This week we update our rig and frac crew forecast to reflect an improving commodity backdrop as well as to reflect observations imparted during Q4 earnings season. We also summarize a recent field tour where we learned about a new product offering.
Upcoming DEP Field Trips/Events: Monday/Tuesday this week, we’ll be in Fort Worth. Next week, we hit Denver on Monday/Tuesday (3/15-3/16) then over to Tulsa on Wednesday/Thursday (3/17-18) and back through Oklahoma City on Friday (3/19). We are still building out our schedule, so let us know if you are around. In keeping with tradition, we’ll likely host a Mickey Mantle’s steak dinner for industry friends. Our next golf outing for clients will be on April 7th in Houston while we’ll host a one year anniversary social at our office on April 1st.
Rig Count Forecast: Rig count predictions are more art than science and often require more luck than skill. Each time we update our forecast, we recognize there is an inherent circular error. Case in point, over our career we are often asked by industry players for our rig forecast which is then used in conjunction with their respective budgeting process. At the same time, in order to develop a bottom’s up forecast, we then ask these same companies for their views on future activity. In other words, sometimes it’s the blind leading the blind. That said, we still endeavor to make forecasts, thus with Q4 earnings season largely behind us, it’s time to true up our rig count estimate.
As we alluded to in prior notes, the forecast moves higher. Not drastically in 2021, but a more assertive increase in 2022. These are our key assumptions:
- We assume the CY’22 strip stays in the $55/bbl vicinity – a function of OPEC+ guardianship and improving global demand.
- We assume public E&P’s will honor their commitment to capital discipline this year. Frankly, many E&P’s bloviated about potentially strong FCF in the current commodity price environment, leading any generalist investor to expect this FCF will come back to them either in debt reduction or dividends. For an industry which is still trying to rebuild investor credibility, any deviation from the capital discipline narrative likely won’t go well. Moreover, the shale industry, we submit, needs to play ball with OPEC+ so a return to irrational exuberance runs the risk of faster OPEC+ intervention. No one wants that.
- We believe private E&P’s will drive incremental activity in the near-term.
- We assume 2022 budgets will be conservatively based on a low ~$50’s/bbl WTI with reinvestment ratios in the 70-80% vicinity. Effective reinvestment ratios lower if capital discipline persists and oil prices stay put.
- This gives the E&P space sufficient wiggle room to ramp activity, but still generate very healthy cash flow, particularly if the 2022 forward curve becomes a reality next year.
- We believe some E&P’s, wishing to be forward thinking, will seek to add rigs ahead of 2022 in order to lock in better dayrates. Remember, drilling costs make up a smaller percent of the well cost, thus picking up rigs in Q4 for one’s 2022 program may be the wise move, particularly when high spec rigs, while available today, might not be in 1-2 quarters. In other words, a Q4 rig count spike feels reasonable (albeit not really modeled).
The result of these assumptions leads us to model the U.S. land rig count improving to an average of ~460 rigs in 2H’21 and exiting 2021 in the 500 rig vicinity. The 2H’21 expectation represents a ~60-80 rig improvement from today or +15-20%. Assuming the CY’22 strip holds (i.e. ~$55/bbl), we do believe disciplined animal spirits will emerge in 2022 with most E&P’s likely to increase activity by at least another 20%. Recall from an old Permian note, we asked E&P’s to humor us with a “what-if” scenario should WTI exceed $50/bbl in 2022. Responses generally fell in the 25%+ increase in activity with one large player claiming its rig activity could jump as much as 50%. We’ll query this same scenario during our upcoming field tours (hitting Denver/Oklahoma/Permian in March). For now, however, we assume the U.S. land rig count rises to the low 600 vicinity by early 2022. The higher oil price would normally lead us to be more bullish, but we think the public E&P space would be wise to maintain the current discipline for an extended period of time.
Frac Crew Forecast: Rolling through our rig count forecast as well as well as expectations for continued completion efficiencies, we update our frac crew forecast which nudges only marginally higher. To be clear, we employ a top-down approach, fully acknowledging this is a horseshoes-and-hand grenades exercise. Notably, the evolution of simul-frac operations seems to be in its infancy with only a basket of companies employing this approach. A broader adoption, however, could be a game changer for completion efficiencies as benefits extoled by users of simul-fracs are noteworthy. Take Ovintiv, for example. On its Q4 call, it highlighted the virtues of simul-fracs, reporting an instance where it managed to complete 4,400 lateral feet in 24 hours, pumping 220,000 barrels during this time period. The use of simul-frac operations purportedly saved OVV approximately $18.5M in 2020, thus the company intends to complete 95% of its wells in 2021 using this completion technique. We have chatted with others who use simul-frac operations and anecdotes of 3,000+ completed feet/day are reported. The challenge, however, is quantifying the total market opportunity for simul-fracs. We hope to have a more formal methodology in the coming months, but for now, the theme seems clear. More simul-fracs are likely another driver of completion efficiencies. Meanwhile, frac companies also continue to report impressive uptime. Take FTSI for example. It reports multiple fleets now pumping over 20 hours/day with fleets regularly averaging 17-19 hours/day. SilverBow Resources cited examples of completing 18 stages/day during Q4. These efficiencies matter, but are admittedly hard to model. Consequently, while we employ a more assertive rig count recovery, we would suspect the rate of growth for completion crews could lag the rig count on a go-forward basis should more E&P’s adopt simul-frac completion techniques. Not to mention, it would seem all public frac companies are now committed to withholding incremental fleets until pricing recovers. Lastly, the frac crew count moved more assertively off the bottom already, a function of E&P’s going back to complete DUC’s. Collectively, the aforementioned commentary leads us to believe a more tempered ramp in the completion crew count is likely. Therefore, our model contemplates today’s active crew count of ~195-200 fleets increases modestly to ~200-215 vicinity in 2H’21. Keep in mind, this is active and not effective. That number would be haircut by 10-15%. For 2022, we believe the active count bleeds into the ~230-240 vicinity. Hard to see a surge in working crews if frac pricing does not inflect materially.
SOI – New Blender? Or Frac Missile Feeder System (authored by Sean Mitchell). Members of the DEP team again travelled to Midland last Thursday, this time to view the new blender system developed by Solaris. The unit, which was on display at the Petroleum Museum for both E&P and OFS companies to see, is yet another solution developed by Solaris for the low pressure/backside of the well. The unit is ESG friendly as the equipment is plug-in ready for both Efleets and traditional fleets. For discussion purposes, we are calling the new blender system another name – the Frac Missile Feeder System – as it is designed to replace the traditional blender. Here’s the pitch from our non-engineer perspective: it is an electric solution on the backside of the well; it enjoys a smaller footprint and purportedly more redundancy will drive less NPT, creating efficiency gains for both the pumper and E&P companies. This is a new product, so time will tell just how effective it is, but we took note of the who’s who from the E&P and pressure pumping world who came out to look at the equipment. And the visit wasn’t just a quick drive by tour. Rather, we observed folks spending quality time visiting with the SOI team, presumably a good indicator of interest. SOI’s new Frac Missile Feeder System is the fourth leg of the table for a fully integrated solution on the low pressure/backside of the well which also includes their Chemical Silos, Water Silos and Sand Silos. Some of the advantages of the new system discussed at the tour include:
- ESG Friendly with all electric design.
- Remote operation that allows for 80% reduction in personnel footprint which contributes to efficiency gains.
- Eliminates hopper screws and t-belt that moves sand from the tub to the blender which contributes to less NPT.
- Closed system, allows for dust control and reduction in lost sand, water and chemicals which also contributes to efficiency gains.
- Reliability and redundancy with 3 blender systems directly connected to the sand, water and chemicals which contributes to efficiency gains and less NPT.
- Greater than 20klbs/min sand ingestion per tub.
- The three systems can run simultaneously or stand alone.
Housekeeping Note: We will soon transition to a new distribution system. Potentially next Sunday, but most likely the following Sunday. If you see a disruption in your receipt of our Sunday note, send me an email. We will try our best to not screw this up.
Q4 Earnings Observations:
SND. Revenue = $25M, +8% q/q. Adjusted EBITDA = -$7.7M vs. $6.1M in Q3’20. Cash = $12M with total debt = $30M. Q4 volumes increased to 612,000 tons in Q4 from 309,000 tons in Q3, a +98% improvement. Q1 volumes guided flat to up 10%, would be better but Texas freeze impacted operations. 2021 capex = $10M to $15M and SND expects to be FCF positive in 2021. Some of the spend will likely be directed to SND’s SmartPath transloader product offering. The company now has four of its fleets outfitted with this, but all twelve should have it by year-end. The SmartPath system, as we understand it, is a self-contained system capable of being used with bottom-dump trailers. Q4 call highlighted multiple prepared comments on the need and willingness for M&A. To SND’s credit, it executed on this strategy in Q3 with the opportunistic purchase of Eagle Materials operations. During Q4, SND turned on the old Eagle Utica operation, a facility gives SND access to another Class 1 rail line. Nevertheless, the sand space still remains too fragmented, thus more M&A is needed to address the supply overhang.
FTSI. Revenue = $50M, +55% q/q. Adjusted EBITDA = -$5.2M vs. -$7.6 in Q3’20. Q4’20 capex = $1.8M with 2020 capex at $21M (down from $54M in 2019). FTSI averaged 10.5 fleets in Q4, up from 7.3 fleets in Q3. The company exited Q4 with 12 fleets active and today has 13 fleets active. The company has two fleets running simul-frac operations while seven fleets are dual fuel capable. Pumping times continue to improve as hours pumped per day averaged 15.1 in Q4, up from 14.9 in Q3. Averaged stages completed per fleet increased to 632 in Q4, up from 579 in Q3. The company noted a maintenance capex budget of $2.5M/fleet in 2021, thus a low-end capex range would be roughly ~$30M. Our guess is spending comes in closer to $40M-$50M. With FTSI’s restructuring now complete, the company has no debt and $94M in cash. Of note, FTSI spent $54M in cash/expenses during its restructuring process. The company expects to be EBITDA positive in Q1.
SBOW. 2021 capex budget = $100-$110M vs. $95M in 2020. Reduced debt by $49M to $430M with 2021 FCF expectation of $20-$40M. For 2021, SilverBow expects 20 gross wells completed vs. 16 gross wells completed in 2020. The plan is expected to yield 8% nat gas production growth y/y. Operational efficiencies impressive as SBOW had a total recordable incident rate of 0.00 across both employees and contractors. The company drilled Eagle Ford wells which were drilled in 9 days (spud to rig release). Select wells average 1,900 feet per day. With respect to completions, the company’s Fasken wells were completed with 2,600 pounds of proppant for foot with 18 stages/day completed. Across all of its operating areas, SBOW drilled 44% more lateral feet per day while lowering lateral foot costs by 32% compared to 2019. The company completed 8% more stages per day in 2020 vs. 2019.
ESI.T. Revenue = $201M, -46% y/y. Adjusted EBITDA = $53M vs. $95M in Q4’19. Total debt reduced by $197M, totaling $1.38B at YE’20. 2020 capex totaled $50M with 2021 budgeted at $50M as well. In the U.S., the company is running 36 of its 90 high-spec rigs. The company noted strength in its bid book, mostly with smaller E&P’s. In response to a question on the Q4 call, management noted its rig count could increase ~50% into Q4’21 with pricing traction likely to develop in 2H’21. The company noted one U.S. drilling rig is a hybrid and another is operating with natural gas. U.S. well service rig hours totaled 26,764, +23% q/q – the company owns 48 well service rigs in the U.S.
CFW.T. U.S. revenue up 45% q/q to $67M. Operating income was $1.0M, but included $3.9M of fleet reactivation costs. Calfrac reactivated three crews in the U.S. market, bringing its active U.S. fleet to 7 fleets. Calfrac noted higher returns will be required to bring back additional fleets. In Canada, CFW has 4 active fleets and 4 active CT units. The 2021 capex budget is set at $55M vs. $46M spent in 2020.
As always, no stock opinions or investment advice intended from this or any of our notes…..
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