When headline OFS & EP energy news is light, as was the case this past week, sometimes research folks have to work a bit harder to find newsworthy material.  On that point, DEP took to the streets to chat with frac contacts in order to uncover new business trends.  Pay attention to the anecdotes in this note.

  • New Frac Technology Keeps Coming
  • FTSI Bankruptcy Thoughts
  • BKR U.S. Land Rig Count Flat this week

New Frac Technology:  Call us crazy, but we believe the domestic frac market is about to be redefined once again.  Years ago the last redefinition process began with the advent of electric frac technology, but stalled due to depressed industry returns and low commodity prices.  Now, like a phoenix rising from the ashes, a new transformation is accelerating as power generation is likely to begin its transition from the frac company to the E&P and third-party rental companies.  This will necessitate new fleet designs and create a platform for new frac companies.  Let us explain.

First, as we previewed in an earlier note, we are digging deep into the concept of gas gensets becoming a key power source for the U.S. frac market.  This would be either an alternative or additive to the current use of turbines.  Our comment prompted inbound calls from numerous industry parties – some wanting to know more about this topic with others sharing how they expect to participate in the trend.  In keeping with our modus operandi, we won’t disclose names, but here are some quick takeaways as our diligence continues.

With respect to gensets, our impression is two of the leading engine players are taking the lead on this: MTU and CAT.  First, the use of gas gensets is not new.  They have been used with land rigs for some time.  MTU, for example, has built and deployed over 3,000 gas gensets, although the genset, to date, has not been used to power a frac fleet.  This is expected to change as MTU recently developed its Hybrid Electric Frac design which uses its 20V4000 Gas Genset (CAT provides its G3520 2.5MW genset).  The MTU concept is simple and can be designed whereby the E&P and/or power rental company buys a package of the 20V4000 gensets or a frac company could install the genset on a trailer alongside a power end.  Interest in the design is building and we suspect at least one MTU Hybrid design could hit the market later this year with more to follow in 2021.

An advantage of the MTU genset concept is its ability to use flare gas as well as pipeline gas.  Moreover, multiple industry contacts claim gensets do not have the same derating challenges that turbines might face in certain operating conditions.  With the MTU design, a hybrid fleet would use anywhere between 6-8 20V4000 gensets.  If installed on a trailer, we understand the power end employed on the trailer would be one of the larger 5,000HP designs.  Of course, if the E&P or a third-party rental company opted to buy the gensets, the frac company would employ a different trailer design which we discuss below.

A key benefit of the genset is a longer expected life and purportedly lower maintenance expenses.  OEMs contend the genset has nearly 4x the life of the traditional frac engine as the first major overhaul is advertised at ~80,000 hours.  The per unit cost is not cheap, but when packaged as an electric fleet, the all-in cost is not offensive given the need for less frac trailers relative to today’s conventional design.  Namely a genset may run $1.1M to $1.2M but an all-in cost of a Hybrid trailer would range anywhere in the $2.3-$2.8M ballpark.  This compares, we believe, to a conventional Tier 4 trailer in the $1.3M vicinity.

As the power transition process unfolds, so too will frac fleet designs. Consider this scenario.  Let’s assume the E&P or a newly-created rental company purchases either turbines or gas gensets to provide power.  The frac company no longer needs the traditional engine, transmission, radiator set up.  Rather, it would require a trailer with an electric motor, VFD and pump (power end/fluid end).  The trailer, which would need to be built new, could be designed to have either two 2,500hp pumps or a 5,000hp pump.  Estimated cost for this trailer package according to contacts could run into the low-to-mid-$20M vicinity.  Call it $2.5M per trailer with up to eight trailers.  This compares to the traditional 16-20 conventional trailer concept which would run as much as $28M (both excluding blenders, data van, etc.).  Under our new design concept and assuming the power is generated remotely and wired into the pad, the implication is a smaller wellsite footprint.  With the push for automation simultaneously evolving, the new fleet design would most likely require fewer people.  According to contacts, the new designs are anticipated to offer lower operating costs.

The transition of power generation away from the frac provider also means a large portion of the installed base of frac equipment will become obsolete, in time.  The parallel is the land drilling market.  Think mechanical rigs followed by a transition to SCR followed by an eventual transition to AC.  In pressure pumping, we see this as Tier 2 followed by Tier 4 and ultimately followed by electric.  The transition in land drilling took over a decade and required take-or-pay contracts with the E&P industry.  The same will be required for the pressure pumpers.  For E&P’s who balk at the idea of signing a term contract for frac services today at what would be a premium price, we suggest you consider the benefits and efficiencies the E&P sector gained via enhanced drilling rigs and associated drilling technology.  That R&D paid off.

Keep in mind, there are still a few mechanical and SCR rigs running today.  So too will be the case for pressure pumping.  Not all jobs (or customers) will require electric or leading edge dual fuel engines, thus legacy equipment will still have some life.  Some of our OEM contacts estimate the electric market will be as much as 30% of the overall frac market.  We, however, believe it will be more as ESG pressures likely grow while the benefits of micro-grid technology might just surprise to the upside, particularly if E&P’s can sell power into the grid.

The MTU electric design will not be the only one.  We learned last week another company is developing a new fleet concept, but in full disclosure we have yet to see this design or speak to the company (although we expect to speak to them on Monday).  Meanwhile, new power end / pump designs are also forthcoming.  One pump OEM recently introduced a new power end which uses a casted frame as opposed to a fabricated frame.  The casting concept is expected to eliminate frame cracking.  In addition, the power end will use a larger pinion bearing as opposed to the traditional smaller pinion bearing.  This design is made to spread out the load to extend the life of the bearings.  The new power end is now deployed in the field with no reported issues yet.  Further, on the test stand, the casted design demonstrated a 3x life versus legacy designs.  To be fair, other pump OEMs are also introducing/testing new pump designs, some of which are profiled frequently on social media.  We’ll do a more comprehensive summary / product profile in the coming days (after returning from our final kid college drop-off later this week).

Another concept potentially emerging surrounds labor.  We understand there is at least one company contemplating a frac contract labor business.  Simplistically, field contacts report the enterprise will gather experienced crews/people and rent them out like consultants.  Perhaps a good strategy for short-term project work or for companies wishing to deploy idle equipment, but not wanting to go through the hiring/layoff process.  For contract labor, these individuals might find more consistent work as they could move between various service companies.  Key question for us is one of liability and risk management.  Will a frac company want to use unknown folks on its equipment?  Keep in mind there are probably plenty of qualified former frac crews on the sidelines who could participate in a contract labor framework.

Things To Consider:  We are in the early innings of our diligence, but our instinct tells us the emergence of new fleet designs will hit the field in 2021 and accelerate in 2022.  Remember, the new fleet concepts are electric.  They will be powered by either a turbine or gas genset which means nat gas or CNG/LNG (think Certarus/Stabilis) is a fuel source.  Lower emissions, reduced carbon foot print and reduced diesel costs all become viable benefits.  The power, if owned by E&P’s, has other options besides frac.  It can be used to provide power to other parts of the field, thus providing optionality for the E&P.  Meanwhile, it is our understanding the gas gensets and turbines have other industrial applications relative to traditional frac engines which makes the equipment easier to sell into other markets, if needed. The equipment, according to engine OEMs, also has a longer useful life as one leading OEM tells us the gas genset should last ~4x the life of a traditional frac engine while ongoing maintenance costs are also lower.

Other points one should consider:  New equipment designs, while potentially cheaper than legacy designs, still cost money.  Will existing public frac companies authorize new capex, particularly in a period of capex austerity?  Perhaps some, but most won’t.  How does a public company justify to investors the merits of new fleet investment when most frac companies generated negative EBITDA in Q2?  We’re not so sure you can, at least not in 2020.  Maybe the really big frac companies who don’t provide granularity can sneak this by, but not transparent pure-play SMID-cap folks.  On the other hand, some debt free companies known for innovation may get a pass as these investments would be in-line with an established strategy.  Meanwhile, private companies who answer to themselves have much greater optionality, with some potentially being the real first-movers.  In our opinion, these new concepts give rise to new start-up’s, something we suspect we’ll see in 2021.

What about Tier 4 dual fuel engines?  These investments likely continue, but we see the Tier 4 dual fuel solution as a stepping stone to an eventual electric adoption.  And for legacy Tier 2 equipment?  Still some life, but fading.  Remember, in a few recent RFP’s several of the leading lights within E&P inquired/mandated Tier 4 DGB and/or electric.  As ESG pressures rise, more E&P’s will seek these solutions, particularly if E&P investors wake up and question E&P companies’ frac strategies.  With respect to Tier 4 dual fuel, the most consistently mentioned name is CAT’s Tier 4 DGB.  The “DGB” term is now common, akin to “Kleenex” and “Coke”.  We believe Cummins will roll out its Tier 4 dual fuel equivalent next year while we believe MTU will focus on the genset concept.  The Cummins QSK50 frac engine is rated Tier 4 already, but the dual fuel solution arrives next year.

Will All E&P’s Move To Electric?  Nope.  Some frankly don’t care about ESG so they don’t see the urgency.  Some simply don’t have the volume of work to justify an electric transition.  Others will avoid any type of term commitment or will simply continue to play the low-bid spot market.  Some, we suspect, haven’t fully paid attention to the emerging technology and aren’t prepared to state an opinion.  What we also know is many of the leading OEMs have, to date, focused their sales efforts on the frac industry.  What they need to do in order to fast-track change is educate the E&P companies so that they drive the change.

Our view is the move to electric will be made by the largest E&P’s who are all competing for increasingly less public investment dollars.  They will play the ESG game and check the box.  Make no mistake, however, there is evidence the current electric designs are working.  Just take a look at recent comments by the Marcellus E&P players who highlight both the efficiencies and fuel savings associated with their fleets (i.e. EQT, CNX).

Private Equity Considerations:  We are not entirely plugged into all things private equity, but we’ve heard about challenges for some existing energy-focused PE shops with fundraising efforts.  Presumably a key challenge is performance-related as energy investments across the board have not fared well in recent years.  We also hear the ESG craze is leading some large endowments to avoid energy altogether, a move which has caused a few traditional energy-focused PE shops to pivot towards renewables and other green-related investing.  While positioning pressure pumping as ESG friendly is tough, there is a twist with the electrification of the oilfield.  Think about the ability to recapture and utilize field gas.  Think about the ability to reduce wellsite diesel consumption via gas-power and/or less tractors required on site.  For PE’s who invest solely in the E&P sector, would it be helpful to have an E&P portfolio which pursues a greener agenda?  We presume concrete evidence of portfolio E&P companies using greener D&C solutions would help with marketing efforts.  Wouldn’t that make good fodder for one’s sustainability report?  Now, consider if such efforts actually reduce well costs.  That’s the advertisement from the OEM community.  If true, could that be a win-win as well?  We think so which is why funds need to start digging into this emerging theme.  Suggestion – start with the Tier 4 dual fuel option.

Current Electric Players:  We believe there are ~16 electric fleets today: Evolution (7), U.S. Well Services (5), Halliburton (3) and TOPS (1).  BJS has introduced its new electric design and we suspect they will build fleets post-bankruptcy.  We also suspect LBRT will introduce its electric option as well.  Lastly, we believe there are potentially two other electric fleets poised to be built by private players.  Look for more color on this by YE’20.

FTSI Bankruptcy Announcement:  Not surprising and frankly expected.  FTSI announced on Monday its plan to voluntarily file bankruptcy.  The restructuring agreement, we believe, will leave FTSI with no debt and a decent chunk of cash on the balance sheet.  This move should now give FTSI much more flexibility and allow it to better compete with peers who similarly enjoy clean balance sheets.  The key question, however, will be the vision of FTSI’s new owners.  Do you consolidate, reinvest or perhaps something else?   No view on which path they take, but the ability to make strategic moves and/or participate in a broader industry consolidation process should now be much easier to effect given no debt overhang.

BKR Rig Count:  Flat this week.  Still at 241 land rigs.  Up three rigs in the Haynesville, down two in the Permian and down one in Other.

DEP Houston Energy Conference & Expo.  We are off to Minute Maid Park this week to measure the concourse and parking lot.  Therefore, information about booth availability and exhibit space will be available shortly.  As a reminder, the event will be on February 24-26.   Stay tuned.

Upcoming Field Tours:  We head north to Oklahoma the week of September 7th followed by a Permian tour the week of September 15th.   In between, we’ll conduct meetings in Houston.

Podcasts:  Seems like everyone is doing podcasts, so DEP will soon jump into the fray.  We’ll kick off our series in September.  If anyone has ideas how we should brand it, let me know.  Importantly, if you aren’t scared of a DEP deposition and would like to discuss your service/technology or just simply educate folks about your company, let us know.  We are looking for victims to join us as we explore the world of domestic oil and gas.


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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