Upcoming Events: The DEP team will host a reception in Midland on August 9th along with small reception in Houston on August 12th. Next Sunday, we’ll recap a recent Marcellus trip where our team toured a low-emission electric fleet powered by gas genset technology.
Permian Basin BBQ Cook-Off: We are two months away from the Permian Basin BBQ Cook-Off. For those not familiar with this event, the BBQ Cook-Off is intended to bring folks from all facets of the industry together. Industry leadership from E&P, OFS, Capital Equipment, Midstream as well as professional service firms and institutional investors will be in attendance. Approximately 60 companies are expected to cook while the judging will be overseen by the Kansas City BBQ Society. To elevate the competition this year, each cooking team is competing for a charity of their choice with DEP donating money to the Overall winning team’s charity.
The event should be fun, but there’s a catch. We have a headcount limit. Therefore, we are allocating initial invitations to DEP subscribers, event sponsors and select DEP guests. This group should be receiving the BBQ registration link this week. Many will receive it individually. Cooking teams/sponsors, however, will have the link sent to a designated person who can then register your guests/team. Our policy, we know, may offend non-client readers who don’t receive the registration link. We apologize in advance if any feathers are ruffled, but we have a business to manage, and we need to support those firms who support DEP. If you would like to attend this or any other DEP event, please reach out to the team and we can discuss our subscription model and/or sponsorship opportunities. Meanwhile, for those sponsors and clients supporting the event, we thank you as you have allowed the DEP team to pursue its dream while at the same time, you make our events possible.
New Pump Technology. The push for emission friendly equipment grows. So too does the pursuit of differentiated new technology. For nerdy folks such as DEP, we like to see cutting edge technology and/or new equipment designs as they prepare to come to market. This week we were afforded such an opportunity as we visited the team at ShalePumps to learn more about their quest to play a role in the growing bifurcation of the U.S. frac market. Specifically, we had the opportunity to see the company’s new patent pending Q5K 5000hp frac pump as well as to see designs for the company’s integrated frac trailer and the pending Q7K 7000hp frac pump. Now, as usual, we won’t speculate on the quality of the pump and how it stacks up versus the competition as we aren’t qualified to do so. We will, however, address the following. First, the Q5K has undergone field trials. Management was not able to disclose which frac company tested the pump, but we understand the pump saw action for multiple E&P’s (who they also could not disclose). Feedback was purportedly very good and we look forward to eventually hearing from the end users whoever they may be. Second, we have seen many frac pumps in our career. The Q5K was definitely the largest. Further, the company contends the Q5K pump can deliver the full 5,000hp. With respect to the ShalePumps frac trailer design, it is expected to weigh less than 100,000 pounds which the company contends means no permits will be required to move the trailer. Also, it is an emission-friendly concept (not electric) whereby the pump is powered via a direct-drive turbine and can run using line gas, CNG or LNG. A benefit of this design is a smaller footprint as ~6-8 trailers would, in theory, be on site. Once the Q7K rolls out, likely in 2022, the footprint could become even smaller. One of the advertised benefits of both ShalePump designs is higher rod load. According to the company, maximum rod load of the Q5K is just over 340,000 pounds. This implies a durable product. A quick review of other power end designs suggest maximum rod loads generally in the mid-200,000 pound range. The reason to pay attention to the ShalePump design is the same reason we write about or have profiled at DEP events other leading edge technology designs such as digiFrac, Dragon’s DP4000Q Continuous Duty Pump; Kerr’s EF5; Gardner Denver’s Thunder 5,000HP pump, OMT Flow Products and/or SPM’s EXL Frac Pump, among others. Our objective is to highlight new designs as new innovations will be the driver of further industry efficiency gains. It’s also fun to see new stuff.
Rig Count Outlook. Positive comments from land drilling leadership as HP, PTEN, PDS and NBR collectively guide to higher rig counts. These four players expect their rig counts to rise in the range of 12 to 19 rigs between now and the end of Q3. That’s a 4-6% improvement from their current counts. Using Friday’s BKR U.S. land rig count of 473 rigs, a ~5% increase, if achieved by all other U.S. drillers, would imply we exit Q3 near 500 rigs. Most noteworthy, however, is HP’s call for the U.S. rig count to rise another ~50-75 rigs between now and year-end. If correct, this puts us in the 525-550 vicinity. Further, the company sees further rig demand surfacing in 2022. To that point, most E&P companies passed on providing any formal 2022 outlook, but we do point out HES suggested it could take its rig count higher. The company recently reactivated its second Bakken rig and it plans to increase the Bakken rig count to three rigs in 2H’21 (+50%). Next year if commodity prices hold, it may ramp to four rigs, but won’t go above that (a 33% increase). One data point clearly doesn’t make a trend, but if HES is representative of the U.S. E&P universe (which it isn’t) and if HP’s outlook for YE rig count is correct, then simple arithmetic puts the U.S. land rig count in excess of 600 rigs during 2022. As a reminder, we have a $1 bet with two smart E&P’s that the BKR land rig count will hit 625 by March 31, 2022. Unfortunately, messaging from many of the public E&P’s this past week is on continued capital discipline with a focus on FCF for debt reduction and shareholder returns. The tone, which could change, is not yet supportive of our optimism, so there’s a better chance than not we will be on the hook for $2.
E&P Capital Spending. Capital discipline persists. Didn’t see any evidence of increases to D&C spending budgets, but ample evidence 2H’21 D&C spending is flat-to-lower. Also, several companies are spending below budget, thus the implied 2H’21 spend calculated below may prove too high (i.e. MTDR, EQT). Exception to flattish spend is HES as its budget is 2H’21 weighted; MTDR bringing forward some wells now in Q4 vs. Q1; while CVX noted plans to increase Permian 2H’21 activity.
- COG: 1H’21 capex = $290M. 2021 capex budget = $530-540M. Implies 2H’21 = $245M.
- SWN: Q2 capex = $259M. Q3 to “trend lower” with “a further decrease” in Q4.
- HES: Q2 E&P capex = $429M. Q3 budgeted at $575M. Q4 implied = $587M.
- MTDR: 1H’21 D&C capex = $227M. 2021 budget = $525-$575M. Implies $323M in 2H’21.
- SM: Q2 capex = $214M. Q3 capex guide = $170-$190M. Implied Q4 = ~$80M.
- OVV: 1H’21 capex = $733M vs. $1.5B budget – roughly 49% spent
- CNX: 1H’21 capex = $252M. 2021 capex = $450M (at mid-point). Implies $200M in 2H’21.
- AR: 1H’21 D&C capex = $308M. 2021 D&C capex budget = $590M. Implies $282M in 2H’21.
- RRC: Q2 capex = $120M; 1H’21 capex = $226M; implied ~$199M in 2H’21.
- CVX: Will add 1-2 rigs in Q1 as well as one frac crew. Presently running 5 rigs and 1 frac crew.
- EQT: Not apples-to-apples due to the Alta acquisition. Q2 capex = $246M. Q3 capex = $275M-$325M. The 2021 budget stands at $1.1B to $1.175B. Implies ~$350M in Q4. The Alta acquisition has $100-$125M of incremental capex as EQT will run one rig and one frac crew on this asset. Early look to 2022 calls for a $1.3B budget – basically flattish vis-à-vis 2H’21 run-rate.
Frac Fleets: PTEN to add two fleets (going from 8 to 9 in Q3 and adding fleet 10 in Q4). Mammoth to add one fleet (going from 1 to 2). RES running 6 fleets but will add fleet 7 shortly. LBRT not providing specifics but implying no expected change to “fully staffed” fleets which are remain in the low 30’s. Calfrac U.S. fleet count at 9 fleets with guidance calling for no reactivations. We should get more fleet granularity soon from NEX and FTSI.
Frac Profitability. Quick take on the respective annualized EBITDA/fleet metrics for SMID-cap frac names. This exercise requires some level of guestimates on our part as not all companies provide active frac crew counts; others don’t provide pressure pumping segment EBITDA, others capitalize fluids ends while some expense them. Moreover, in some cases we use consolidated EBITDA in the numerator whereas in other situations we are able to use a segment EBITDA. Further, some companies consolidated results include other service lines, thus we don’t have a clean pressure pumping number. Basically, this becomes a guess, but when companies provide poor disclosure, it’s the best we can do. So, here’s our SWAG on fleet profitability. In the coming week or two, we’ll throw this into excel for interested readers.
- PTEN: ~$4M/fleet. Assumes 6 fleets.
- RES: $5-$6M/fleet. Assumes 5-6 fleets. PPS Q2 revenue = $72M with estimated ~10% EBITDA margins.
- LBRT: ~$5M/fleet. Assumes 31-33 active fleets.
- CFW: Negative Q2 annualized EBITDA/fleet due to one-off items. Best guess is the clean annualized EBITDA/Fleet would have been in the $1M vicinity. Q2 was burdened by equipment moves, so not a good indicator of the business.
Looking ahead, only PTEN provides specific Q3 guidance for its frac business. The company sees pressure pumping revenue up 30% q/q to $150M with a 9 active spreads. Gross margin is expected to be $18M. Using Q2 G&A expense for the segment implies Q3 pressure pumping EBITDA of ~$16M. On an average of 9 fleets, this implies ~$7M EBITDA/fleet, a nice improvement relative to Q2 results.
Upcoming Auctions. Another Superior Energy Auctioneers event upcoming on August 11th in Oklahoma City. This event will feature a myriad of business lines, but one which interests us is the liquidation of ME2 well service. This will feature the sale of several well service rigs – all 2007/2008 vintage. We would normally attend this auction, but we’ll be in Midland that week.
Sell-Side Interest. The following are the number of sell-side Q&A participants on OFS vs. E&P calls. Not surprising, there continues to be less relative interest/engagement in OFS vs. E&P.
OFS: BKR (9), HAL (8), NOV (7), CHX (6), HP (6), LBRT (4), RES (4), BOOM (4), PTEN (4), NBR (4), SLCA (4), SOI (2), RNGR (3), CFW (2), OIS (1)
E&P: CVX (13), OVV (11), HES (10), EQT (9), AR (8), SWN (8), RRC (7), MTDR (7), XOM (6), SM (6), CNX (4).
Random Observation. Hat’s off to MTDR for executive leadership’s praise of the performance of its two frac providers – Universal and Halliburton. What makes the shout out noteworthy to us is MTDR’s specific acknowledgement about each company’s crew performance. Moreover, MTDR leadership stated the merits of keeping a crew together. In their own words, MTDR stated “we wanted those same guys to continue to work for us, so that instead of releasing them, so somebody else can get the benefit of their skills and their ability to get many fracs done in a day, we’ve elected to keep them, which has brought about lower cost, greater efficiency.” This recognition, we believe, would support our contention that low-bid does not always result in low-cost. In the days of efficiency, we submit crew continuity matters and it appears MTDR understands this.
Q2 E&P Anecdotes. The following are company and/or thematic specific anecdotes which we found interesting. These bullet points don’t touch on the impressive FCF generated by the E&P sector, nor do we touch on the voluminous commentary on reduced emissions, impressive production/well results and/or plans to enhance balance sheet and/or increase returns to shareholders. All are very important, of course, but these data points below focus on activity and efficiencies.
- SM: Running three rigs and two frac crews in the Permian. Average lateral lengths = 11,300’. DC&E costs at $520/lateral foot. Completed first simul-frac which hit a max of 24 stages/day and averaged 16 stages/day, 2x the pace of the company’s typical zipper frac. Also, drilled a lateral of 20,900’ in 20 days which SM notes is the longest lateral in the state of Texas. In South Texas, SM is running two rigs and one completion crew. The average South Texas lateral is 12,000’.
- OVV: Averaged 3 Permian rigs and 2 Andarko rigs; using in-basin, wet sand in the Permian. Growing use of Simul-Fracs. In the Permian, OVV completed 3,500 lateral feet per day and pumped 9.5M pounds of sand per day on a single pad. In the Anadarko, OVV averaged 2 rigs. All wells in the STACK were completed using Simul-Fracs with D&C costs per well at $430/foot YTD. The company achieved a new spud-to-release record of 5.9 days. OVV has four rigs running in the Montney.
- EQT: Expected to run 2-3 HZ rigs and 3-4 frac crews. This is up due to the Alta acquisition.
- MTDR: Running 4 rigs and will stay at four rigs. Running two frac crews and will bring forward the completion of ~11 wells from Q1’22 to Q4’21. Average laterals exceed 12,000 feet
- AR: Running three drilling rigs and two frac crews. Set company record for stages/day in Q2 at 9.8, a 23% improvement over 2020 levels. Set a monthly record of 10.7 stages a day in Q2 as well. Wells drilled in Q2 had an average lateral of 11,740 feet. AR drilled its longest lateral to date in the Marcellus which totaled 18,858 feet.
- CVX: In the Permian, CVX shifted from diesel fuel drilling rigs to electricity powered / nat gas powered. Will use nat gas powered technology for completion crews. Added a frac crew in July and will add another crew before year-end. Running five drilling rigs and will add 1-2 more in late Q3/early Q4.
- CNX: Running one rig and one frac crew. Likely stays at this level.
- SWN: Averaged 5 rigs in Q2 and two frac crews. Average lateral length was 14,000 feet. Production is expected to be flat YE’21 to YE’22.
- XOM: Achieving same drilling lateral lengths today with 8 rigs vs two years ago with 25 rigs. Completion times running 50% faster too.
- RRC: Wells placed online in Q2 totaled 25 with YTD TIL’s at 41. RRC has another 18 wells to be turned online this year, thus activity in 2H’21 moves lower. RRC is running two dual-fuel rigs. Average lateral lengths were 12,000 feet with five wells exceeding 16,500 feet. Completed over 1,100 frac stages in Q2, up 6% vs. Q2’20.
OFS Observations / Guidance: We went through the transcripts somewhat quickly this weekend with a focus on L48 comments. Apologies if we missed anything consequential.
- SOI: Averaged 53 fully-utilized mobile systems in Q2. Similar utilization expected in Q3. SOI continues to return cash to shareholders with 11th straight dividend. Debt free. Healthy cash position.
- SLCA: Expects flat oil & gas proppant volumes in Q3. Witnessed a 17% q/q improvement in Q2. Received sizeable legal settlement of $128M which helps strengthen the balance sheet. Contribution margins likely stay in the ~$10/ton vicinity with Oil & Gas. New product innovations in Industrial to drive growth long-term.
- CLB: Guidance for Q3 calls for revs to improve to a range of $122-$126M, +4% q/q at the mid-point. Operating income totaled $13M in Q2 with Q3 guidance of $14-$15M expected.
- CHX: Q3 revs expected to increase to $765M-$805M vs. $749M in Q2. Q3 EBITDA guided to $119M-$125M vs. $105M in Q2. Mgmt sees U.S. drilling growing but at a moderated pace.
- PTEN: Land drilling Q3 rig count expected to average 81 rigs, up from Q2 average of 73 rigs. PTEN will exit Q3 at 83 rigs vs. 79 today. Drilling gross profit expected to improve to $46M from $42M in Q2. Margins/day flat q/q at ~$6,250/day. Pressure pumping revenue to grow ~30% q/q to $150M with gross profit of $18M. Active spreads = 9 in vs. 8 in Q2. Company will have two Tier 4 DGB fleets by early 2022. 2021 capex = $165M.
- HP: U.S. land rig count to exit between 127-132 rigs. Today HP’s at 123 active rigs. North America Solutions gross margins will range between $72M-$82M vs. $75M in calendar Q2. International Solutions margins expected to be flat at ($2M) to $0M. This compares to ($1M) in calendar Q2. Company expects capex to be towards the low end of FY’21 guidance of $85-$105M. For HP and other drillers, quarterly results continue to be negatively impacted by reactivation costs. During calendar Q2, this cost HP about $6M.
- MRC: Q3 revs up low-single digits sequentially while 2021 revenue should be up mid-single digits y/y. Q4’21 revs will decline seasonally, but at the low end of the historical range. Gross margins likely hang in the realm of 19.5%, but MRC sees improvement to its EBITDA margins. Objective is to push EBITDA margins to ~7% vicinity in the coming quarters (was ~5% in Q2). Total debt declined by $85M in Q2. MRC will continue to focus on debt reduction. Noted July backlog was up 7% vs. June. Also, MRC quantified potential “green” projects as it is tracking 30 biofuel projects, 21 carbon capture projects and 12 hydrogen projects. MRC’s opportunity set with these projects could be ~$40M.
- OIS: Q3 revs to improve 4-5% q/q. Offshore Products should see a book-to-bill greater than 1.0x. Well Site Services and Downhole Technologies should see margin expansion in Q3. Full-year 2021 EBITDA guidance now estimated at $40-$44M. 2021 capex budgeted at $15M with $3M spent in Q2. OIS called out a number of large offshore project potential in 2022.
- RES: Noted low double-digit revenue in Q3 was in the realm of possibility. Would think +10-15% given the fleet reactivation (DEP thought).
- NBR: L48 cash margins were $7,017/day in Q2 vs. $8,466/day in Q1. Q3 cash margins guided similar to Q2. NBR’s L48 rig count today is 67 rigs with the Q3 average rig count guided to 68-70 rigs.
As always, this note is not intended to be investment advice, nor should any of the company commentaries be considered an investment opinion or recommendation.
Comments are closed.