and legal expenses related to evaluation of growth opportunities.
  • Customers expected to add 25 rigs from mid-Sept to year end ‘22, most of which are in back half of quarter.
  • Recent customer conversations indicate additional rigs in early 2023.
  • Both year end and early 23’ activity is being driven by public operators.
  • See some year-end related slowdown in the rental business due to holidays but expect that to rebound in early ‘23.
  • 4Q expect avg rigs followed to be up in mid-single digits %
  • Comments on supply chain, WHD said transit times and overseas freight cost improving.
  • Mid-East Facility commercialization is still on for 2024.



  • Production of 391 MBOE/d (57% oil), up ~2.8% sequentially.
  • Capex of $491mm brings YTD to $1.4B, 72% of new full-year guide of $1.9B, up 4% from prior guide.
  • Spending on Firebird assets will account for $30-45mm of the ~$80mm increase.
  • For 2023, guessing ~10% increase over pre-Firebird $1.9B levels, with another $250mm for Firebird assets.
  • Generated >$1.16B of FCF in Q3.
  • Repurchased 3.9mm shares for $472mm.  $1.2B of $4B authorization used so far.
  • Base dividend of $0.75/share (1.9% yield) and variable dividends of $1.51/share.
  • Firebird acquisition expected to close end of November.  Rig count there will drop from 3 to 1.



  • Production of 92 MBOE/d (53% oil). Not comparable with prior periods given September 1 merger close.
  • Full-year 2023 production guided to 150-165 (MBOE/d), growing 10% from Q4 ’22 to Q4 ’23.
  • Capex of $199mm, brings YTD to $454, with guidance of $300-325mm for Q4.
  • 2023 capex seen at $1.15-$1.35B, assuming 15% inflation from 2022.
  • Management feels that the “lion’s share” of inflation is “behind us at this point.”
  • Going to 6-rig program from 7-rig program.  Was recently at 8 rigs.
  • FCF in Q3 of $100mm, $159mm ex merger costs.
  • Plans to return 50% of FCF to shareholders beginning in Q1 2023 and initiated inaugural dividend of $0.05/share (~1.8% yield).  Returns above base dividend will be a combo of special dividends and share repurchases.



  • Production of 516 MBOE/d (26% oil, 52% liquids), up 3.2% sequentially.
  • Full-year guide raised by 5 MBOE/d to 505-515 MBOE/d.
  • Capex of $511mm brings YTD of $1,473mm, or 82% of full-year guidance of $1.8B (now at top of old range).
  • FCF of $437mm for the quarter.
  • Returning 50% of after-base-dividend FCF through buybacks.
  • Share repurchases of $325mm for Q3.
  • $300mm of debt reduction for the quarter.
  • OVV has contracted all the services it needs for its 2023 program.
  • Noted it switched frac providers in the Permian and Mid-Con on two crews.



  • Production of 1,179 MBOE/d (53% oil), up 2.5% sequentially.
  • Management expects 2023 volumes to be flat.
  • O&G Capex of $1B brings YTD to 81% of full-year guidance.
  • “We really don’t know what 2023 is going to look like from an inflation standpoint.”
  • OXY is running 13 net rigs:  11 Permian, 2 DJ.
  • Q3 FCF (pre working capital) of $3.6B.
  • Increased quarterly dividend to $0.13/share (<1% annualized yield).
  • Secured 2 locations for CCUS hubs:  1. 65K acres in SE TX with up to 1.3B tons of capacity (20 direct-air captures (DACs)) and 2. A lease with King Ranch in TX for 30 DACs.



  • Production of 79 MBOE/d (57% oil), up ~9% sequentially.
  • Full-year production guidance of 74.5-78 MBOE/d, up from 73-77 MBOE/d previously.
  • Capex of $156mm brings YTD to 77% of new 2022 guidance of $460-510mm.
  • Operators drilling longer laterals, bringing AFE’s to $8.6mm on average for Q3.
  • On a normalized lateral-length basis, costs rose 5% from Q2.  “There is leading-edge inflation.”
  • FCF of $110.6mm.  Expect $500mm of FCF for 2022.
  • Will provide 2023 guidance on Q4 call.
  • Dividend increased 20% to $0.30/share (3.2% annual yield).



  • Throughput of 685 MB/d (>100% utilization), up 3% sequentially.
  • Adjusted EBITDA of $1.5B, down 19% from Q2.
  • Margin per Bbl of $31.47 vs $36.36 last quarter.
  • Returned $951mm to shareholders during Q3 ($866mm of share repurchases).
  • New $1B share repurchase authorization in September.
  • Management sees a “better for longer” scenario where refining margins are above mid-cycle for the foreseeable future.
  • Management also indicated that high run rates will ultimately lead to additional maintenance outages—both planned and unplanned.



  • Throughput of ~300 MB/d (99% utilization), up 1.6% sequentially.
  • Guidance of 280-290 MB/d for Q4.
  • Adjusted EBITDA of $136mm, down from $518mm in Q2.
  • Refining margin of $17.07 per Bbl vs ~$30 last quarter.
  • Operating Cost of $6.10/Bbl for Q3—management expects lower costs in Q4 due to lower natural-gas and electricity prices, as well as lower utilization.
  • Seeing same-store fuel sales up 7% from last year.
  • Share repurchases of $40mm during Q3.  Expect to buy in $75-100mm during Q4.
  • DK raised its quarterly dividend by 5% to $0.21/share (~2.5% annual yield).



Product Inventory, Demand, and Margin Charts

(Shaded areas show the 5-year range)



Source for Inventory and Demand Charts:  Energy Information Administration





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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