DEP Update:  Dividing and conquering again this week as half the team heads to Midland while the other half is conducting E&P meetings in Houston.  Our Midland reception is on Wednesday, so email us if you would like to swing by.  Lastly, we are attaching an updated THRIVE agenda.  This incorporates a few additional confirmed speakers as well as corrects a few of our typos.


DEP Podcast:  We are finally kicking off our DEP podcast with a bit more vigor, hoping to issue content at least twice a month.  This past week, we released another In-Basin Observations (remote version) featuring Matt Wilks from ProFrac Services.  We will be taking our mobile studio to Midland this week as we head to New Mexico for a site tour of a new water treatment facility.  For any Midland friends open to doing a podcast with the DEP team, let us know.  We promise to be gentle.  In the meantime, please use the link below to take a listen on whatever podcast application you prefer. Let us know your thoughts and we’ll keep trying to publish every other week.


Mexico Castings Plant Recap (Authored by Bill Austin): This week the folks at POK were kind enough to invite DEP down to Guadalajara, Mexico to take a first-hand look at their brand new Acatlán castings facility. The visit agenda included a tour of their existing Santa Anita and Acatlán facilities, industry presentations highlighted by Ildefonso Guajardo Villareal (Mexico’s Secretary of Economy, lead negotiator of the USMCA, fka NAFTA), along with several networking discussions.


For the uninitiated, POK produces castings and precision machined products used by the oil and gas, mining, and sugar processing industries. POK has been owned by Nucor Steel (NYSE:NUE) since 2018 and is focused on producing high-quality, value-added castings targeting niche markets. POK employs 450+ people at its current Guadalajara production facility and will likely grow that to 600 people with the capability of producing more than 5,000 tons of castings per year when the Acatlán facility is fully operational. The current facility sits in Guadalajara on six acres of land and is maxed out of capacity with low volume and high mix products for a variety of industries/customers. The new facility will allow them to concentrate on larger volumes of products with lower mix through standardization and greater automation.


The event included a wide variety of customers and suppliers from numerous industries.  Oil and gas, aerospace, pumps and valves, mining and agricultural equipment (to name a few) both in the US and Mexico were all well represented. Castings are a key oilfield equipment component (as evidenced by the contingent of OFS capital equipment providers in attendance). Think, handling tools for rigs, power swivel components, BOP components, drill bits, coil tubing equipment, mud pump components, ROV Components, frac pump power-ends (conrods and bearing housings) amongst others.  In the case of power-end components, POK is presently producing components for about 100 power ends per month.  The new Acatlán facility will double this capacity, a potential start in solving some industry supply chain woes.  What is interesting is a comment about foundry headcount and utilization.  According to contacts, U.S. foundries are running at 50-60% capacity.  The low utilization does not reflect demand, but rather an inability to get people.  With respect to the new POK facility, the labor situation in Mexico is not as bad as already nearly 300 folks have been hired.  Also, the new facility will have an element of robotics.


With respect to castings, many are sourced from all over the world (including the US) and the recent supply chain disruptions over the last 2 years have emphasized the opportunity for nearshoring/reshoring components. POK/Nucor saw this opportunity and invested $35 million in the Acatlán facility to capture this capability in North America. A greenfield castings foundry, to our knowledge is not happening in the US anytime soon for all the reasons you would think. And with many of the existing facilities at or near capacity this project made sense for POK/Nucor. Reshoring/nearshoring is not about moving “everything” from China (or another low-cost country) but rather to expand production in local markets and offer customers a more robust supply chain.


The facility inauguration was spread out over two (plus) days and DEP had to leave just as the fun stuff was kicking off (ahem, tequila tasting) but the crowd was excellent (130+ people, although less than 15 were from the energy arena – a big deal as most attendees were outside of energy, a sign that energy is competing for space).  Moreover, the variety of supply chain folks from different industries and geographic locations was interesting to see, but we wonder if those non-energy sectors are potentially more lucrative buyers to POK, a potential risk for capacity to the oilfield.  Almost all the supply chain teams in attendance were doing their due diligence on processes, engineering capabilities, steel characteristics, timeframes for potential production runs etc. and asking pertinent questions which is always nice to see in person.


M&A Alive & Well:  PUMP announced the acquisition of Silvertip Completion Services for $150M, adding to its completion portfolio as PUMP can now offer wireline services, a feature similar to HAL, LBRT and NEX.   WTTR meanwhile announced two acquisitions: (1) Breakwater Energy Partners and (2) Cypress Environmental Services.  Two different acquisition strategies, in our view.  First, the PUMP deal, in our opinion, is an effort to bring in-house wireline services to provide PUMP a bundled solution capability.  The Silvertip team is well-established and well-respected within the Midland community.  The Pros of the deal include: (1) a new product line with an established management team and (2) a business which is expected generate significant cash flow as well as to be accretive to PUMP shareholders.  The primary Con of the deal is arguably valuation.  The purchase price relative to replacement value seems generous – ballpark 2.5x.  Of course, valuation on an EBITDA multiple basis screens more attractive, but our concern is paying premium dollar potentially encourages folks to attempt to replicate the Silvertip deal, thus a potential risk.  Of course, if we have a multi-year upcycle, which is our view (and prayer) and if the Silvertip team stays and generates the expected ~$65-$75M of annualized EBITDA, then the deal pays for itself in just over two years (after maintenance capex).  Not too shabby.  In the case of the WTTR deals, these screen more like true consolidation plays. The Breakwater transaction provides greater scale in the recycling market and screams ESG positive.  Like PUMP’s Silvertip deal, the WTTR transactions should also be accretive as 2022 projected EBITDA implies a valuation in the 3x EBITDA vicinity.  Moreover, as this is a consolidation play, one would think better pricing could unfold in time, all else being equal. Regardless of what one thinks of these deals, the big takeaway is the continuation of the OFS M&A movement, a trend which we believe will continue as several small players regularly tell us they are ready to hit the bid and cash out.


E&P Observations (Authored by Geoff Jay):  More earnings reports than you can shake a stick at this week (almost all of them summarized below), but the big takeaway is that budgets are—for the most part—moving higher for 2022.  For the public companies we track, capex guidance for this year got bumped up by another 4%, and spending is on track to increase by nearly 43% from last year in the US.  There have been a host of reasons given.  Inflation, sure, but the greatest hits so far are non-op activity increases and drilling longer laterals.  Some budgets are growing with increased activity, namely Callon (+1 rig), Earthstone (+1), Ranger Oil (+1), and Comstock (+2).  PDCE added a 2nd frac crew.  Chord, meanwhile, is releasing a rig and lowered its 2022 guide.


Not many companies willing to give specifics on 2023, but cost pressures are clearly going to bleed into next year.  Guesses around inflation generally center around 10-15%.  EOG is adding 2-3 rigs and 1-2 frac spreads next year.  They believe that well-cost inflation will grow by another 10% in 2023, so the increase in activity should add at least another ~$400-600mm in spending.   Coterra forecasts its cost/ft in the Permian to grow by 10-20%, to $1,000-$1,100, but admits that certain line items may grow faster (rig rates, frac crews, sand, tubulars, fuel, and labor). There is likely upside risk to these assumptions—plenty of legacy rig contracts will be rolling off, repricing at significantly higher rates.  Also, APA guided 2023 spend 21% higher, citing rig-rate and frac inflation for its 5-rig program. Wall Street appears to be catching on to this too:  Wall Street estimates for capex now show 2023 growth of 22% for the independents, up from 15% not too long ago.


Even with higher spending, the free-cash-flow story remains intact at current commodity prices.  Virtually everyone reported sufficient surpluses to buy in shares and pay a dividend.  Variable dividends were generally lower than last quarter, which should come as no surprise, given that the average WTI price was 15% lower in Q3 than Q2.


There was some big M&A news as well:  MRO acquired the Eagle Ford assets of Ensign Natural Resources for $3.0B, financed with cash on hand, MRO’s revolver, plus new prepayable debt.  The assets bring 130K net acres, 97% WI, and 67 MBOE/d (33% oil).  MRO estimates the valuation at 3.4x 2023 EV/EBITDA with a 17% FCF yield.  A one-rig program holds production flat (35-40 wells/yr).


Emission Friendly Fleets – More Deliveries Coming:  A few new announcements this week as PUMP announced it is likely to order more electric fleets.  The company previously had two fleets on order, both of which are expected to be deployed in Q3’23.  On its call, however, PUMP alluded to potentially two additional electric fleets as well.  The company expects to have six Tier 4 DGB fleets to start 2023 with a seventh fleet expected next summer, so on a pro forma basis, of PUMP’s ~15 active fleets, seven will be Tier 4 dual fuel and potentially 4 will be electric.  Of note, PUMP stated the electric fleets will not be incremental, but will displace legacy equipment.  Calfrac also noted plans to purchase 65 Tier 4 dual-fuel engines in 2023 which suggests as many as three Tier 4 dual-fuel fleets.  Finally, ProFrac completed its acquisition of U.S. Well Services and changed its stock ticker to ACDC.  In the closing announcement, ACDC noted it will have 12 electric fleets and 13 Tier 4 dual-fuel fleets by the end of Q1’23.


Drilling Data Points:  Smaller companies often provide more granular commentary.  Such was the case this week with the Independence Contract Drilling earnings call.  A few points which we think illustrate the land rig market.

  • ICD running 18 rigs, with two more rigs to go out in Q4 and two more rigs to go out in Q1’23, thus a 20% increase in the company’s working rig count.
  • Cash margins = $11,341/day in Q3.
  • Cash margins guided to $12,500 to $13,000/day for Q4 and to $14,500 to $15,000/day in Q1’23.
  • The company’s contract backlog jumped 87% to $102M.
  • Most contract terms range from six months to one year.
  • Rigs in backlog are priced, on average, at $35,300/day.
  • The company may attempt to deploy two more rigs in 2H’23.  Time will tell.

In keeping with the disconnect between what E&P’s say (or don’t say) vs. what land drillers report, Ensign Energy Services stated on its call that the company is running 62 rigs in the U.S. today.  Near-term visibility is strong as the company believes its working U.S. rig count will exit 2022 at 65-70 rigs.  That’s a +5% to +11% move within the next 2-3 months – potential gains spread across Permian, California and the Rockies.  In Canada, Ensign is running 46 rigs, but sees its YE’22 Canadian rig count at 60 rigs with a Q1’23 peak approaching 70 rigs.  Pricing on recent U.S. rig reactivations in the mid-$30’s.


As for the U.S. rig count, which added +2 rigs w/w to 754 rigs per BKR this past Friday, the collective comments/guidance from Ensign, Independence, Nabors, H&P, PTEN, and PDS points to an incremental 40 to potentially 60 rigs over the next 3-4 quarters from just these six companies.  Keep in mind these companies collectively represent about 70% of the working U.S. rig count.  Not all drillers, however, expect incremental gains as we chatted with five private drillers who together operate about 99 rigs.  Three don’t have plans to deploy any more rigs.  The other two see near-term visibility for a combined incremental four rigs, so the privates we chatted with increase from 99 rigs to 103 rigs.  The privates, along with the six publics, account for ~85% of the U.S. rig count, thus if their forecasts are correct, it would seem a seem a ~+50-60 rig count improvement over the next 3-4 quarters is reasonable.  On this point, we’ll true up the DEP forecast next Sunday.  A couple things though to highlight.  First, several drillers report rising safety incident rates – likely a function of new people, but another frustration is their belief consultants are pushing too hard for speed and efficiency.  There is a shared view that within the E&P company, a disconnect may occasionally exist between the field and the corporate office.  That is, the corporate office is all-in for safety, but the consultants are all-in for speed and minimizing costs.  Sometimes those may inadvertently be conflicting objectives.  Also, multiple drilling contacts acknowledge efficiencies are stalling while others point out the rising incidents likely lead to a sharp uptick in insurance costs.  The good news for them, in our view, is industry margins can more than cover those increases.  Lastly, one driller said it now takes longer to find a competent crew than it does to reactivate a rig.  If true and broad-based, that’s a telling observation.


Refining Observations (Authored by Geoff Jay):  MPC, PSX, and CVI reported this week (summaries below).  Unlike VLO, MPC does not see demand above pre-pandemic levels, but admitted it was using DOE data to make that determination.  Nevertheless, the company continues to run at high levels of utilization, benefitting from wide Canadian crude differentials (WCS was >$20 lower than WTI in Q3, it is currently -$29) due to refinery outages in Ohio and Indiana.  PSX made hay here too.  Every refining region was weaker sequentially except for the Central Corridor, where the company could run WCS.  Virtually everyone sees a very tight refining market, suggesting that midcycle margins will be higher than in the past.  Hard to argue with that, given the current inventory picture.


Q3 Earnings Observations:  Brevity is bliss, so we’ve tried to be brief, but in many cases we failed.  Apologies in advance.



  • Production of 176.3 MBOE/d (45% oil), up <1% sequentially.
  • Management now expects 2022 production of 166-170 MBOE/d, up 2% at the midpoint from its prior forecast.
  • Gathering, transportation and processing expenses for the year are now forecast at $4.60-$4.80, up from $4.25-$4.75 last quarter.
  • Capex of $237mm brings YTD to $710mm, or 71% of full-year guidance, newly lowered by 1% (top end of range is now $20mm lower than before).
  • D&C program of ~3 rigs / ~2 frac crews.
  • A third frac crew was brought in during Q3 and will work in Q4 to bring down DUCs.
  • FCF of >$352mm in the quarter (24% FCF yield, annualized).
  • Base dividend increased by 8% to $0.50/quarter (2.9% annualized yield).  Variable dividend of $1.45 for the quarter.  Dividends for full-year 2022 of $6.29/share (~9% yield).



  • Generated $773M of FCF during Q3.
  • Dividend of $3.16 for the quarter–$0.55 base (>2% annual yield) plus $2.61 variable.
  • Nearly $1.1B in stock repurchases this year.
  • Production 4.1 Bcfe/d (90% gas), flat sequentially.
  • Capex of $619mm brings YTD spend to $1.47B, ~80% of unchanged full-year guide.
  • Q4 spend will decline q/q due to less Eagle Ford drilling and fewer Haynesville completions.
  • Management expects inflation of 10-15% for 2023, with the heaviest impact in the Haynesville.
  • Marcellus inflation characterized in the mid-single digits but the Haynesville could see +15%.
  • Rig counts for Marcellus and Haynesville remain at 5 and 7 rigs respectively.
  • Unlikely at this point that an 8th Haynesville rig will be contracted.
  • No update on Eagle Ford divestment process.
  • CHK going from 4 rigs in Eagle Ford in Q3 to 3 in Q4.
  • On Macro, CHK doesn’t see structural growth for the gas market until 2024, so expect some softness in 2023.



  • Production of 614 MBOE/d (48% oil), flattish with Q2.
  • Management suggested 2023 growth at the low end of the 0-5% range, based on the 4Q exit rate of 650 MBOE/d (322.5 oil).
  • Q4 production guide was raised to 640-660 MBOe/d (35 of which is due to Eagle Ford acquisition production).
  • Upstream capex of $639mm, brings YTD to 66% of newly raised guidance of ~$2.5B, up 8% from prior forecast.
  • $120mm of the capex delta is due to its bolt-on acquisitions in the Eagle Ford and Williston Basin.
  • Management acknowledged that inflation is significant and will bleed into 2023.
  • Highlighted IRR’s in the triple digits for the Delaware Basin wells.
  • Highlighted a 13% drilling productivity improvement in Midland Basin wells.  Some spud-to-release times for 2-mile wells under 20 days.
  • Cited use of 3,000 pounds of sand/foot in the Powder River Basin.
  • Called out opportunity set for re-fracs and EOR in the Eagle Ford.
  • FCF of ~$1.5B for the quarter.
  • Dividend of $1.35/shr–$0.18 fixed (1% annualized yield) and $1.17 variable.



  • Production of 81.5 MBOE/d (45% oil), up nearly 10% sequentially.  Q4 guide of 77-79 MBOE/d as completions will be back-end loaded.
  • Management expects production growth of 10% in 2023.
  • Capex of $116mm brings YE spend to $321mm, 71% of full year guidance of $454mm at midpoint (higher than consensus of ~$430mm).  Capex for Q4 of $125-140mm is impacted by greater-than-expected completions and OBO activity.
  • No formal guidance for 2023 but said up 10% feels right given what is known right now.
  • Supply-chain management and close vendor relationships saved $25mm in capex this year, or $0.5 per well. MGY expects additional savings next year.
  • Although 8-well pad in Giddings underway, expect 4 well pads as the norm.
  • Well costs were ~$1,100 per completed foot for the quarter.
  • During Q&A, CEO said no big M&A likely.



  • Shareholder returns featured prominently as MRO has now repurchased nearly 20% of its stock since 2021 and returned $1.2B to shareholders during Q3.
  • The dividend was increased again, marking the 6th time in 7 quarters MRO has raised it.
  • Q3 FCF totaled $1.03B.
  • Production of 352 MBOE/d (50% oil), up 2.6% sequentially.
  • Capex of $413mm for Q3 brings YTD spend to $1.13B or 81% of 2022 guidance.
  • 2022 capital estimate was raised by 7.7% to $1.4B account for incremental inflation and capital needed to retain rigs/crews.
  • Q4 capex moves lower to $264M vs. the $413M spent in Q3.
  • MRO raised LOE expectations for the year to $5.90-$6.10, reflecting higher commodity prices and elevated workover activity.
  • Management raised income estimates from Equatorial Guinea, due to a more favorable European natural-gas-price environment.
  • Acquired Ensign Eagle Ford assets for $3B.  Deal brings 130K net acres, >600 locations, and 67 MBOE/d of production.



  • Production of 107 MBOE/d (62% oil), up 7% from Q2.
  • Expect 105-108 MBOE/d for Q4.
  • Adjusted EBITDA of $459mm, up ~10% sequentially.
  • Adjusted FCF of $148mm for the quarter.
  • Capex of $255mm brings YTD to 78% of new full-year guide of $830-$845mm, up ~7% due to the addition of a 6th drilling rig in Q4.
  • Q4 capex = $180-$195M.
  • For 2023, rigs contracted under laddered maturities.
  • CPE expects FCF of more than $200mm in Q4.
  • Callon will run one frac crew in Q4 and plans to add a 2nd in 2023.
  • Both crews will be simulfrac.
  • New frac design uses less fluid.  Saves money, but also allows for faster cycle time
  • Noted use of CT units in the Midland basin.  Already uses CT in the Delaware and Eagle Ford.
  • Changing from full-cost to successful-efforts accounting in 2023.



  • Production of 188.5 MBOE/d (57% liquids) up 15% from Q2.
  • Full-year production guide of 164-172 MBOE/d (54% oil), vs prior guidance of 168-176 MMBOE/d (52% oil).
  • Forecast delta caused by: Tupper Montney royalty impact (10.5 MBOE/d), Offshore downtime (9.5 MBOE/d), and non-op Kodiak #3 underperformance (4.5 MBOE/d).
  • Capex of $209mm, brings YTD to $776mm, or 78% of newly raised full-year guidance of $975-$1.025B.
  • Looks like a $75mm increase.
  • Capital increase is due to operated offshore (+$40mm), Eagle Ford (+$20mm), non-op offshore (+$10mm) and exploration (+$5mm).
  • Noted Eagle Ford wells exceeding forecast with some of the highest IP30 rates in company history.
  • Reduced debt by $248mm.
  • $300mm buyback plan authorized.



  • Production of 299 MMcfe/d (70% natural gas), up 26% from Q2.  Guided Q4 to 315-329 MMcfe/d.
  • Capex of $110mm brings YTD to $225mm, or 68% of new full-year guidance of $320-340 (up ~5% at the midpoint).  Inflation was not a factor in the increase, according to management.
  • Shifted both rigs to Webb County to accelerate Austin Chalk Dorado development.
  • This play now has 17,000 net acres and 200 potential locations.
  • Drilling 16 wells here Q3 and Q4, 15 Austin Chalk and 1 Upper Eagle Ford.
  • Guided capex to $450-550mm in 2023, anticipating a 2 to 2.5 rig program.
  • Production in 2023 of 400-420 MMcfe/d, up 8% vs. prior outlook and +50% y/y.
  • Expect 2023 EBITDA of >$700mm.
  • Plan to add third rig in 2H 2023.



  • Adjusted production of 310 MBOE/d (44%oil), up 1.6% from Q2.
  • Capex of $492mm, YTD spend of $1.28B or 74% of unchanged full-year guide of $1.725B at midpoint.
  • Q4 capex guided to $450M.
  • Adjusted EBITDAX of $1.69B.
  • FCF of $609mm.
  • Dividend doubled to $0.25/quarter (annualized yield of 2.3%).
  • Repurchased 10mm shares in the quarter.
  • Total of $373mm returned to shareholders in Q3.
  • Averaged 5 rigs with 4 in the Permian and 1 in the Austin Chalk with 16 gross wells drilled & completed.  The Austin Chalk rig was released in September.
  • Averaged 19 rigs internationally (2 Suriname and 17 Egypt).



  • Production of 250 MBOE/d (32% oil)
  • Capex of $260mm brings YTD spend to $770mm, or 72% of guide of $1,075mm (now at high end of previous range).
  • Roughly $230M spent in the Wattenberg and $30M in the Permian.
  • Increase is due to brining on a 2nd completion crew at the end of Q3, plus cost pressures.
  • The 2nd crew is in the Wattenberg where PDCE runs 3 rigs.
  • Cited 2.5 mile to 3.0 mile laterals as increasingly common.
  • Noted two LBRT records: 808 stages completed in one month and 129 continuous pumping hours.
  • Claims ~100% returns in ~14 months at strip pricing in the Wattenberg.
  • Looks like PDCE will keep one rig in the Permian with a partial frac crew.
  • FCF of $440mm.
  • Reduced debt by $300mm and repurchased 4.2mm shares.
  • Paid a dividend of $0.35 (~2% annualized yield).
  • Noted ~5% service cost inflation from here.



  • Volumes up 15% q/q with Q4 volumes guided to 105,000 to 110,000 BOE, essentially flat q/q.
  • 2022 capex to be $430M vs. the previous guidance of $400-$440M.
  • Q3 capex = $114M.
  • Generated $570M of FCF YTD, returning $270M to shareholders.
  • Noted additional purchases QTD of $44M with a total of 8% of shares repurchased.
  • Dividend raised 10%.
  • Net debt reduced 28% q/q with net debt now equal to $391M.
  • Will complete 5 Bakken wells in Q4 vs. 8 in Q3.
  • Frac holiday expected with the company’s crew taking ~2 months of so off.
  • ERF will continue to run 2 rigs and 1 frac crew in 2023.
  • Bakken well costs were forecasted to be $6.5M, but are closer to $6.9M.  For 2023, expect another 10% increase.
  • Noted use of in-basin Bakken sand as well as employing emission-friendly drilling rigs (i.e. battery pack, etc.).



  • Production of 42.6 MBOE/d (72% oil), up ~11% from Q2.
  • Capex of $134mm brings YTD to $308mm, or 60% of full-year guide of $507-527.
  • This forecast is ~14% higher than last quarter’s guide of $440-470mm.
  • Q4 capex guided to ~$160M.
  • The company recently added a 3rd rig through YE’22, but commentary suggests its reasonable the company will keep the third rig through 2023.
  • Adjusted PF FCF of $58mm.
  • Repurchased ~5% of common stock or $80M since May.
  • Dividend of $0.075/quarter (0.75% annualized yield).



  • Production of 172.5 MBOE/d (56% oil), up 8.8% sequentially.
  • Capex of $230mm brings YTD to $557mm, or 75% of newly lowered 2022 guide of $740mm (-~`1%).
  • Q4 capex moves lower to $170-$200M.
  • FCF of $326mm in Q3 and $1.3B forecasted for 2022.
  • Shareholder returns:  $125mm in share repurchases, $52mm base dividends ($1.25/share or 3% annual yield), and $100mm of variable dividends ($2.42/share).
  • Cited delays in 2H’22 frac schedule.
  • Dropped from 4 rigs to 3 rigs due to operating efficiencies.



  • Production of 1,754 MBOE/d (51% oil), up 3.6% sequentially.
  • Lower 48 production of 1,013 MBOE/d (53% oil), up 3.7% from last quarter.
  • Full-year production guide of 1,740 MBOE/d unchanged.
  • Capex of $2.2B brings YTD to $5.9B, or 73% of new full-year guidance of $8.1B (up ~4% from prior guide).  Of the $300mm delta, $100mm change in working interest/OBO mix, rest inflation.
  • Full year operating-cost guidance increased by $200mm (2.7%) to $7.7B.
  • Increased dividend by 11% to $0.51/share (1.5% annual yield).
  • Bought in $2.8B worth of shares in Q3.  Upped share-repurchase authorization by $20B.
  • Q3 FCF of $4.7B.
  • For 2023, early indications for activity to keep FY flat with 2H 2022 levels.



  • Production of 94.3 MBOE/d (41% oil), up 22% from Q2.
  • Q4 production guide of 98-102 MBOE/d (43% oil).  Guidance is up 2% from prior levels.
  • Full-year production guidance now 76.4-77.5 MBOE/d, up from 73.9-75.9 MBOE/d previously.
  • Capex of $147.2mm brings YTD to $349mm, or 66% of full-year guidance of $519-534, up 2% from prior guide at the midpoint.  Contemplates longer laterals than previous, as well as higher levels of non-op activity.
  • LOE outlook for 2022 raised from $7.49/BOE to $7.97/BOE at the midpoint.
  • 2 rigs Midland Basin, 3 rigs Delaware.
  • ESTE added a rig in the Delaware and expects to run a 5-rig program in 2023.
  • Adjusted EBITDAX of $345mm.
  • FCF of $174mm.



  • Production of 79.6 MBOE/d (44% oil) in line with preannounced levels, down 8% sequentially.
  • Capex of $140M during Q3 with Q4 guided to $135-$145M.
  • LPI ran 2 rigs and 1 frac crew – that’s the working plan for 2023 although a spot crew may be sporadically needed next year.
  • YTD spend of $449M, 76% of full-year guidance of $589mm (up 7% from $550 previously).
  • FCF of $51mm in Q3.
  • LPI repurchased $152mm of debt during the quarter and bought in $18mm of its shares.
  • Company using 2 rigs and 1 frac crew for Q4. 4Q22 production consistent with pre-announced volumes 79.6k bbls/d and oil at 34.9k bbls/d.
  • Repurchased $152M of debt at 98% of par, which reduced total net debt to $1.14B.
  • Repurchased $17 .5M of stock through equity repurchase program.
  • November 1, 2022 finalized revolver at $1.3B up from $1.25B.



  • Production of 919.2 MBOE/d (51% oil), down slightly from Q2.
  • Full-year guide 903-915 MBOE/d (51% oil), up from 884-924 MMBOE/d previously.
  • Capex of $1.2B brings YTD to $3.2B or 71% of full-year guidance (bottom end raised to $4.5 from $4.3B.  High end remains at $4.7B).
  • Cash cost estimates for 2022 unchanged at the midpoint, but range tightened to $10.25-$10.61.
  • FCF of $2.3B for Q3.
  • Regular dividend increased to $0.825/share (2.4% annual yield).  EOG declared a special dividend of $1.50/share for Q3.
  • Unveiled Utica Combo Play, 395K net acres, owns 100% of mineral interest as well.  20 well program for 2023, using 3-mile laterals.



  • Production of 641 MBOE/d (86% natural gas), up 1.4% from Q2.
  • Full year production guide raised to 625-640 MBOE/d (from 615-635 prior).
  • Capex of $460mm brings YTD to $1.25B or 74% of full year guidance of $1.7B (at high end of previous range).
  • FCF of $1.1B for Q3.
  • Base dividend unchanged at $0.15/share (~2% annual yield).
  • Variable dividend of $0.53/share for Q3.
  • $253mm in share repurchases this Q, retiring 9.3mm shares.
  • Permian well costs expected to average $935 per completed foot this year, ~$1,000-1,100 per foot in 2023.  Electric wells save the company $75/ft.  Roughly 80% of CTRA’s Permian wells are drilled with e-rigs., and 20% are completed with e-fracs.



  • Production of 137.8 MBOE/d (45% oil), in line with preannounced levels, -6% from Q2.
  • Full-year production guidance now 144-145 MBOE/d (46% oil), down >3% from 148-151 MBOE/d.
  • Adjusted FCF of $178mm; over $1B of FCF during the past 12 months.
  • Total debt down about $500mm since YE’21 while cash is up nearly $165mm.
  • Launched capital returns program, buying back over 450,000 shares and increasing the dividend.
  • Capex $239mm brings YTD spend to $643mm, or 73% of unchanged full-year guide of $870-900mm.
  • Q4 capex guided to $228mm to $258mm.
  • Annualized Q4 capex implies is $910mm to $1,032mm, which would be up about 10% y/y should this prove to be the 2023 budget range.
  • Rig count unchanged:  3 rigs / 1 frac crew Midland Basin, 2 rigs / 1 frac crew South Texas.
  • Noted service cost of inflation of 25-30% relative to Q4’21 is baked into the 2022 capex budget.
  • Nice well performance charts in slide deck.



  • Production of 414.4 MBOE/d, up 3.6% from Q2.
  • Full-year guidance of 200-210 BO/d, 1.1-1.2 Bcf/d.
  • Capex of $816mm brings YTD to $1.99B, or 75% of unchanged full-year guide of $2.65B.
  • FCF >$1B
  • Reduced debt by $1.26B in the quarter.
  • CLR did not hold a conference call, given recent agreement for Hamm family to take private.



  • Crude throughput of 2.8 MMB/d, 98% utilization
  • Q4 Throughput estimated at ~2.7MM B/d, ~97% utilization.
  • Unlike VLO, MPC sees demand below pre-Covid levels, but believes there is significant recovery underway.
  • 4 MMB/d of capacity offline globally during the last couple of years, making system extremely tight.
  • This means midcycle earnings likely higher than before.
  • Adjusted EBITDA of $6.8B, down 25% from Q2 levels.
  • Margin per Bbl of $30.21 for Q3, down from Q2’s record $37.54/Bbl.
  • Margin capture of 97%.
  • Increased dividend to $0.75/share (2.5% annualized yield).
  • Share repurchases of $3.9B during Q3.  Completed $15B share repurchase agreement using Speedway proceeds.



  • Throughput of 1.9 MM B/d (91% utilization), up slightly sequentially.
  • Refining pretax income of $2.8B, vs $3.1B in Q2.  Virtually every region was weaker sequentially, apart from the Central Corridor, which enjoyed an $830mm benefit from wide WCS differentials.
  • Realized margin of $26.58/Bbl, down from Q2’s $28.31/Bbl.
  • Market capture was 73% for PSX, impacted largely by refinery-configuration impacts and secondary products.
  • In Chemicals, the company’s Olefins and Polyolefins segment fell sharply sequentially, due to low polyethylene prices.
  • For Q4, PSX expects refinery utilization in the low to mid 90% range.
  • The company expects its global Olefins & Polyolefins utilization to be in the mid-90%’s.
  • PSX repurchased $700mm of common stock in Q3, and paid dividends of $500mm.



  • Refining throughput of 202 MB/d, flattish with Q2 levels.
  • Throughput for Q4 expected to be 200-220 MB/d.
  • Margin per Bbl of $23.05, a 52% capture rate.  RINs obligations reduced capture by 12%.
  • Fertilizer segment was impacted by major turnarounds in Q3, resulting in EBITDA of $10mm for Q3.  No more are expected until fall of 2024.
  • For Q4, ammonia utilization should be between 93-98%.
  • Adjusted EBITDA of $313mm for total company
  • The company’s board authorized a regular dividend of $0.40/share (4.2% annualized yield) and a special dividend of $1/share.



  • Revenue $577M +7% q/q and +31% y/y
  • EBITDA $53M +12.7% q/q and +211% y/y
  • FCF $44MM with total liquidity of $635MM ($267M cash and no debt)
  • Bought back $4M of shares during the quarter $76M still available under buyback program.
  • Annualized revenue per at $1.3M for 3Q22.
  • M&A remains a priority and the pipeline of opportunities continues to be active.
  • Guiding Q4 revenue lower mid-to-high single digit percentage due to seasonality and budget exhaustion.
  • Opened new super center in the Bakken during the quarter.



  • Revs = $49M, +51% y/y.
  • Adjusted EBITDA = $8.4M.
  • Q/Q revenue saw strong improvement in Canada (+171%) with International up 5% and the U.S. down 5% q/q.
  • U.S. revenue was negatively impacted by lower sales at Repeat Precision.
  • International was up despite no product sales, something that should reverse itself in Q4.
  • Both U.S. and International are expected to see sequential Q4 revenue improvement while Canada to decline, a function of customer budget exhaustion.  Consequently, Q4 revenue on a consolidated basis is expected to be lower.
  • Canadian revenue = $35M, the highest level since Q1’18.
  • Cash = $10M with total debt = $8M.
  • Recently participated on a Canadian simulfrac.



  • Revs = $49M vs. $42M in Q2
  • Adjusted EBITDA = $12.5M vs. $9.2M in Q2
  • Averaged 17.4 rigs
  • Drilling days were 1,601 in Q3 vs. 1,540 days in Q2
  • Running 18 rigs today with rigs 19 and 20 going to work in Q4
  • The company is marketing two additional rigs to be deployed in 1H’23.
  • Revenue/day = $28,646/day.
  • Cash margins = $11,341/day.
  • ICD sees Q4 cash margins improving 10-15% q/q with Q1’23 cash margins to exceed Q3’21 levels by 28-32%.
  • Cash = $8M with total debt = ~$170M.



  • Revenue for 3Q22 was $92.3M, +6.5% q/q and +86.7% y/y, EBITDA was $23.8M +16.4% q/q.
  • Fully utilized systems grew from 84 in 3Q to 94 in 4Q22 +12% q/q
  • 1/2 of fully utilized system growth during the quarter was pull through share from new top fill systems.
  • Some growth in Q3 came from customers that led SOI to Rockies and Bakken.
  • Top fill systems typically can reduce truck miles by up to 20%, Rockies and Bakken the reduction is 35-40%.
  • One out of three top fill units will drive pull through sand systems that are currently not in use.
  • Added 7 fully utilized top fill units during the quarter, for total of 9 working during the quarter.
  • Continue to test the ability of full offering to handle wet sand, stay tuned.
  • Capex for 4Q22 will be between $15-20M
  • Capex Guide for FY23′ is $75MM, which $10-15MM is for maintenance and growth capex will be mostly spent in 1H23.
  • 23′ growth capex of $60M being driven by incremental demand for top fill systems.
  • Top fill systems are approximately $1.5M to build and SOI expects 2-3 year payback.
  • We don’t model SOI, but the simple math would suggest $60M of growth capital should equal $20M of EBITDA on a 3-year EBITDA payback.
  • Q422 expect normal seasonality with potential slow down at Thanksgiving and around the year-end Holidays.



  • Revs = $333M vs. $315M in Q2, +6%.
  • Adjusted EBITDA = $90M vs. $76M in Q2.
  • FCF = ($26M)
  • Effective utilization = 14.8 fleets as PUMP continues to market 15 fleets.
  • Annualized EBITDA per fleet increased 18% q/q to $20.5M.
  • Recall, PUMP noted last quarter that it expected its 2023 EBITDA/fleet metrics to be 25-40% higher than Q2 levels, thus feels like a $22-$23M EBITDA/fleet is a reasonable range.
  • Cash = $43M with total debt = $30M.
  • Q3 capex = $115M.
  • Q4 Guidance: Effective fleets to average 14-15 fleets.
  • Will have 6 Tier 4 DGB in early 2023 and a 7th Tier 4 DGB in mid-2023.
  • PUMP has two electric fleets on order and insinuated more could be ordered.
  • The electric fleets will be leased.
  • Full year cash capex budgeted at $325M with total capex = $350M.
  • 2023 capex expected to be lower.
  • Purchased Silvertip for $150M.  Assets include 23 wireline units and pump down trailers.  Not clear how many, but we believe many of them are Tier 4.
  • PUMP expects Silvertip to contribute $65M-$75M in EBITDA in 2023.



  • Revs = $375M, +12% q/q.
  • Adjusted EBITDA = $63M, +32% q/q.
  • Two acquisitions for total consideration of 9.2M shares and assumption of $13M of debt and other obligations.
  • Combined companies expected to generate $110-$115M of revs and more than $30M of Adjusted EBITDA.
  • Water Services: Revs = $221M vs. $196M of Q2.  Gross margin = 22.8%, up 330bp q/q.
  • Water Infrastructure: Revs = $74M vs. $60M in Q2.  Gross margins = 27.2%, up 170bp q/q.
  • Oilfield Chemicals: Revs = $79M, flat with Q2.  Gross margins up 420bp to 18.8%.
  • Q4 Guidance:
    • Water Services: Flat revenue and margins expected.
    • Water Infrastructure: Revs to grow low-double digits with gross margins in the high 20% range.
    • Oilfield Chemicals: Revs to grow mid-single digits.  Stable margins.
  • Cash = $13M.  Total debt = zero.



  • Canadian Dollars.
  • Revs = $245M vs. $273M in Q2
  • Adjusted EBITDA = $58M vs. $55M in Q2
  • Operated 5 frac spreads in Canada and 3 frac spreads in the U.S.
  • Operated 8 CT units in Canada and exited Q3 with 11 active U.S. CT units.
  • STEP will reactivate another large diameter CT unit in the U.S.
  • U.S. Operations
    • Revs = $104M in Q3, down $4M from Q2.
    • Adjusted EBITDA = $20.8M, +$0.5M q/q.
    • Annualized EBITDA/fleet = $27M
  • Canadian Operations
    • Revs = $141M vs. $84M in Q3’21.
    • Adjusted EBITDA = $41M vs. $17M in Q3’21.
  • 2022 capex budget = $98M.
  • Includes one Tier 4 DGB fleet, previously announced, for the Canadian market.
  • 2023 preliminary capex budget = $55M.



  • Canadian Dollars.
  • Revenue = $438M, +67% q/q.
  • Adjusted EBITDA = $91M vs. $30M in Q3’21.
  • Actual results beat guidance.
  • U.S. Operations:
    • Ran 9 fleets in Q3 with a 10th fleet recently deployed.
    • Revs = $237M with Adjusted EBITDA = $55M.
    • Annualized adjusted EBITDA/fleet = $24M.
    • 601,000 active horsepower or about 66,000/hp per active fleet.
    • 270,000 idle horsepower.
  • Canadian Operations:
    • Running 4 fleets and 5 CT units.
    • Revs = $137M, +79% y/y.
    • Adjusted EBITDA = $37M, +145% y/y.
    • All 270,000 horsepower is active or roughly 67,500 hp/fleet.
    • Operates 7 CT units.
  • Argentina revs +34% y/y to $64M with adjusted EBITDA = $9M.
  • Cash = $12M with LT debt = $412M.




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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