For those on spring break, we hope you are having fun and defer reading this note to a later time.  For those who are tasked with working this week, please read on….

Upcoming DEP Events:  Our one-year anniversary social will be held on April 1st at our office parking lot from 5pm to 8pm.  Feel free to swing by, but please let us know first so we can let the caterers know.  The next Houston golf outing is on April 7th.  We still have some open spots.  Also, be on the lookout for our Permian Basin BBQ Cook-Off Save the Date email.  Hope to get that out on Monday.  Finally, we’ll be in Denver (weather permitting) on Tuesday/Wednesday and then over to Oklahoma on Thursday/Friday.  Let us know if you’ll be in town.  Other field tours in the works: (1) Permian Basin tour on March 30 to April 1 and (2) a Bakken/PRB couples tour on April 12th – 16th.

Frac Engines.  It’s game on for dual fuel upgrades as multiple industry contacts report surging interest by frac companies seeking quotes for engine conversions.  In most cases, frac players are looking to upgrade to Tier 4 dual fuel, but some companies are also upgrading Tier 2 engines to Tier 2 dual fuel.  Costs to upgrade vary.  To swap out a Tier 4 for a Tier 4 dual fuel is less expensive than to convert a Tier 2 trailer to Tier 4 dual-fuel.  Per trailer conversion costs are quoted as low as $250,000 to as much as $700,000.  Presently, CAT has its Tier 4 dual fuel system in the field, aka the Tier 4 DGB.  Cummins, meanwhile, is introducing its Tier 4 dual fuel solution this year.

Rising conversion inquiries are largely the result of increasing requests for dual fuel by E&Ps.  With this backdrop, understanding the supply/demand framework for dual fuel engines takes on more importance.  Unfortunately, tracking the actual supply of Tier 2 and Tier 4 dual fuel fleets is not easy.  In fact, the tally process requires a number of different channel checks. Why the challenge?  Some companies are sensitive to discussing their fleet specifics while others don’t seem to care.  While we know our estimate could be off slightly as “exact” precision is hard with limited disclosure, we do believe, however, that we are in the ballpark.  By our tally, we believe there 28 fleets in service or under conversion which will have Tier 4 dual-fuel status (we peg conversions in process at ~9 fleets).  Some of estimated 28 fleets are Tier 4 engines outfitted with 3rd party dual-fuel kits (we estimate at least ~7).  Most, however, are the Tier 4 DGB product from CAT.  With respect to Tier 2 dual fuel, we estimate there are roughly 60 fleets in service.  Legacy Tier 2 fleets, we believe, approximate ~250 fleets.  We believe Cummins now offers a kit to transition its Tier 2 engines to Tier 4 status, so look for conversions here as well.  While the Tier 2 to Tier 4 conversion won’t reduce diesel consumption, it will add an emissions benefit.  Looking forward and making an educated guess, we would expect to see our Tier 4 dual fuel count increase into the range of 35-40 fleets by YE’21 as most capital-advantaged frac companies are presently evaluating orders for Tier 4 dual fuel engines.  We would envision the typical well-capitalized company adds 1-2 fleets or ~20-40 engines.

So what does this mean?  First, we estimate the marketed U.S. frac fleet is roughly 200 fleets, maybe as much as 205.  We peg electric/next gen frac fleets at 20 and the collective dual-fuel fleets at ~85-90 once near-term conversions are completed.  We further estimate there are another ~65 Tier 4 fleets. In other words, roughly 75% of the total active fleet offers some sort of emissions and/or fuel savings benefit.  Second, by all accounts, E&P interest in emission friendly equipment is growing.  For example, one prominent frac packager reports a surge in frac company interest within the past 30 days.  All inquiries surround interest on emission friendly solutions (i.e. electric or dual-fuel).  Right now, potential engine buyers are gauging conversion costs, but with the bi-furcation of the U.S. frac fleet playing out, many will soon order (in our humble opinion).

Why?  E&P’s face growing pressure to reduce emissions.  Additionally, diesel prices are on the rise.  Not that any frac company pays retail diesel prices, but for simplicity, take a look EIA’s Gulf Coast diesel prices which averaged $2.93/gallon this past week.  This compares to $2.25-$2.50/gallon for much of 2020.  That’s a ~25% increase.  The combination of improved emissions and potentially the ability to lower one’s diesel costs are the drivers of rising E&P interest in new engine technology.

Back to the supply/demand balances of dual fuel engines.  By all accounts, utilization for Tier 4 dual fuel and/or electric is at or near 100%.  Tier 2 dual fuel utilization is less robust.  We’ll try to quantify for our next update, but we’ve had some contacts claim E&P customers run the Tier 2 dual fuel fleets, but are running the fleets on diesel, not gas/CNG.  Nevertheless, market tightness exists within a subset of the frac market, a potential bright spot for the U.S. frac industry.  On the one hand, the industry could choose to leverage this market tightness and seek pricing opportunities.  Or, the industry could react by adding more capacity to meet customer demand.  At this point, it would appear the industry is pursuing the second option with more vigor, but we would presume the tightness will ultimately yield some price recovery.

Final thought.  The focus on emission friendly equipment extends beyond just engine conversion.  There is growing interest in gas gensets and likely, a broader adoption of turbine power.  Leaders in genset technology are MTU, CAT and Cummins while Siemens, CAT, Pratt & Whitney and BKR play in the turbine market.  These collective power solutions, we believe, will be required for those frac companies wishing to employ the new, bulkier 5,000hp type-pumps.  Multiple pump companies have either introduced new pumps recently or will be doing so this year.  We’ll dig into this segment of frac in the coming weeks.

Frac Pricing. Mixed commentary persists as some frac companies claim to have successfully raised spot prices; others claim increases are pending while others have yet to see any improvement.  One contact shared its leading edge hourly pumping charges in the Permian now range between $5,500/hour to $6,500/hour.  This is down from the ~$7,500/hour pre-COVID pricing, but above the market bottom of ~$4,000/hour.  It’s worth considering the potential EBITDA/fleet impact from a small movement in price.  Dumb-guy math here, but let’s call spot pricing $6,000/hour.  Let’s assume pricing moves higher by 10%.  We’ll further assume the fleets average 16 pumping hours/day and work 24 days/month.  That change would equate to an incremental ~$2.75M of EBITDA/year (all else being equal).  That’s a decent start to fund some engine conversions, but more pricing (or term) is likely needed as well.

Frac Newbuilds.  We are now tracking a private frac company expanding with a new fleet.  This fleet was previously built and sitting in inventory at a builder.  The purchase is akin to what PUMP did recently with its advantageous purchase of new pumps.  By our tally, there is one remaining newbuild Tier 4 DGB fleet still sitting at a builders facility while there are two other Tier 4 fleets at two different builders facilities.  Thus, three new fleets could quickly enter the market should someone wish to buy them.  Multiple equipment fabricators are sitting on 1-2 new units which are also available for sale.  There is no shortage of stacked capacity which could be bought and rebuilt.

Sand Thoughts:  Sand prices have spiked recently leading to some inbound inquiries from industry contacts.  Specifically, sand friends report WTX spot sales prices in the $27-$30/ton vicinity in recent days (a blend of 40/70 and 100 mesh).  The spike reflects a combination of events: (1) inclement weather which shutdown regional mine capacity; (2) reduced productive sand capacity due to mine closures/reductions in staff and (3) growing demand due to a rebound in D&C activity.   Key questions posed to select sand mine contacts: what do you do?  Do you increase capacity to meet expected higher demand?  Or, do you take a play from the E&P playbook which is to reduce capacity, remain disciplined and let prices rise?  One would think the answer is obvious.  That is, let current elevated spot prices become the norm such that respectable contribution margins can be generated.  Unfortunately, market share considerations still flow strongly through the veins of OFS companies as 75% of the mines we chatted with now intend to increase production capacity.  And, these same companies generally agree the current strength in spot prices will fade in 2H’21 as the incremental capacity is brought to market.

BKR U.S. Land Rig Count:  Flat at 389 rigs this past Friday.  In June 2020, DEP made its first official land rig forecast.  That prompted a bet with a prominent E&P CFO.  Our forecast assumed the U.S. land rig count would average 371 rigs in Q1’21 and would surpass 400 rigs by March 31, 2021.  The subsequent bet was the over/under on our 400 rig count exit-rate forecast.  We, of course, took the over as we don’t enjoy capital discipline.  With nearly two weeks to go, the BKR U.S. land rig count is likely to average between 375-380 rigs this quarter, but what really matters is the exit number.  Therefore, the DEP team needs another 11 rigs running for us to win the free dinner.  Let’s go land drilling friends.

U.S. Land Rig Thoughts:  One anecdote does not make a trend, but we had the chance to catch up with a large E&P.  Our note from last week prompted the discussion as we presented an optimistic outlook on U.S. drilling activity.  This E&P would be best described as a disciplined player so we were interested to hear this company’s plans to increase its rig count by ~33% over the course of the next few quarters.  The ramp will still keep the E&P below prior peaks, but we submit even disciplined players could see continued rig count growth.  We subsequently visited with two private E&P’s.  Both have no plans to add rigs near-term due to hedge positions in the $40’s.  Both companies have been asked by sponsors to review the costs to unwind the hedges – perhaps a sign of oil price optimism??  When asked if their respective sponsors would be willing to allocate more capital to D&C, both expressed a belief the answer would be yes.  As for implications for their respective rig activity in 2022 should the strip stay steady, one E&P chose not to prophesy while the other expressed a view that its rig count could rise ~30% from today’s levels.  Earthstone Energy, meanwhile, stated last week plans to run one rig in 2021, but could increase to two rigs later this year.  While that wasn’t official guidance, the tone of the call gave us the feeling such an increase is probable.  That’s a 100% increase.  Yes, it’s a small number, but a reminder that small players collectively can have an impact on the overall count.  Finally, we caught up with another large E&P to discuss our view the Q4 rig count could spike as E&P’s seek to lock in rigs early for their 2022 drilling programs.  While this company did not opine on its own rig strategy, it did express a view that a broader industry Q4 acceleration seemed more probable than not.  Time will tell, but we remain constructive in a ~600+ rig count by Q2’22.

Q4 Earnings Observations:

NOG: Interesting non-op E&P story as NOG has expanded beyond its legacy Bakken-only strategy with the recent/pending entry into the Permian and Marcellus.  What we found most interesting in the company’s prepared remarks was this quote by the CEO: “We are a company run by investors, for investors”.   The company, like others, should see healthy free cash flow.  Consequently, NOG will evaluate a dividend strategy as well as evaluate additional working interest opportunities, which management called out as being close to $10B.  What matters, though, is the team’s comment about running the business from an investor’s perspective.  As for activity, NOG will see increased workover activity heading into the summer, particularly in its Bakken interests.  Drilling activity, according to management, should be up “substantively” in the Bakken as the year unfolds.  With respect to capex, NOG spent $163M in 2020, down 56% y/y.  The Q4’20 spend came in at $49M.  NOG sees its peak quarterly capex spend in 2021 occurring in Q2.  Balance sheet improvement is expected.  The company sees its leverage ratio moving below 2x in 2021 with a long-term objective of nearly 1.0x.  This is down from ~6x back in 2017.

USWS: Revenue = $48M, +9% q/q.  Adjusted EBITDA = $2M vs. $8M in Q3.  Adjusted annualized EBITDA/fleet is roughly $4M. Q4 results were burdened by a $3M bad debt expense.  USWS spent $56M in capex in 2020, of which $4M was spent in Q4.  No formal 2021 capex guidance was provided.  The company now has 10 active fleets, including its 4 electric fleets.  USWS noted it will soon deploy its 1st generation electric fleet to commence three trials with three different E&P’s, thus look for the USWS active fleet count to migrate to 11 fleets during Q2.  Importantly, USWS has auxiliary equipment which the company could use to support the build-out of two additional electric fleets.  Total cash costs to complete those two fleets would be close to $50M.  Meanwhile, maintenance capex seems like it could fall in the $25-$30M vicinity in 2021, subject to activity.

GDP:  2021 Capex = $75-$85M vs. $56M in 2020 and $11M in Q4’20.  GDP plans to drill 17 gross wells with 9 in Q1.  Cadence then calls for one well in Q2, 4 in Q3 and 3 in Q4.  Average lateral length will be 7,500’ although GDP is preparing to frac a 10,000’ lateral in April.  The company increased its acreage position in 2020, adding 6,000 acres to 26,000 total acres.  Advertised IRR’s are strong as GDP claims it is generating 100% IRR’s at $2.50 gas.  2021 guidance calls for $15-$30M of FCF.

ESTE: 2021 Capex = $90M-$100M vs. $67M in 2020 and $20M in Q4’20.   Advertised IRR’s impressive.  Company claims IRR’s of 70% to 90% on 10,000’ laterals at $50 oil and $2.50 gas. Company noted all-in frac costs per stage averaged $37,833/stage in Q4’20.  This compares to $50,300 in Q1’20 and $56,600 in 2H’19.  The company expects to average $40,000/stage in 2021.  Wells per pad holding relatively stable in 2021, expecting to average 3-5 wells/pad vs. 4.5 in 2020 and 2.4 in 2019.  The company expects to operate a one-rig program in 2021 with plans to use FCF to pay down debt.  That said, the company did note it will consider plans to add a second rig (DEP impression from tone is a 2nd rig seems probable later this year).  The current capital budget assumes ESTE will drill 16 gross wells.   ESTE also noted plans to increase workover activity this year.

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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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