We recently returned from our 10th trip this year to the Permian – getting in and out before the winter weather excitement.  The good news is an expectation for continued activity growth, best characterized as stable-to-slightly improving.  Several companies report more populated Q1 calendars vs. expectations for greater equipment deployment, thus the overall business from a utilization perspective is trending up.  In some cases, companies are now being more selective on inbound work requests.  Several frac companies report customers wanting short-term work.  To the extent availability in the calendar exists, these companies will seek to squeeze the customer in, but without dedicated utilization (generally described as six months of work), several contacts are reluctant to reactivate more equipment at current pricing/returns.   These comments mirror what we heard on our East Texas trip about ten days ago which is a further indication, we hope, the OFS sector is transitioning from a market share mentality to returns mentality.  Not terribly different from E&P’s who have already transitioned to a returns/cash flow focus vs. straight production growth.

 

Oil Service Pricing is Nuanced.  Lots of questions about OFS pricing, particularly given our reports of recent efforts by some industry constituents to raise rates.  Let us first begin by stating the obvious which is pricing depends upon product line, customer mix and region.  While there are some companies who claim success raising rates and who expect further increases, there are others within the exact same service line who have seen no improvement and who see no near-term upward movement.  We heard this on our Permian trip this week, prompting us to dig into the perceived discrepancies.  Let’s us explain with a simple example.  First, assume there are two completions-oriented companies.  Each was charging $20,000/day in January 2020.  Following the Saudi/Russia tiff and the initial fears of COVID, oil prices fell rapidly and customers collectively asked for pricing concessions.  Both companies gave a 20% break, so now pricing is $16,000/day.  Industry activity subsequently collapses and all equipment goes to the yard.  By summer, however, a few E&P’s opt to complete DUCs so work is put out for bid.  One of our two companies, we presume, is focused on equipment utilization to cover fixed costs thus it bids aggressively and prices work at $12,000/day.  The other competitor prefers to avoid the bidding as it waits for its dedicated customers to resume work.  So now, one company is working for $12,000/day and the other is not working, but has a stated rate with its customers for $16,000/day.  Over the next several months, completion activity rises.  More calls come in and by the end of the year, the company who bid $12,000/day for the spot work is now bidding $14,000/day and winning.  It correctly reports a ~15% price increase.  The second company, meanwhile, begins redeploying crews with its pre-activity collapse customer base.  Those customers bring the equipment back at the $16,000/day.  Purportedly, the customers don’t bid this work out as they are comfortable with the service provider’s crews/performance.  The company at $16,000/day is not necessarily crushing it financially, but for now, the $16,000/day is sufficient.  The other company meanwhile sees further opportunities to raise rates and sees near-term opportunities to return pricing to the $16,000/day vicinity.  Neither company, however, sees a near-term opportunity to restore pricing to the pre-COVID levels of $20,000/day, but both hope to be there by year-end 2021 should commodity prices cooperate.

 

Yes, this is an overly simplistic example, but it helps explain why some E&P’s and service companies might claim service costs are rising while others will claim it’s not.  For purposes of the example above, we made up numbers, but in our discussions with select OFS contacts, actual numbers were shared.  We simply present a hypothetical scenario.

 

In our note last Sunday, we referenced positive pricing traction in well servicing and frac, but not wireline.  During our Midland trip, we had the chance to visit with a wireline friend.  This company reports pricing taking another step lower in Q4.  The company, like most, dropped pricing in early 2020 in response to softening oil prices.  The company then maintained that pricing until RFP season.  As this contact is perceived to be a strong player with a good customer base, it did not anticipate having to move rates lower.  However, during the RFP season, long-term customers approached the contact, notifying them of the pricing landscape.  In order to keep the work for 2021, our contact was forced to lower its rates.  Again, OFS pricing is nuanced.

 

Permian Frac Crew Count:  Local contacts report an active crew count of ~70-74 crews spread across ~18 frac companies working for ~45 E&P companies.  As we conducted our channel checks, we believe the Permian active count will approach ~76 fleets in early January.   Assuming local contacts are directionally correct with their reporting, there are ~9 E&P companies running frac crews with no rigs while there are now ~19 E&P’s running rigs, but with no frac crews.  Recall from a late September note when we reported a total of ~17 E&P’s running crews with no rigs, but only four with rigs, but no crews.  Our comment then noted the trend of E&P’s bringing back crews to complete DUCs.  We also observed the need to eventually add rigs or else a potential correction in completion in activity could unfold.  What has subsequently occurred is a ramp in drilling activity to replenish well inventories.  Moreover, the fact that there are more companies drilling vs. running crews indicates an eventual need for those E&P’s to pick up a completion crew.

 

U.S. Frac Crew Count:  We spent our New Year’s Eve day reaching out to industry contacts to update our U.S. active frac crew tally.  Based on industry discussions and feedback from contacts, we believe the U.S. active frac crew count is roughly ~177 crews.  We acknowledge there are a few educated guesses on our part, so give us a +/- 5 crew wiggle room.  Remember, our tally is “active” and not “effective” as on any given day a frac crew could be in between jobs.  Also, our tally includes some companies who presently have crews running on vertical wells.  This is a very small component of our tally and we suspect these crews might not be counted in other tallies.  Also, as we reached out to industry contacts, we know a few fleets counted in this tally are fleets going to work this week.  Our regional breakdown is provided below.

 

 

U.S. Land Rig Count:  The BKR U.S. land rig count climbed +3 rigs last week, ending 2020 at 332 rigs.  This represents an increase of 101 rigs from the August trough.  For the quarter, the BKR land rig count was up ~24% q/q.

 

DEP Land Rig Forecast:  A bit of horseshoes and hand grenades, but here’s our take on U.S. drilling activity.  Note the near-term forecast hasn’t really changed since we last updated it in November.   We assume a ~20% q/q improvement in Q1, an assumption based largely on reported rig inquiries from private drilling contacts.  With oil prices still range-bound between $45-$50 WTI, we would envision the U.S. rig count (per BKR) migrating into the ~400 vicinity in the coming months.  Low 400’s feels reasonable in a ~$45 WTI world with potentially high 400’s if the strip reaches ~$50 WTI.  Our multi-year forecast is largely assuming a mid-$40’s environment near-term with a return of industry cyclicality in the out years.

 

 

 

DEP Frac Crew Forecast:  Like our rig count forecast, our frac crew forecast is more art than science.   We model a Q1 average crew count at ~170 fleets.  Even though our active count is presently ~177 fleets, we employ a slightly lower number to reflect effective fleets.  Our forecast assumes a y/y improvement in 2022 vs. 2021, but another industry slowdown in 2023/2024.  This is clearly a wild-ass guess, but what seems apparent in recent years is the reality of shorter-cycles.  Also, we can’t in good conscience present a forecast which shows a five-year up-and-to-right improvement when we all know that probably won’t be the case.  Nor is the concept of a “stable” forecast as stability and the oilfield are not synonymous.

 

 

Frac Capital Equipment Thoughts.  Fleet cannibalization will persist in 2021 as will companies announcing fleet retirement programs.  Here’s a telling example.  We updated with one contact who acknowledges its fleet profitability continues to hover around breakeven.  The company’s fleet has units with engine life averaging 12,000+ hours.   Recall, most engines generally are ascribed an engine life of ~12,000 to ~15,000 hours.  Variability in useful life is typically associated with one’s maintenance programs as well as the type of work performed.  Our contact expressed concern about 2021 as the working fleets are running all-out.  Lots of pumping/hours per day means more wear-and-tear.  A new engine may cost as much as $450,000+ assuming one opts for a Tier 4 dual fuel solution while a rebuild will be closer to ~$300,000.  Neither option is really affordable when the fleet level EBITDA hovers around break-even.

 

Fluid end demand will rise in 2021 as well. We believe some companies leaned heavily on robbing fluid ends from idle units during the past few quarters.  According to contacts in the forging business, orders for blocks are up sharply.  This means fluid end OEMs are seeing more demand (or at least expect more).  For the frac company, the fluid end is an expense, thus margin pressure, all else being equal, seems a reasonable assumption should pricing not materialize.  In other capital equipment news, field contacts claim a new Tier 4 dual fuel fleet from one of the equipment packagers has just been bought.  We suspect this will be a replacement fleet vs. an expansionary fleet.  Look for 2021 to be the year when frac providers test new pump and power solutions with orders for new fleets materializing later in the year.  Our prediction is at least ~10-12 electric / ESG friendly fleets are ordered this year while Tier 4 dual fuel upgrades/conversions accelerate.  Larger E&P’s where ESG is a focus will increasingly drill down into the engine/power source as part of frac RFP’s.

 

DEP 2020 Review:  We would like to thank all those companies who graciously stepped up to support Daniel Energy Partners via a formal paid subscription this year.  Your willingness to help is very much appreciated.  Frankly, your generosity provided the necessary ingredient (i.e. money and confidence) for the firm to have a successful launch in what was an otherwise awful year.  With your support, DEP has grown from one employee to four.  Further, during the year the DEP team conducted ten Permian tours, four East Texas tours, three Oklahoma tours, two Bakken/PRB tours, multiple visits to the DFW area and one trip to Pittsburgh.  We are very strong believers in field research and, perhaps call us old school, but we still like face-to-face meetings.  As a former wise boss once told me, trust but verify.  That’s a core tenet to our research philosophy which is why we opt for windshield time vs. excel modeling.  Interestingly, a quick glance at our Hilton Honors account activity indicates we spent 93 nights on the road during 2020!  Not too shabby (admittedly some of this was personal, but still…).

 

The financial support from those who are kind enough to formally subscribe to our services will allow DEP to host multiple industry events in 2021, including our THRIVE Energy Conference & Expo at Minute Maid Park in February as well as our Permian Basin BBQ Cook-Off in September (we still have a few cooking spots, but they are going fast and are only open to subscribers).  In our opinion, these events, as well as our golf outings, regional dinners/BBQs and other small group events, are fantastic forums for industry and investor networking.  To the extent our research helps you, that’s great, but we strongly believe our events can help you learn about trends in the business, save money, and/or meet new contacts/customers, thus potentially allowing you the chance to grow your business.  There’s value to that.  Finally, for those readers who have yet to formally subscribe, but who enjoy our notes/events, we hope you will consider a formal subscription.  We could really use the support and like you, we can’t give away our product for free, thus the time to prune our distribution list is rapidly approaching.

 

Thank you and we look forward to a fun and improving 2021.

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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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