This past week we completed another Permian trip as we travelled west to attend a ChampionX open house featuring its recently acquired Scientific Aviation business (more below) while we also summarize a Marcellus frac site tour from two weeks ago.  We return to the Permian tomorrow for another two-day visit as we will be taking an investor team through the basin for a private investor tour.  It has been a long time since we hosted a Permian buyside tour.  Nevertheless, it’s good to see some renewed interest and we remind our buyside audience of this opportunity should they be interested.  The week of August 16th, members of the DEP team will be in the DFW area for three days with another Pittsburgh visit on the docket for the week of August 23rd.  Those in the DFW and/or Pittsburgh area, let us know if you are up for a visit.  Finally, our Midland reception will take place Monday night followed by a small happy hour in Houston on Thursday.

ChampionX Equipment Tour.  In its pursuit to invest in sustainable businesses, ChampionX acquired Scientific Aviation in early July.  The Scientific business was founded in 2010, originally offering plane-based measurements of air pollutants and greenhouse gases.  The company subsequently moved into drone-based emission monitoring and now has a continuous ground monitoring system called SOOFIE. This past Thursday, ChampionX brought the Scientific team and all of its operating gear for an open house at the Commemorative Air Force Museum in Midland (a great place if you’ve never been before).  On display was one plane, a drone and the SOOFIE system.  Also, in attendance were name brand E&P companies.  Here’s our quick-and-dirty takeaway.  First, while emission monitoring is not necessarily a new concept broadly-speaking, it does feel like a concept with growing urgency for the oilfield.  In fact, our chat with event attendees would seem to suggest the E&P sector might just be price-takers today, a positive for those offering quality emissions monitoring services.

The Scientific Aviation monitoring solutions come in different forms.  If an operator wants to quickly evaluate a wide area, the plane solution is optimal as the plane can fly and monitor for ~8 hours, covering a significant area.  For a better near-field point source emissions quantification, the drone solution may be optimal.  The drone, we believe, can fly about 30 minutes before a recharge/batter swap is required.  The drone is equipped with sensors to gauge wind, temperature, relative humidity and pressure measurements.  Within the Scientific fleet, it owns/operates multiple planes and drone systems. The third option is the SOOFIE system (Systematic Observations of Facility Intermittent Emissions) which provides ground-based monitoring and can operate 365 days per year.  The system can take 5 measurements every second and can best detect which specific field component might have a leak.  Also, the system can be powered by solar panels.

Our two cents from the visit.  First, the technology is neat – folks should check it out.  Second, the SOOFIE system would appear to be the most useful for someone seeking real-time measurements (and perhaps the most accurate – at least that’s our assumption – we’ll correct if mistaken).  The onsite aspect coupled with its cloud-based reporting allows end-users the ability to monitor all that’s going on remotely.  We did not get any color on pricing for any of these services nor did we try to dig into the economics of the acquisition.   For this reason, we can’t opine on the economics of installing/using SOOFIE or a similar product.  That said, if an E&P truly wants to measure all of its emissions, one would think an onsite measurement solution working 24/7 and 365 days a year would be best.  The aerial solutions, we submit, are appropriate as an interim step or where setting up onsite monitoring doesn’t make sense.  We do note that upon leaving the Doubletree hotel we met someone who works for a competing large-cap OEM.  This person’s job is to sell its company’s emission monitoring equipment.  Our short discussion helped validate our view the demand for an effective emission monitoring solution is real and we may be in the early days of building out monitoring programs.

NEX Acquiring Alamo.  NEX announced it will acquire Alamo for $268M, a combination of cash and stock.  NEX will get 9 frac fleets, of which many are Tier 4 DGB or in process of being upgraded.  The company operates out of one yard in Stanton and according to the acquisition press release generated ~$68M of EBITDA in 2020.  We believe recent/current customers for Alamo include COP, CrownQuest, Birch, SM and XTO.  If our assumption is correct, this is a good customer list.  Finally, the deal includes an earn-out to keep folks through 2022.  This is important as Alamo entered the Permian market in 2017, quickly took market share and delivered arguably the best financial results of any frac company over the past 4-6 quarters.  Suggests the Alamo team is doing something right.

Reasons why we believe this deal matters for the industry/NEX.  (1) this is a major win for NEX as it is a dominant provider of Tier 4 DGB equipment; (2) Alamo’s implied EBITDA/fleet in 2020 was $9-$10M/fleet (~7 fleets in 2020), way better than virtually any other frac company; (3) the industry needs consolidation and this deal helps as Alamo had ~10% market share in the Permian pre-deal, thus the combined NEX/Alamo share is roughly 17% now; (4) by our estimates, the top four Permian players now hold ~60% market share while several of the smaller players are sold out, thus pricing power exists for the frac industry should they choose to flex it.  Finally, for NEX, this should be a simple integration given Alamo only operates one facility.

Tier 4 DGB Push.  The push for emission-friendly upgrades continues with multiple frac companies citing plans to upgrade Tier 4 Dual Fuel Technology.  This past week, FTSI announced it will build a new Tier 4 DGB fleet for $26M (thankfully backed by a contract); PTEN announced last week it would upgrade two fleets to Tier 4 DGB; RES increasing its Tier 4 DGB capacity by at least one fleet; PUMP has at least 90,000 Tier 4 DGB capacity while NEX is buying Alamo Pressure Pumping, in part, we believe, to become the dominant operator of Tier 4 DGB technology.  Updates with industry contacts suggest lead times for the CAT DGB product are roughly 18 weeks.  Add another 3-4 weeks to assemble/deliver the new frac trailer and the effective lead time is about 22 weeks or ~5-6 months.  Of note, as a sign the market appreciates disciplined expansion, we point to FTSI whose stock jumped ~10% on Friday as the company noted its new fleet will be supported by a contract. What also matters is the pressure pumping industry leadership is finally acknowledging the emission-friendly frac solutions are sold out, thus pricing leverage exists.  We would assume the industry will flex its muscle after two years of beatings.

BKR U.S. Rig Count.  +3 rigs with the U.S. land rig count rising to 476 rigs.

Fully Powered Electric Frac Site (DEP tour participant and author = Sean Mitchell). Background: DEP made the trip to the Marcellus two weeks ago to visit a Chesapeake well site outside of Sayre, PA.   In our 25+ year career, we have visited several frac jobs, but this was the first time to a site being run essentially by all electric equipment.  What stood out was the small footprint, little noise on location and no diesel smoke.  For the three companies involved – Halliburton, Chesapeake and VoltaGrid – all seemingly will benefit from the push for emission-friendly equipment.

What was on location from Halliburton?   A total of 40,000 HP (8- 5,000 HP Zeus Electric Pumps vs traditional job with 18-20 2,000 HP Diesel Pumps).  1- Electric Tech Command Center which is similar to a traditional command center with the exception that this one was all electric and works with integrated well completions unit (wireline and frac under one roof).   1- All Electric Blender to facilitate HAL’s ExpressBlend fluid management system.  1- E-Winch, which has essentially replaced a wireline truck.  1- Large-bore, dual-manifold trailer that replaces the traditional frac missile.

What is special about HAL’s All-Electric Fracturing Offering?  Reduce emissions and lower cost (i.e. elimination of diesel, among others).  These, however, are DEP’s observations.  The eight Zeus Pumps were extremely quiet.  Ear protection on any traditional frac job is a necessity and on this job, DEP had protective gear as well.  However, to test the noise emissions, ear plugs were temporarily removed and a full discussion occurred, despite the fact the pumps were pumping at a high rate.  According to HAL, the pumps can reduce the footprint on location by 34% and while advertised emission reductions range between 20-45% depending on the power source.   In this case, using VoltaGrid as a power provider, HAL was able to reduce emissions for Chesapeake by 32%.  A conventional frac spread with 20 pumping units would occupy approximately 6,500 sq/ft on location vs HAL’s electric spread with 8 pumping units will occupy approximately 4,300 sq/ft on location.  It is our understanding the Zeus pump is capable of delivering 5,000 HP consistently at 22BPM and 9,500 PSI.  Moreover, the Zeus pump is flexible as it can run on power from the grid, reciprocating engines or low emission turbines.  With zero gallons of diesel consumed during pumping operations, HAL claims emissions are reduced to levels significantly below Tier 4 thresholds.  In addition to reducing NPT associated with transmissions, engines and hydraulics, the pump allows for instant and seamless rate changes without lag times during rate transitions.  Electric Blender. The electric blender and ExpressBlend fluid management system on location was built to help reduce NPT and the blender has a maximum rate of 120 BPM.  The most visible benefit was the elimination of the dust bowl that you might typically see when sand is entering the blender. The HAL electric blender has full onsite/offsite remote-control capability and hammerless connections which are HSE friendly.  Electric Wireline Unit is called the Halliburton E-Winch.  Size of the E-Winch was an apparent benefit as the E-Winch is much smaller relative to a traditional wireline truck. The trailer mounted electrically powered winch eliminates the need for a traditional wireline and logging truck that relies on a diesel engine to supply electricity and hydraulic HP.  It is our understanding the cost to build the E-Winch is materially cheaper than the traditional wireline unit, a benefit to HAL.   Also, the E-Winch uses a direct-drive motor vs a traditional hydraulic or chain-driven winch. The E-Winch panel is located inside the Tech Command Center (TCC) which houses wireline and frac under the same roof.  And, the E-winch can be operated from a remote handheld device outside on the ground or from inside the TCC.  Operating the winch from the remote-control handheld device outside allows for the winch operator to be in direct communication with the ground crew and crane operator.    The system also has multiple high-definition cameras that provide real time views of the winch and the operation. Manifold Trailer. The large-bore, dual-manifold trailer is similar to what many refer to as the frac missile and it located in the middle of the 8 pumps.  Purported benefits vs a traditional frac missile include fewer failure points and a faster rig-up, a function of eight Zeus pumps connected to the trailer vs a traditional fleet with 18 connections to the frac missile.  The large bore allows for higher rate capacity up to 230 barrels per minute (BPM), which might be a benefit for operators moving to simul-frac operations.  This trailer is operated with remote actuated valves which can be more efficient and reduce personnel on location from the red zone.

What was on location from VoltaGrid? A total of 25MW of mobile power, which is capable of essentially powering a small city.  The power set-up consisted of ten 2.5 MW trailers of low carbon power generation running on field gas, 1- All Electric mobile refrigeration unit (MRU)/ booster compression system, 1- trailer mounted energy storage system (ESS) and 1 – Emissions Portal System.  Each 2.5 MW trailer has a CAT 3520 natural-gas engine that provides reliable and clean power to remote locations. The MRU and compression system allows the generators to run on CNG, LNG, field gas, residue gas or renewable natural gas, which gives operators tremendous flexibility. The MRU has the capacity to produce up to 4.2 MMSCF per day of conditioned gas per system. When paired with VotaGrid’s single-trailer, all-electric booster compression system, the VotaGrid MRU can accept inlet gas pressures as low as 80 psi and as high as 5,000 psi. It is our understanding that VoltaGrid’s system can accept gas from 850 LHV to 1,150 LHV and the MRU strips out natural gas liquids (NGLs), which can be returned to the customer for sales and could potentially offset some of the power cost.  The ESS is critical to stabilizing the mobile micro grid and ensures power quality meets/exceeds IEEE & ISO standards especially during aggressive load-step changes.  The ESS also allows VoltaGrid the ability to manage and optimize the most efficient number of gensets running during frac operations as well as between stages.  VotaGrid’s emissions portal system is tracking and analyzing emissions and carbon intensity throughout the completions operation, allowing CHK to minimize emissions with greater fuel efficiency.    One thing that was very apparent on location was the VoltaGrid power system is modular and can fit on just about any well pad in different configurations. While VoltaGrid was running field gas on this particular job, they are planning to use CNG on the next job.  Lastly, VoltaGrid was able to move all their equipment off location in less than 10 hours.

What is the benefit to CHK?   In this case, the most obvious benefit to CHK is the emissions/noise reduction and fuel cost savings from using their field gas to run the VoltaGrid power system.  The power system is capable of running everything on location from large pumps to small tower lights that typically would run on diesel.  Some stats around diesel cost savings are as follows:  CHK has been using roughly 13,700 gallons of diesel/day in Marcellus and averaging about 27 days/month of pumping.  The HAL E-fleet is expected to be active throughout the year, so we would assume 12 months.  This would equate to approximately 4.4MM gallons of diesel/year under this utilization framework.  This system, per CHK, should allow them safely reduce their emissions profile without sacrificing reliability and performance on their completion jobs.  According to a contact, the Zeus pump apparently delivers 40% higher performance than conventional pumps.  Lastly, CHK has indicated the fleet performance partnership has exceeded expectations.

What does this mean for the industry?  First, there are multiple new emission-friendly solutions coming to market as well as emerging power solution providers.  The DEP team was fortunate to see first-hand one of the working solutions.  Second, DEP has been fairly vocal that the frac industry will migrate towards emission-friendly equipment whether that’s direct-drive turbine, Tier 4 dual fuel and/or Electric Frac.  We don’t know which system will ultimately win, but we do believe all will eventually have a prominent role.  In fact, we hope to see another competitive solution this week in Midland.  Furthermore, when we return to the Marcellus in two weeks, we’ll visit with two E&P’s who have elected to use a different solution.  We look forward to hearing their perspectives.  Point is, there are growing options and we’ll do our best to report on all of them, so let us come out and see what you are doing.  Also, the E&P feedback regarding performance is thus far encouraging.  For those interested, we include two pictures.  The photo on top is the HAL E-Winch which is essentially replacing a wireline truck (circled in blue).  The bottom photo shows the pad layout with the power equipment.

Sell-Side Q&A Participation: Highlighting relative sell-side participation on last week’s earnings calls.

OFS:  NEX (6), PUMP (5), FTSI (3), DNOW (3), SND (3), NINE (3), ESI.CA (2), WTTR (2), ICD (1), NCSM (1)

E&P: PXD (13), FANG (10), EOG (9), DVN (9), COP (8), OXY (7), CRK (7), CLR (6), CPE (6), MUR (6), MRO (5), PDCE (5), CDEV (5), PVAC (4), ESTE (3), XEC (3), WLL (2), LPI (2).

Q2 Earnings Observations

E&P Capex: Most budgets reaffirmed.  To the extent, budgets were tweaked higher, that’s a function of acquisitions and/or updating for higher service costs.  One company cut its budget.

  • WLL: Q2 Capex = $58M vs $56M in Q1. Tightened 2021 Capex Range for FY21 to $240-$252M as previous low end of guide was $228M.  Implies slightly more spend in 2H21 vs 1H21.
  • PXD: Capex $3.1- $3.4B for FY21.  Q1 = $605M, Q2 = $883MM.  Implies $1.76B in 2H’21.
  • FANG: Reduced 2021 cash budget by $100M, now = $1.525B-$1.625B. Q3 cash capex guide $430-480M vs $366M in Q2.  Company noted the 2022 budget could be up 10-15% y/y.  Let’s assume 15% on the mid-point of 2021 guidance.  This implies a 2022 budget of ~$1.8B.  The mid-point of the Q3’21 spend annualized is $1.8B, so FANG’s guidance would effectively be flat vs. current spending.
  • MUR:  Q1 = $230MM, Q2 = $198MM.  Q3 Guided to $160M with Q4 guided to $112M.
  • EOG: Q2 capex = $972M came in below the low end of guidance.  Q3 capex guide is $900-$1.1B. CY’21 capex budget is unchanged at $3.7-$4.1B.
  • LPI: Q2 = $95M.  Q3 Guide = $150M and Q4 = $105M.
  • MRO:  Q1 = $184M; Q2 = $289M, Q3 expected to be $340M with implied Q4 = $187M. Budget maintained at $1.0B.
  • CPE: Q2 operational capex = $138M vs. $96M in Q1.  Q3 operational capex budgeted at $120M-$130M.  Implied spend in Q4 is $70-$80M.
  • PDCE:  Q2 capex = $180M.  Q3 expected to decline to $150M with Q4 declining as well.  The 2021 capex budget will range between $550-$600M.   PDC noted the budget does incorporate some service cost inflation with ~10% referenced in the Wattenberg.  The reinvestment rate through 2023 expected to be 40-45% with an annual capex budget in the $600-$650M range.
  • CLR: 1H’21 capex = $600M.  Budget stays at $1.4B, thus a second half step up.
  • APA:  Reaffirmed the $1.1B budget.  Q1 = $243M; Q2 = $257M.  Q3 guided to $280M.  Company provided a simplistic framework which would indicate the 2022 spend could be as much as $1.2B, but the development capital in this scenario would rise from $900M in 2021 to $1.2B in 2022.  Company was clear this wasn’t official guidance, but 2021 includes $200M for its Suriname exploratory project.
  • CRK:  Q1 D&C capex = $163M.  Q2 D&C capex = $165M.  2H’21 D&C capex budget remaining = ~$215M or ~$105M/quarter.
  • ESTE: 1H’21 capex = $33M.  2021 budget = $130-$140M, thus 2H’21 capex = ~$100M.
  • SBOW:  Revised 2021 capex to $115-$130M.  Previously was $100M-$110M.  1H’21 capex = $57M.  The 2021 capex plan indicates a 70% reinvestment rate.
  • PVAC: Q2 capex = $69M.  Q3 capex guided to $56-$64M.
  • CDEV: Q1 capex = $73M.  Q2 capex = $83M.  2021 budget is $260M-$310M.  Assuming high-end of guidance implies spending flattish in 2H’21.
  • COP: L48 spend was $1.5B in 1H’21.  Similar level expected in 2H’21.
  • DVN: Q1 capex = $499M.  Q2 capex = $504M.  Q3 capex guided to $420M-$490M.  Full year budget stands at $1.72B to $1.98B.  Using mid-point suggests Q4 capex would come in around $400M.
  • GDP:  1H’21 capex = $46M.  2H’21 capex to range between $38-$42M.  Commentary suggests a Q4 slowdown.
  • GPOR:  1H’21 capex = $141M.  The 2021 budget is $290-$310M, thus ~$159M to be spent in 2H’21.
  • XEC: 2021 budget reaffirmed at $650-$750M.   1H’21 capex = $363M.  Implies 2H’21 spend of $290M-$390M, so flattish.

DEP E&P CapEx Observation.  One anecdote which we found hopeful.  This week we were discussing E&P capital discipline with a service company.  We noted the lack of movement in capex budgets and persistent chatter about discipline.  To this point, the service company indicated that commentary from E&P conference calls does not jive with customer inquiries from the field (i.e., field comments indicate an expectation to be much busier next year).  This reminded us of prior E&P comments regarding service costs.  Recall, in recent months we have made repeated references to both evidence and prospects of higher service costs.  Yet, go back to Q4/Q1 E&P calls and the consistent refrain from many was the expectation for flat service costs. In fact, some E&P players seemed defiant about potential increases.  Yet, on the Q2 calls the past two weeks, the discourse on service costs has changed.   Makes us wonder if a similar trend with respect to E&P capex could evolve in 2022.  That is, talk discipline now, but take up activity later.  On that point, ICD announced it will likely deploy another 2-3 rigs in early Q4 (+15-20%) while Ensign Energy Services, which is running 33 rigs in the U.S. today, will add ~6 rigs in September (+18%) and sees its rig count migrating to ~+/- 50 rigs in Q4 (+50% vs. today).  Time will tell, but comments from the land drillers would suggest we’ll see an uptake in drilling spending in 2022.  Question is whether this is just to replace DUCs or will we see a commensurate rise in completion activity as well.

E&P Activity / Efficiency Anecdotes:

  • WLL:  Running 1 rig today and going to 2 rigs before year end.  WLL had 1 completion crew which was dropped in May but returned in late July.  WLL will keep the crew through YE.  Company acknowledges some service cost inflation, but it is mostly offset by efficiencies.  WLL drilled 9 wells in Q2 and exited Q2 with 21 DUCS.
  • PXD: Avg 2021 Rig Count 22-24 rigs.  Will run 2 simulfrac fleets in 2H’21.  Generated $616M in FCF during Q2; accelerated first variable dividend payment to Q3 which based on Q2 FCF.  75% of quarterly FCF after the base dividend.  Reinvestment Rate of 50-60% at current strip.  Expected synergies from DoublePoint/Parsley deal are $525M.  D&C efficiencies improved as drilled feet per day is 65% better than 2017 averages while completed feet per day is 75% better when compared to 2017 averages.
  • FANG: Running 2 simulfrac crews and 1 spot crew.  Completing 2,800 lateral feet per day in the Permian. Reducing rig count and frac count the rest of this year but will add to activity next year.   Raised production guide in 2H21 and lowered capex.   $578M in FCF during 2Q21, paid down $600M in callable debt so far this year and expect to do another $600M by the end of the year.  Distribute 50% of FCF to investors in 2022.
  • EOG: 2021 Average drilling rigs at 22 (14 in Delaware, 3 in EF, 3 in PRB and 2 in other) and 2021 Average Completion Spreads at 8 (4 in Delaware, 2 in EF, 1 in PRB, 1 in other).  Mgmt commentary: “no growth until market clearly needs the barrels”. Raising FY well cost reduction target to 7%.  Days to Drill down from 17.1 in 2018 to 10 days YTD 21.  Completed lateral ft/day 1,030 in 2018 to 1,765 YTD’21.  Sand & Water Costs per Well $1.295MM in 2018 declined to $685k YTD’21.  Paid $600MM in Special Dividend in July 21’.
  • LPI:  Currently will run 2 rigs and 1 frac crew in 2022.  Activity is a bit higher today as the company wraps up work on the recently acquired Sabolo properties.  LPI owns a sand mine in the play and claims that wet sand mine reduces cost by $200k/well.  D&C cost/ft down from $788 in 2017 to $525 YTD21.   Company completed 16 wells in Q2.
  • MRO: Currently running 6 rigs today and 4 frac crews.
  • CPE:  Will run 3-4 rigs in 2H’21.  The Primexx acquisition will add an additional 2 rigs once the deal closes.  Excellent slide in Q2 slide deck.  Page 4 outlines activity metrics vs. budget.  Wish more companies did this. CPE has ~30-35 wells to drill in 2H with ~25 wells to complete.  CPE noted well completions will largely be in the Permian as 1H was weighted towards the Eagle Ford.   Company noted July production is up sharply from the Q2 average.  Focus of earnings call was on the Primexx deal.  Helpful slides on that as well.
  • PDCE:  Running 1 rig and one frac crew in the Wattenberg which allowed company to drill 23 wells and bring on 22 wells in Q2.  Company has 200 DUCs in the Wattenberg.  In the Permian, PDC is running one rig.  The company operated a frac crew during Q2 but released it.  In the Q2, PDC drilled 6 Permian wells and brought online 18 wells.  The company does not plan to bring back the frac crew this year.  Company noted plans to spend $75M over next the few years to P&A nearly 1,000 wells.  FCF is expected to average ~$800M in each of the next few years.
  • COP: Running 15 rigs (11 Permian and 4 Eagle Ford).  Running 7 frac crews (4 Permian and 3 Eagle Ford).  These levels are expected to remain consistent through YE.
  • CDEV:  Lateral lengths increased to 9,400 feet in Q2, up from 8,100 feet in Q1.  Spud-to-rig release declined from an average of 17.3 days in Q1 to 14.2 days in Q2, despite longer laterals.  Company announced a record having drilled a 22,500 foot well in 8.6 days in the Third Bone Spring Sand.   Increased FCF guidance for 2021 to $140M-$170M, up from $65M.  Company called out paybacks of less than one year.  Company is committed to maintaining its 2-rig program this year despite higher oil prices.  Company ran one frac crew in Q2.
  • GPOR: Drilled three Utica wells in Q2.  One with a lateral of 12,100 feet and two with 9,700 feet.
  • XEC:  Expects to run 5 rigs and 2 frac crews in 2H’21.  Feet drilled/day up 20% since Q3’20.  Averaging 1,513 feet/day.
  • CLR:  Current reinvestment rate is roughly 35% today.  Sees 60-65% as the right level.  Perhaps this means an uplift in 2022 spending may develop.  Expected to average 11 rigs in 2021 with plans to drill 210 gross wells.
  • DVN:  Intends to run 16 rigs the balance of 2021 and bring 150 new wells to production in 2H.  Roughly 80% of the company’s 2021 budget is allocated to the Delaware where DVN is running 13 rigs and 4 frac crews.  DVN also running 2 rigs in the Eagle Ford.  Reported record drill times in the Bone Spring and Wolfcamp formations with spud-to-release times of less than 12 days.  Completion activity delivered 2,000 completed feet/day.   DVN noted rates of return for some wells around the Cotton Draw/Stateline area have 200% returns at today’s strip pricing.  YTD debt reduction totals $1.2B.
  • ESTE:  Running two rigs and one frac crew.  Will run 2 rigs in 2022.  May evaluate the third rig.  FCF in Q1 = $28M with 1H’21 FCF = $60M.   All-in costs/stage were $38k in Q4’20 but guided to $40-$45k in 2021.  Wells per pad will average 3.0 to 6.0 in 2021 vs. 4.5 in 2020.   Lateral lengths earlier this year averaged 6,800, but new wells targeting 9,000 feet.
  • CRK: Running 5 rigs for the balance of the year.  Dropped a rig back in May.  Recent wells turned to sales have had an average lateral length of ~8,251 feet.  FCF of $20M in Q2 with YTD FCF = $53M.   Will utilize a BJ Titan fleet in early 2022.
  • APA:  Added a second Permian rig in June.  Feels like they may go to three rigs before YE.
  • SBOW:  2021 budget includes 18 drilled wells and 20 well completions.  Lateral feet drilled/day is 1,225ft YTD vs. 1,020 in 2020.  Company recently drilled a four-well Eagle Ford pad in 25 days or ~6 days/well.  Completed lateral feet/day improved to 2,229ft YTD vs. 1,848ft in 2020.  The company will likely run a rig for ¾ of 2022 with 2022 production expected to grow 10% y/y.
  • PVAC: Will maintain 2-rig program.  Used Simulfracs for Q2 completions.
  • NFG: Running 2 rigs and 2 frac crews.  Marcellus player.  Will likely bring activity lower in late FY’22 (fiscal year ending 9/30).

E&P Dividends / Cash Returns to Shareholders. A few examples of E&P’s increasing cash returns to shareholders.  Those who did not increase dividends largely witnessed strong FCF which was used to reduce debt.  What’s crystal clear is the FCF generation in the E&P space will allow (i) large returns to shareholders and/or a (ii) purification of the balance sheet as industry leverage ratios drop with improved capital structures.  Not our investment advice, but a recognition of the radically improving health of this upstream sector.  Also assumes a respectable commodity price environment persists.

  • PDCE: Paid the company’s first quarterly dividend in Q2 and repurchased $26M of stock.  $60M has been returned to shareholders YTD with $180M+ expected in 2021.
  • ERF: Resumed dividend and increased it by 15%.


  • EOG: Paid a $600M special dividend in July.


  • MRO: Raised quarterly dividend by 25%.  States it will generate $8B in cumulative FCF through 2025 at $60 WTI and a 40% reinvestment rate.
  • CLR:  Increased its dividend.
  • DVN: Increased its fixed-plus-variable dividend by 44%.
  • FANG:  Increased annual dividend by 12.5%

OFS Observations:  Like an airplane running out of air speed and altitude, we crashed this weekend and failed to get through all the OFS earnings (have to take the bride out for an anniversary dinner soon).  What is important to note is virtually every OFS earnings call discussed service pricing.  Point is it’s going up.  Some increases are cost recovery while others are net gains.

  • Here’s a reason why OFS consolidation must occur.  MRO’s CEO on its Q2 call: “As I’ve said many times, our budget is our budget; and we won’t raise our spending levels with stronger commodity prices but will simply generate more FCF”.
  • SND: Tons sold were 767,000 in Q2 vs. 760,000 in Q1 with revenue up 8% q/q.  Q2 contribution margin came in at $4.55/ton, up from $1.36/ton in Q1.  Balance sheet improved given the recent settlement with USWS.  SND now has cash of $37M.  Guidance indicates a q/q decline in volumes of 10-15% due to timing of well completions.  The slowdown somewhat mirrors the E&P capex commentary above as we are now seeing a number of E&P’s guide to flat-to-down spending in Q3/Q4.  That said, in the SND Q&A it did note a potential uplift in Marcellus activity in Q4.  Important to note, SND believes Q3 contribution can be maintained in the mid-single digits in Q3 despite a potential volume decline.
  • PUMP:  Effective utilization in Q2 was 13.1 fleets.  Company intends to have 13 active fleets in Q3.  Q2 revs = $217M, +34% q/q.  Adjusted EBITDA = $36M vs. $20M in Q1.  Implies about $11M in annualized adjusted EBITDA/fleet.  PUMP does capitalize fluid ends.  If one assumes $5M in Q2 (company had loss of disposal of assets = $15M, thus we take a 1/3 for fluid ends), the implied annualized EBITDA/fleet is closer to $9.5M.  CY’21 capex guided to $115M to $130M which includes $37M for 90,000HP of Tier 4 DGB equipment.
  • NINE:  Revenue = $85M in Q2, +27% q/q.  Q3 expected to range between $95M-$103M.  Hats off to company for specificity on pricing, announcing its targeting net pricing increases of 10-20% in cementing and net increases of 8-12% in coiled tubing.  Will begin to test pricing for wireline and other services in 2H’21.  While our E&P friends may tire of our OFS pricing bantering, the key to a healthy service industry is to let the service industry generate a fair return.  To date, most OFS players have opted for market share, not returns.  Most deflect questions on pricing due to competitive reasons.  NINE’s Q2 adjusted EBITDA was slightly negative so the price increases are warranted.  Also, positive commentary regarding NINE’s dissolvable plug segment (composite plug sales up 42% q/q).  ESG benefits on the dissolvable appear to be gaining customer interest.
  • FTSI:  Revenue = $100M vs. $96M in Q1.  Adjusted EBITDA = $14M vs. $8M in Q1.  Active fleets remain at 13 with effective utilization of 11.8 fleets in Q2.  Annualized adjusted EBITDA/fleet improved to $4.7M vs. $2.6M.  Company will build a Tier 4 DGB fleet for $26M.  Fleet will go into service in early 2022 and is supported by a contract.  FTSI averaged 16.9 pumping hours/day in Q2, a +6% improvement over Q1.  Price increases are underway.  2021 maintenance capex = $30M-$35M with about $15M of growth capex.  Cash = $99M with no debt.  No incremental fleets likely deployed in 2H.
  • ICD:  Running 15 rigs with 2-3 rigs going back to work in early Q4.  All rigs on short-term contracts thus can reprice early next year.  Company was negative EBITDA in Q2 but sees positive EBITDA in Q3.  Spot dayrates for the company’s 200 series rigs in the $16-$17k range while rates for the 300 series rigs are in the upper teens.  Dayrate bias is higher with rates in the 20’s once early 2022 starts.  Cash margins in Q3 are expected to be in the $3,700/day to $3,900/day range.  Another $500,000 is expected to be incurred for the start-up of the next 2-3 additional rigs.

Random Midland Observations.  While this past week’s Permian trip was tied to our ChampionX tour, we did squeeze in a few other meetings.  Two things stood out: (1) COVID is impacting both OFS and E&P’s with multiple anecdotes of work-related impacts.  The labor shortage and COVID are not a good mix.  Would not be surprised to see this be a headwind for Q3 earnings if the outbreak persists; and (2) it’s clear that vacation season is upon us as there were no shortage of rental cars available; plenty of seats on the flight; our hotel rate was $106/night and Wall Street was at ~50% capacity.

As usual, no stock opinions or investment recommendations from us in this note….just some industry color and our observations.  Take them for they’re worth.


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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