Thank You.  The DEP team would like to thank all of our industry friends who came out to support us at the Permian Basin BBQ Cook-Off.  We had approximately 2,300 registered attendees with actual onsite participation closer to 1,800 guests.  We know all of you are very busy folks, but your presence, as well as your sponsorship support of the BBQ Cook-Off, is greatly appreciated, so thank you.  We are targeting September 29, 2022 as the day for next year’s event, so please save the date.

As for the final rankings, here’s the top three plus DEP.  What we can see is that each year we add more cooking teams, DEP keeps moving further down the list.  Next year, we may have just one team compete so we can win.  As a reminder, the event featured 54 competing teams.

Rank Best Overall
1 BEST Pump & Flow
2 Signal Peak Silica
3 Universal Plant Services
38 DEP
Rank Best Ribs
1 FTS International
2 BEST Pump & Flow
3 Universal Plant Services
43 DEP
Rank Best Brisket
1 Stallion Oilfield Services
2 Solaris Companies
3 BEST Pump and Flow
31 DEP

DEP Update.  We will be in Houston the next two weeks.  Objective is to squeeze in a bunch of local meetings, but we return to the Permian for the Permian Oil Show on October 18th.  Also, the DEP Houston golf outing is moving to November 10th vs. the original October 20th date which conflicts with the Oil Show, hence the change.

RNGR/BAS:  On Friday, RNGR announced the closing of its purchase of the BAS assets (excluding water logistics and California).  The purchase price was $36.65M cash.  Tomorrow morning, RNGR will host a conference call to discuss the transaction, thus an opportune time to hear RNGR’s views on the broader well service market.

BKR Land Rig Count:  Up 4 rigs to 513 rigs.  Gains largely confined to the Permian.

Land Rig/Casing Thoughts:  Something we are just starting to dig into is the potential for casing shortages to impede incremental rig activity.  We have heard multiple anecdotes from various industry sources regarding the challenges with casing, including production tubing.  What prompted us to start an initial inquiry was a report from a private frac company about a fleet sitting idle due to casing issues with its customer.  Essentially, casing was delayed causing the E&P to keep the fleet on unpaid standby.  Subsequent to this anecdote, a land drilling contact conveyed a concern regarding the prospect for further rig count growth given growing casing challenges.  These two observations, both unsolicited, necessitated our initial inquiry to E&P friends on Saturday as in most cases they procure casing services directly.  Feedback is less dire than what we expected, but all contacts offering feedback note the problems are real.  First, casing costs are up materially for some E&P contacts with one reporting price increases of 30-40% since the market trough (and not abating).  Another claims increases of closer to 15% on a y/y while a third has seen a +50% increase.  The problem, most believe, is a function of domestic mills not running at capacity along with shipping delays/issues from foreign mills.  Larger E&P companies with dedicated programs generally buy casing months in advance with most conveying a sense of security through Q1/Q2 of next year.  Purportedly, the mills and distributors are more inclined to grow with existing customers.  A number of contacts believe small E&P companies who simply wish to prosecute short-term projects could see access issues on casing.  Too early for us to have a definitive view on this matter as we have limited feedback given our inquiries went out on Saturday, but the concerns are nonetheless worth digging into.

Perspectives on the U.S. Frac Market:


Summary:  We believe the U.S. frac market has reason to cheer as 2022 approaches.  The market is tightening and will tighten further.  Customer appreciation and demand for emission-friendly equipment is growing and this segment of the frac market is essentially sold-out.  Consequently, healthy price improvement, particularly on incremental upgraded spreads, is emerging.  Moreover, industry consolidation seems poised to continue as several small players acknowledge a desire to sell while larger players acknowledge a desire to consolidate.  Frankly, this has been the case for months, but sellers don’t like to sell at the bottom, nor do buyers like to issue equity at subdued prices.  With balance sheet cleansing largely behind us and equity prices rebounding, the time to tango would seem to be now. Of course, reasonable minds need to agree on valuation – not always easy, but where there is a will, there is a way.  The challenge, however, is some sellers have legacy equipment which is not what public buyers wish to acquire.

One reason for consolidation is a tightening market and firmer pricing will lead to some new frac entrants.  Not huge numbers at this point, but the formation of companies is happening.  Previously, we were first to highlight Straitline, Express and Pharaoh.  The latest is PureFrac, a pure-play Permian frac provider which has amassed 125,000hp thus far, much of which is going through the rebuild process now.  It is our understanding the company should commence its first frac operations in November.  For now, we are not tracking any other emerging companies, nor have builders implied any realistic new entrants are a near-term threat.

Current Market.  We believe the U.S. “active” frac crew count is approximately 220-225 fleets.  We further believe the “effective” or working fleet is closer to 200-210 crews on any given day.  Our tally is a bottoms-up approach involving channel checks with frac companies and vendors to the frac space.  Distinguishing between “active” and “effective” matters as we occasionally find cases of companies having an actively marketed crew which is not working.  Case in point, we visited with one frac company who regularly shares its working/active crews.  In August, for instance, 100% of that company’s capacity had been “active” but temporarily not working as third-party contractor issues prevented the E&P from bringing out the crew as planned.  As this happened unexpectedly, the frac company was not able to reposition the crew for short-term work to fill the gap, thus it sat idle.  Seeing these instances in public company reporting can be hard as it gets lost in the noise, but granular comments from smaller private companies often illustrate the on-the-ground realities.  Therefore, when we hear of others reporting 260+ working crews, we scratch our head as our field level checks simply can’t get to those figures.

Perhaps one of the biggest misperceptions is the amount of readily available supply of frac equipment.  Part of this problem is a function of research folks like DEP.  Here’s why.  First, most frac companies report total fleet horsepower owned.  Yes, a couple still limit disclosure, but we believe reasonable guesses and field discussions put us in the ballpark.  Tallying up these disclosures and our assumptions puts total U.S. horsepower at roughly 20.8M (which includes ~1.5M horsepower from shutdown companies).  Conventional wisdom historically assumed ~50,000hp per fleet for a horizontal spread.  Smaller vertical spreads might require as much as ~20,000hp.  To keep it really simple, we assume everything is horizontal thus implying a total supply of ~415 fleets.  Based on the DEP estimate of 220-225 active fleets, our total supply estimate would imply utilization of 53%, a level well below the often quoted 80% utilization threshold necessary to obtain pricing power.

However, the above monkey math is borderline worthless as a substantial majority of the idle horsepower is not operable without some form of capex.  And, assuming capex dollars are spent, finding crews is not easy.  In fact, it’s darn near impossible.  Organic recruiting and training take time while poaching employees can be expensive.  One Oklahoma frac contact just lost employees to a Texas competitor for $30/hour.  Consequently, frac friends generally estimate the time required to reactivate and deploy a fleet is somewhere in the vicinity of 2-3 months.  That begs the question, what is the true supply of readily available equipment?  It also begs another question which is why do public frac companies keep reporting elevated frac horsepower totals?  Why not simply be bold and state a formal plan to retire even more capacity?  Frankly, we struggle to quantify the first answer, but virtually all frac companies tell us the idle, but ready to work equipment is essentially nil, a key reason why incremental fleet deployments are generally securing higher pricing.  Remember, higher returns are needed to justify the investment to transition stacked equipment to work ready status.  Yes, a soft answer with no excel support, but we speak to many companies, and few have fleets just sitting ready to go. This leads us to believe we are effectively sold out of workable equipment with crews.

Another reason the monkey math is misleading is the reality that many of the smaller frac companies are generally sold-out.  Yes, some are able to chase short-term spot market jobs, but these companies, unlike their larger public peers, generally don’t have idle fleets to bring back.  Therefore, increasingly the swing capacity rests with the basket of public companies or with those companies willing to buy assets from recently shutdown companies such as BJS, Legend, PumpCo, etc.  If one steps back and understands where the swing capacity really rests, to us, at least, it makes even more sense for public-on-public M&A.

Finally, the historical view on fleet size is becoming less relevant given the rise of simul-fracs which might take as much as 1.5x the capacity.  Check out the Simul-Frac teach-in slides on Patterson-UTI’s website. Also complicating matters is the fact that during the downturn, frac companies often allocated more capacity to jobs – either to pump at a lower rate/unit to maximize fleet life or to simply have redundant capacity on location should a failure occur.  Collectively, these scenarios are mean more pumps on location so the use of ~50,000hp per fleet might be too generous.  Take the 50,000hp figure to 60,000hp and the potential supply of total fleets swiftly declines from 415 to 345.  Again, these numbers don’t really matter given our aforementioned bloviating on lack of crews and poor equipment quality.

DEP Outlook.  Our forecast is based on a combination of our recent E&P survey from ~2-3 weeks ago along with our gut.  Recall, the survey suggested active frac crew counts should rise by 20-25 fleets in 2022, a +10% improvement relative to our view on working fleets today.  As a reminder, we surveyed just over 50 E&P companies who collectively operate ~55% of the U.S. working frac fleet.  That said, we also lean on our gut which tells us a CY’22 price deck of ~$70/bbl and ~$4.00/mmbtu will lead to more growth; therefore, we are inclined to take the over relative to our survey and instead model an improvement of ~30-35 fleets, or ~15%.  The difference really isn’t that material, but a takeaway from our Permian BBQ is a bit more willingness to accelerate spending.  Now, this does not mean the E&P industry will go morally casual and spend recklessly, but the uplift in free cash flow should this price deck persist is consequential, thus more money will be available for the drillbit.  Near-term, concerns about Q4 seasonality are fading, but most companies still do not foresee a big uptick in unit counts in Q4.  Right now, we would peg a Q4 fleet average likely in the 220-225 range – strong October with a softer 2H December but ramping again in Q1.  Good news is Christmas and New Year’s fall on a Saturday.

New Capacity. The industry is far from a newbuild boom, but there is a smattering of expansion-related activity underway.  In essentially every case, the orders are either (1) electric; (2) direct-drive turbine and/or (3) Tier 4 Dual Fuel.  On the latter point, we refer to Tier 4 Dual Fuel as there are two Tier 4 dual fuel solutions – the CAT Tier 4 DGB, but also the Cummins QSK50 which was officially announced by Cummins on September 28, 2021.  In addition, it is our understanding Cummins offers an option that can take a Tier 2 engine to a certified Tier 4 dual fuel solution at a lower cost than purchasing a new Tier 4 dual fuel engine – an interesting option for those with legacy equipment.

Based on our newbuild tally, we envision 22 new, incremental emission-friendly fleets before year-end 2022 (this does not include Tier 4 dual fuel upgrades of legacy capacity which most likely exceeds 20 fleets before YE-22).  Given the continued transition to emission-friendly equipment, we do not view these fleet introductions as a headwind to the broader market, at least not yet.  The unfolding industry bifurcation is real and newer fleets will have both a price and utilization advantage.  Moreover, the demand for emission-friendly equipment and/or fleets which can deliver higher diesel substitution rates will grow.  We submit this trend is a key reason why NexTier acquired Alamo in August.  Furthermore, we envision more industry M&A which will help offset incremental fleet creep.  It is important to note, however, the number of fleets undergoing upgrade process will likely accelerate as more E&P’s will transition to dual fuel capability.  Again, as the frac industry pursues upgrades, we do not necessarily see all of these as incremental, but in most cases, we see them as end-of-life upgrades.  Nevertheless, this should be a specific question directed to each frac company during Q3 earnings.  Case in point, in recent weeks we have witnessed announcements by companies such as PUMP and Trican announcing fleet enhancement programs.  In the case of PUMP, the company announced the purchase of 50 Tier 4 Dual Fuel Engines.  Trican, meanwhile, announced it will pursue its second Tier 4 dual fuel upgrade while during previous earnings calls we have witnessed FTSI, LBRT, NEX and PTEN all cite Tier 4 dual fuel upgrade plans.

Pricing.  Commentary is mixed, but most frac companies claim pricing is moving up, but essentially all agree it moves higher in 2022.  Here’s the way we think about it.  First, the market is bifurcated.  Emission friendly fleets are earning a price premium relative to legacy fleets.  Most everyone understands this by now, so this is not a wow moment.  But virtually all frac friends agree current pricing for legacy equipment remains well below pre-COVID pricing.  However, many frac companies upgrading fleets today anticipate pricing returning to at or near pre-COVID levels once these fleets are deployed.  A few anticipate pricing ahead of pre-COVID levels next year, but this is the minority view.

Here’s another way to think about this.  Sophisticated companies have a targeted payback framework before incremental capital is spent.  Two have shared a view the cash-on-cash payback must be under a two-year framework while another contact claims just over one year.  We can agree to disagree on the right framework, but let’s use these ranges to see what it means.  Let’s first assume a frac company wishes to do a Tier 4 Dual Fuel conversion.  Equipment fabricators tell us the cost on just the trailer is likely $800,000 to $1.0 million.  Yes, the engine cost is less, but the conversion process also requires updates to other equipment on the frac trailer.  If the frac company cost achieves an $800,000 per trailer cost, a full 20 pump fleet would cost about $16M.  An EBITDA payback of one year implies annualized EBITDA/fleet of ~$16M which in our view is not likely today, but a payback of 1.5 years to 2.0 years implies annualized EBITDA of $8M to $12M – that seems much more reasonable.  One frac company tells us it requires at least $10M of EBITDA/fleet to prosecute a full Tier 4 dual fuel conversion, so we are in the ballpark (at least with him).  When one considers most public frac companies reported Q2 annualized EBITDA/fleet and/or gross profit per fleet metrics in the mid-single digits or less, our simplistic math exercise above implies higher pricing will be required to justify investment.

Take this one step further.  Let’s assume a Midland Basin frac fleet charges $6,500 per pumping hour or low teens on a per stage basis.  On average we’ll assume the fleet pumps 18 hours per day and works 26 days per month.  The annualized revenue, assuming no downtime, holidays or weather impacts, would be about $37M per year.  Now, let’s assume a customer seeks a Tier 4 dual fuel conversion which could potentially require a $16M upgrade cost.  Again, using very simplistic math, the incremental price necessary to achieve a 2.0-year EBITDA payback is ~22%.  That assumes 100% of the price increase drops straight to the bottom line.  The reality is not all of the increase will, so a price increase of greater than 20% is warranted.  Moreover, if a company is steadfast in achieving a shorter return threshold, the price increase must be even higher.

To the extent one thinks our assumptions are crazy, that’s fine, but consider the recent comments by ProPetro, Trican and FTS International as it relates to their Tier 4 upgrade spending.  As the table below illustrates, the implied cost per trailer is much higher than our assumptions, perhaps a function of these companies doing more than just upgrading the trailer (i.e., new blender, data van, tractors, etc.).

Company Date CapEx Units Cost/Unit
ProPetro Services 9/29/2021 $74,000,000 50 $1,480,000
Trican Well Services (1) 9/13/2021 $22,222,222 16 $1,388,889
FTS International 8/5/2021 $26,000,000 20 $1,300,000
(1) U.S. dollar estimate using the USD/CAD exchange rate of $1.26 as of 9/30/21.  
Source: DEP estimates, company press releases    

If these companies employ return thresholds in the ballpark we mentioned above, just eyeballing the total capex per fleet comfortably puts necessary annualized average EBITDA/fleet in the low-to-mid teens, arguably a level to justify these investments.  Relative to the broader market vis-à-vis Q2’21 results, that’s a big increase which we submit is price driven – a reflection of the sold-out market for emission-friendly equipment.  These returns are the reason we expect more fleet upgrade announcements in the coming months.

Other Random Considerations:  Couple things to consider these days.  First, the rise in Haynesville activity is both a blessing and curse.  Recall, the high-pressure nature of the Haynesville creates significant equipment wear-and-tear challenges, particularly for fluid ends.  For frac companies, the wear-and-tear is an addressable challenge which can be solved with higher pricing, but in the short-term, long lead times for equipment may create some short-term challenges.  For OEMs, the rise in Haynesville activity is a blessing.  Second, frac companies report acid shortages with some jobs being missed due to a lack of acid.  Third, an operator reports pricing for vertical frac work in the Permian is up materially – most likely because the big frac companies tend to chase the bigger work.  Fourth, one company sees sand shortages in the Permian unfolding in October – haven’t checked in with sand companies on this yet but will this week.

As always, this note is not intended to provide investment advice or stock recommendations…it is simply our views as we sit here on a Sunday evening recovering from too much BBQ and beer earlier this week.


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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