Very busy week last week as we were consumed by the inaugural THRIVE Energy Conference, thus a somewhat low calorie note this weekend.  Given our lack of free time last week, we haven’t fully digested all of the Q4 earnings calls in recent days, but below, we largely touch on some of the SMID names who might not otherwise get as much attention.  This week the DEP team will be dividing and conquering.  Bill and Sean head to Midland on Thursday/Friday while I will be floating around Houston seeking company updates and listening to this week’s Q4 earnings calls.   The week of March 8th I’ll do a couple days in the DFW area if anyone is free.

Thank You!  The DEP team can’t begin to thank our industry friends enough.  First, we really want to call out our sponsors and exhibitors who made a financial bet on us.  Without your financial support, there’s no way we could have pulled this off.  But an event is much more than just covering one’s bills.  We also must thank all of our speakers who took time out of their schedules to discuss their respective views on the market.  Your thoughts, observations and outlooks were all greatly appreciated by the conference attendees.  I know each of our speakers receive numerous requests to present each year and for you to allocate time to Daniel Energy Partners, particularly for our first event, is huge blessing.  Finally, for those who attended, we want your feedback.  If you saw things you didn’t like or have suggestions how we can improve next year’s event, please let us know.  By no means do we claim to be Expo experts.  Importantly, we are old enough and hopefully, mature enough to appreciate constructive criticism.

THRIVE 2022:  We have tentative dates for next year’s event: February 23-24.  While formal conference planning is a few months away, please let us know if your company has an interest to either exhibit equipment; have an indoor display and/or be a suite sponsor.  As a courtesy to our sponsors this year, we’ll give them right-of-first-refusal for next year.  The objective for 2022 is to use the entire stadium, but similar to this year, we intend to stick with an invite-only philosophy.  We want attendees to maximize their networking/learning time as opposed to being hassled by solicitors.  If you want that, go to another event.  Finally, we recommit our quest to establish the THRIVE event as the most cost effective conference with the highest quality attendees at the most enviable venue.  That, we hope, is the value proposition to our supporters.

Grayson Porter and Travis Weaver.  We really must give a huge shout out to Grayson Porter of CP Energy Services for the hitting the first home run at the THRIVE Energy Conference batting practice.  We saw lots of really ugly swings coupled with a few pulled muscles, but a few young energy gurus such as Grayson reaffirmed our decision not to take any swings.  And while Grayson hit the first home run, we also give a mega kudos to Travis Weaver from Cactus Drilling who came darn close (i.e. within inches…).  We think next year, Travis will find the Crawford Boxes.  Meanwhile, for all the mom’s and dad’s who brought kids to hit, your family’s presence is what made this event so special.

Abbreviated THRIVE Takeaways:  Our two-day conclave featured numerous industry panels with executives across the E&P, Oil Service, Capital Equipment, Midstream and Private Equity communities.  There was plenty to digest, but in the spirit of brevity, we’ll touch on a few key themes.  First, make no mistake, the concept of free cash flow and capital discipline permeated virtually all panels.  E&P executives all uniformly concur “the budget is the budget” and any benefit from higher commodity prices would defer to the shareholders either through debt reduction, dividends and/or share repurchases.  When given the bait about rig count prophesies (i.e. will the rig count eclipse 500 rigs this year), all took the under.  Even top-shelf private equity participants known for savvy E&P investing concur the business model is changing whereby investment decisions will be returns-driven.  Outliers to this theme were few save one large private E&P whose owner prefers to reinvest in the business vs. pull cash from the business.  Uniquely positioned, this player will add rigs while still building cash.  To sanity check public E&P company messaging, OFS panelists concur inbounds for incremental activity exist, but the level of inquiries coincides with the capital discipline narrative.  One prominent frac company shares our view on marketed U.S. frac fleet (i.e. ~190ish fleets) and sees an opportunity for this count to grow into the 200-205 vicinity.  Let’s call that a ~5% improvement from here.  A land drilling panelist believes a reasonable improvement for his specific fleet is ~5 rigs or +20% from today’s rig count.  Most agree private E&P’s likely drive most incremental activity from here.

Many of the conference panels centered around ESG and capital equipment innovations geared to reduce GHG emissions.  Anecdotes which we took note of were industry forecasts for ~6-12 electric fleets over the next ~12 months.  This range is consistent with our thinking.  Some disagreement, however, with industry players views on the installed electric fleet.  One frac panelist proffered a view that three criteria have yet to be met: Reliability, Economic and Emissions.  For this reason, the company is not rushing into the eFrac market.  Two frac players questioned to merits of turbines, yet a third claims no problems to date.  Meanwhile, a new player in the power generation market seeks “separate” power generation from the frac fleet, potentially maximizing power utilization with the potential to sell back into the grid.  The company intends to use gas gensets as the power solution of choice.

A final panel featured an emerging mining player whose focus is on nickel.  According to this player, if Tesla actually hits its new vehicle targets, it alone will use up the supply of nickel from the top six mines in the world.  Therefore, this player sees some challenges in the various EV prophesies/desires of several of the leading auto makers.

Other comments which we found interesting is the continued exodus of commercial banks from the energy space.  One PE panelist noted banks are leaving the space even for the most creditworthy names in the portfolio.  Yes, European banks are leading the way, but even several regional U.S. banks which have an energy history are also moving away.

Clearly, there was much more discussed.  This is just a quick snapshot of a few themes which come to mind.

BKR U.S. Land Rig Count.  Up 5 rigs to 385 rigs this past Friday.  The Permian continues to lead the way and is now up 91 rigs or ~78% since the August trough.  DEP will update its U.S. land rig forecast next week.

Q4 Earnings Anecdotes:  We highlight a few companies below and we fully acknowledge we missed a bunch due to our THRIVE event.  That said, the message from the E&P sector is remarkably consistent with what we heard at THRIVE.  Capital discipline, free cash flow and returning that cash to shareholders is paramount.  E&P’s with elevated debt balances will allocate a disproportionate percentage of FCF to debt reduction while others in a bit better shape either increased dividends or expect to initiate a dividend.  Most companies seek to keep production relatively flat with Q4 exit rates, in part because many companies acknowledge that oil prices are being artificially supported by OPEC+ actions.  For service companies, the results, once again, suggest a need for higher pricing as returns remain inferior.  Visibility and outlooks are generally consistent with most seeing ~10-20% increases from current levels.  As always, these company anecdotes are not investment advice, rather our observations from their respective earnings releases/calls.

RNGR:  Revenue = $42M, +20% q/q.  Adjusted EBITDA = $3.2M vs. $4.4M in Q3.   Top line growth driven by well service operations as rig hours jumped 43% q/q to 43,100 with average hourly rig rates moving higher by 5% q/q.  The well service segment generated Adjusted EBITDA margins of 13.3%, but were burdened by $1.3M of reactivation costs.  The Completion Services segment witnessed a q/q revenue contraction to $18.6M from $18.9M due to year-end slowdowns and pricing pressures.  Recall from a prior Permian note, we highlighted Q4 pricing pressures within wireline.   Balance sheet improvement is real.  Total debt now at $24.5M at 12/31/20 vs. $42.2M at 12/31/19.  RNGR continues to call out the need for industry consolidation and higher pricing, stating “….pricing discipline must return to the market and further OFS consolidation needs to occur.  Ranger is committed to participating in both.”   We concur as this is a message we’ve been preaching for far too long.  The competitive landscape within the U.S. well service market is too intense as years of companies selling old rigs has simply fostered new competition while procurement decisions, we submit, are almost entirely based on price vs. safety/quality/reliability.  Using RNGR’s Q4 margins as a proxy for the industry, a mid-teen’s margin for a labor intensive business is simply too low.  Rationalization in the space needs to occur.

SLCA:  Revenue = $227M, +29% q/q.  Adjusted EBITDA = $63.6M vs. $51.3M in Q3. Top line growth driven by a recovery in the Oil & Gas Proppants segment as sand volumes sold totaled 1.901 million tons, a 48% increase vs. the 1.282 million tons sold in Q3.  Contribution margin within the Oil & Gas segment improved to $51.5M vs. $31.5M in Q3.  Revenue within the Industrial segment decreased 3% q/q to $107M as tons sold contracted by 3% q/q as well.   Within Oil &Gas, the company is restarting its Crane and Sparta plants due to improving demand.  Pricing, meanwhile, was down 2% in Q4, but our field checks lead us to believe spot pricing is moving higher.  SLCA does have contracts in place for ~90% of its Oil & Gas sand volumes, thus it’s unclear how much price spikes could benefit them.  Of note, SLCA did call out “surging” proppant demand in January with February impacted by the inclement weather.  Nevertheless, Oil and Gas volumes are guided higher by 15% to 20% q/q.  Contribution margins, normalized, in Q4 was close to $10/ton.  Reactivation costs could cause a modest Q1 contraction, but margins should move higher beyond Q1.  2020 capex totaled $35.4M with 2021 capex budgeted at $30-$40M.  G&A reduced by 18% y/y in 2020 to $124M, but current annualized run rate is $112M, thus if sustained, marks another nice improvement.  Final thought:  SLCA is focusing R&D to new products within the Industrial Segment.  It’s not clear what the impact to these new products will be, although management alluded to some products which could have contribution margins as high as $500/ton.  Not too shabby, if achieved and achieved in scale.  Balance sheet remains the focus for SLCA as total debt stands at $1.24B with cash at $151M.

PDCE:  2021 capex budget = $500M to $600M. vs. $520M in 2020 and Q4’20 annualized at $440M.  The company plans to reinvest less than 60% of adjusted cash flow into capex.  The company intends to use FCF in 2021 towards debt reduction, the initiation of a dividend and stock repurchases. The budget is based on $45 WTI and $2.50 Nymex nat gas.   Operations:  In the Wattenberg, PDCE will run one rig, one frac crew and on intermittent spudder rig.  The company expects to drill 75-85 wells with an average lateral length of 8,900’.  Spud to spud times are expected to average ~5 days.  The company expects to bring 150-175 wells on line with a  n average of 20 stages completed per day.  Also, PDCE will spend $20-$25M to P&A ~350 legacy vertical wells.  Delaware Basin:  PDCE will spend $125M to $150M in the Permian.  Plans are to drill 15-20 wells.  This will require one rig while the completion program is expected to use one frac crew.   Other:  PDCE will spend 60% of the 2021 budget in 1H’21.  The company provided a three-year outlook which calls for $500-$600M in annual capex spend.

CPE: 2021 capex budget = $430M vs. $489M in 2020 and Q4’20 annualized of $350M.  The company is presently running 3 rigs (2 Permian/1 Eagle Ford) and two completion crews (1 Permian/1 Eagle Ford).  CPE generated healthy cash flow in 2H’20 (via operations and asset sales) and reduced debt by nearly $350M.  Balance sheet enhancement remains a core focus for CPE, thus any deviation from the 2021 budget appears unlikely.  The 2021 budget implies a ~75% reinvestment rate at $50 WTI which, if our read of the slide deck is correct, should yield about $200M of FCF in 2021. Other:  The Q4 conference call slide deck highlights a number of ESG improvements.  Also, CPE lays out potential scenarios over the course of the next 2-3 years which highlights the FCF generation capability with capex essentially unchanged from 2021 levels.

EOG:  2021 capex budget = $3.7B to $4.1B vs. $3.5B in 2020 and Q4’20 annualized of $3.3B.  The company anticipates averaging 22 drilling rigs and 8 frac crews (vs. 24 rigs / 7 crews today).   The rig breakdown is: 3 Eagle Ford, 14 Delaware Basin, 3 Powder River Basin and two in other plays.  Frac crews will be 2 Eagle Ford, 4 Delaware, 1 PRB and 1 in other.   Within the Delaware, EOG expects ~275 net well completions or ~69/crew or ~5-6 wells/month per crew.

CDEV:  2021 D&C capex budget = $250M to $290M vs. $212M in 2020.  The company will run a 2 rig program (at two rigs today) with an average lateral length of 8,800 feet.  Total wells drilled expected to range between 40 to 46 vs. 26 wells in 2020.  Total wells completed in 2021 expected to range between 40 to 48 vs. 31 wells completed in 2020.  The company’s 2021 plan calls for FCF of $55M to $75M.

APA:  2021 capex budget = $1.1B vs. $988M in 2020 and Q4’20 annualized at $756M.  Roughly 35% of the 2021 budget will be spent on the U.S. operations or approximately $385M.  During Q4’20, only $40M or $160M annualized was spent, thus the U.S. business will see 140% increase in spending relative to the Q4’20 annualized levels.  The company added one rig in the Permian in February and will add a second rig by mid-year.  In addition, the company added a rig for a 4 well pad in the Austin Chalk area.

ICD:  Revenue = $13.3M vs. $10.2M in Q3.  Adjusted EBITDA = -$1.5M vs. -$0.5M in Q3.  Q4’20 rig count averaged ~7.7 rigs, generating 707 revenue days.  ICD exited Q4 with 8 rigs drilling, but has 12 rigs drilling today.  It sees a rig count improvement to ~15 rigs by late Q2.   During Q4, the company reduced its marketed fleet from 29 rigs to 24 rigs and incurred a $24M impairment charge.  Average revenue/day in Q4 was $16,720/day with average rig margins of ~$3,000/day.   The 2021 capex budget is set at $6M vs. $14M spent in 2020.

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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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