Permian Observations. We had the pleasure of returning to the Permian once again with this trip marking the 113th night we have stayed at a Hilton properties YTD (not all work related, however). On this field visit, we caught up with contacts in multiple segments, but the general themes remain the same: labor, strong customer demand and service cost pricing. Topical this trip is the rise of COVID cases and initial signs it’s beginning to impact the field. Finally, we used this tour to dig into the water midstream sector and to visit an emerging Permian LNG plant. A snapshot of these observations is provided below.
COVID Considerations: By now, most are aware of the rising COVID cases with many new COVID cases occurring in vaccinated folks. We aren’t here to get into the vaccine debate, but rather to opine on the implications. In our travels the past two weeks, we have hosted dinners where expected attendees cancelled because they were sick with COVID. All were vaccinated. On the Permian tour, we learned of COVID cases popping up on well sites with two purported crews coming down with the virus. According to local Texas media, the 7-day average of daily cases is now just over 4,000, up nearly 70% over the preceding 7-day average while hospitalizations are up nearly 50% over the same time frame. Assuming this isn’t fake news, the data would seem clear: the Delta variant is pretty contagious with COVID cases rising and likely moving higher. This new development raises a big question – what will be the corporate policy with regards to sick and exposed employees/contractors?
Last year when we travelled around the country, most companies employed a vigorous preventive policy. That is, offices were closed, temperature checks occurred on site and in many cases, companies opted to be conservative with respect to COVID-exposed folks. Namely, sick employees were sent home while exposed employees went into quarantine. This was definitely the case for corporate employees. Now, however, a big difference exists. Drilling and completion activity is accelerating. There is an urgency to get the job done. This urgency, we contend, did not exist last year, at least not to the same degree. Further, the labor market today is tight, and companies don’t have back-up crews. Labor challenges were less severe a year ago. Today, E&P’s, who don’t have dedicated providers, are increasingly waiting for service company availability. So, if a field employee contracts COVID, will the service company pursue the same conservative policies as before? Will an E&P company opt to enforce more restrictive rules? In other words, would a company suspend operations for safety reasons? And, is COVID considered a safety reason? Or, is it full steam ahead? We honestly don’t know, but neither did some of our contacts. In fact, this past week a few admit the speed of COVID’s rebound was not expected and now a game plan needs to be established. So, while we don’t have an answer, we do wonder if 2H’21 could be characterized by D&C choppiness if COVID cases prevent and/or cause activity disruptions. Time will tell, but for companies without an established action plan, it may be worth developing one.
Recognizing The Big Picture. Pay attention to all the tidbits because they collectively point to the Big Picture. It’s a bit like solving a jigsaw puzzle where the final piece, in this case, came from prepared comments during the HAL Q2 earnings call. Notably, HAL recently held a customer day in Duncan, Oklahoma. According to HAL, “several hundred people from more than 40 operators” came to Duncan to learn more about HAL’s investments in electric and dual fuel technology. That’s a great indication of a developing herd mentality, but this shouldn’t come as a huge surprise. Recall from our prior notes and/or recent company press releases:
- DUG takeaways note last week where we reported a new frac start-up which is likely to build multiple emission-friendly fleets
- The ProFrac / US Well Service press release where both parties are materially stepping up their investment in electric fleets – each likely to build at least three fleets each
- U.S. Well Services purchase of 120 electric motors
- BJ Energy Solutions term contracts for four newbuild TITAN emission-friendly fleets
- Successful field-testing announcements from NexTier and Liberty on their respective electrification initiatives
- Recent NOV equipment day displays for customers
- ProPetro’s opportunistic purchase of Tier 4 dual-fuel units
- Cummins introduction of its Tier 4 dual fuel solution
- The emergence of companies such as VoltaGrid and Life Cycle Power
- Telluride Conference Takeaways where we cited lengthening lead times for frac capital equipment – perhaps why US Well Service proactively ordered 120 electric motors
- Telluride Conference Takeaways where we cited power-related OEMs who are “all NDA’d up” – a sign of burgeoning demand
- A recent DEP field tour where several E&P companies joined us to learn more about hydrogen’s ability to be used in Tier 4 engines
- Smart Oilfield Solutions introduction of Tier 4 pumps for its pump-down operation.
These are but a few data points, all within the past year, which speak volumes about the growing interest for emission friendly equipment. And, as we have noted in prior epistles, the amount of emission friendly equipment is in very tight supply today. For this reason, we will see a more material uplift in frac pricing for these assets in the coming months. Moreover, the pressure to utilize cleaner emission equipment is poised to take-off. With elevated lead times, the ability for the industry to quickly meet this demand will be limited. Therefore, we suspect more companies will benefit from contractual arrangements as witnessed with BJ Energy Solutions. We also suspect we’ll see a surge in new fleet orders – best guess today is we see orders/deliveries of ~30 new fleets over the next year (many of which are underway/announced, thus included in our tally). And for those smaller companies who wisely invested in newer generation equipment, they now become ripe consolidation candidates.
Alkane Midstream: The LNG market, like water midstream, is not our core competency, thus more time learning on our team’s part will be required. That said, a new LNG plant owned/operated by Alkane Midstream is on the precipice of being fully operational. The facility, which we visited, is located just outside of Seminole, TX. It soon supply LNG to the Delaware and Midland basins. To our knowledge, it is the first operational LNG plant within the basin, but it’s not Alkane’s first foray into LNG. The company was formed in 2014 and previously operated a plant in North Dakota. That plant is now being moved to Seminole, but while operational in Tioga, the plant produced/sold 57 million gallons of LNG. Initial customers are expected to be E&P’s who will use the LNG for frac operations. While it is early days, the development of this facility should play a central role for those willing to reduce emissions via alternative fuel solutions. Furthermore, with growth expected in both the dual fuel engine market as well as electric, the backdrop for LNG demand would seemingly look strong as well.
Water Midstream. Our tour included a visit to a top-tier water midstream player’s NM/TX operation. Our background with water is dated. In a prior life, a former employer had a water business, but this was largely water transport, vacuum trucks and SWD’s, not the pipelines and recycling which we toured. There’s a big difference as one is commoditized while the other is defensible. And while we don’t have a detailed water analysis to provide in this note, we were simply struck by the technology employed in the office and the professionalism of the engineering teams. Combine these two factors with a service offering which is defensible (i.e., lead times for SWD permits; time to drill the permits; time to build out a pipeline infrastructure, cost to build out this list, etc.) and one realizes this is a good business with staying power. The margins, we believe, would support our contention. Furthermore, the backdrop is good with D&C activity poised to rise, thus more demand for water transport and recycling. And, of course, don’t forget the tremendous ESG benefits of this model (i.e., water recycling and reduced truck traffic due to use of pipelines). Finally, the business model is not as labor intensive as other OFS businesses while safety statistics, most likely, are far better.
OFS Pricing Anecdotes. All sectors are now attempting to raise rates. Common themes from most discussions are the initial price increase salvos are generally single-digit percent increases. No need to shock the customer which could force them to move to other providers. This view, however, is debatable given the current labor challenges. Also, companies generally recognize the initial increases are really not enough to offset inflationary cost pressures and/or justify higher capex spending. Moreover, price increases often lag higher costs, thus the OFS sector is perpetually trying to catch up. Also, the zeal to maintain/expand market share doesn’t seem to go away. This leads to discounting when discounting might not make sense.
As for specific anecdotes. Leading edge dayrates for “hot” rigs are now hitting the $20,000/day level. Heard this in Midland but PDS reaffirmed the pricing data point on its earnings call. Companies will, however, reactivate idle rigs in the mid-teen’s assuming some term is behind that work. Idea being the rig will reprice in early 2022 at a very healthy rate given the “hot” status and a stronger drilling market. Frac pricing moving up with one contact reporting efforts to secure a low double-digit price increase. The contact claims the negotiated price ended up mid-single digits with the potential for performance-related bonuses. Another frac company reports price increases off the bottom of 15-20%, but current pricing remains below pre-COVID levels. Well servicing and coiled tubing rates are similarly moving up, but these contacts still report rates which are below pre-COVID pricing levels. Meanwhile, operating costs for all companies are higher than pre-COVID levels. Moreover, frustration continues with some OFS contacts claiming increases are delayed due to pricing agreements. Here’s the rub. When the cycle collapsed, OFS companies contend they immediately lowered prices at the customers’ request. Now, activity is rising, cost pressures are acute, and relief is needed, yet customers claim increases can’t go into effect until the end of the term of the pricing arrangement. Yes, this is the OFS party line and there are always two sides to the story. That said, we believe the obstinance and delay tactics will lead some OFS companies to consider a more assertive pricing strategy when the pricing arrangement terms expire. Finally, last week we professed our view that OFS pricing would be up ~15-20% this time next year. We maintain this view and if we were Vegas, we would take the over (this assumes current commodity prices hold, no COVID shutdowns, etc.). However, we should clarify this view with a stipulation that well costs likely do not rise as much due to efficiencies.
Land Rig Activity. Privates continue to move the rig count higher. Updated with a private E&P which will add two rigs (1 to 3). Dayrate commentary consistent with price quotes up $4,000+/day. Another E&P with whom we met is likely to increase its rig count by ~33% while a third E&P will add one rig (+50%). These little guys make a big difference.
BKR U.S. Land Rig Count: The ascent continues with another +7 rig count improvement. The BKR U.S. land rig count now stands at 473 rigs. Gains largely found in the Permian Basin with the Permian rig count now at 242 rigs or ~51% of the total U.S. count. On its earnings call, BKR prophesied the North America rig count should move up another ~50 rigs before year-end (no breakdown of U.S. vs. Canada).
Permian Frac Crew Count: Local updates from industry contacts suggest the Permian frac crew count is at ~97 fleets, +/- 2. The fleets are operated by 19 frac companies with the top three providers operating an estimated 45% of the Permian fleet count. Of the 19 frac companies, we believe roughly 8 of the players are likely sold out. These companies, we submit, maintain roughly 20% of the estimated active market share.
Other: Equipment maintenance activity is on the rise, but evidence of equipment issues still exists. First, we drove by a refurb shop just south of MAF airport. This facility in prior drive-by’s typically had frac trailers in the single digits in the yard. This trip we saw at least twelve, including light blue units which we’ve never seen before. If anyone knows who operates light-blue pump down units, let us know, but we saw about four in the yard. Point of this ramble is further evidence the maintenance cycle is heating up (i.e., increased units in for repair). That’s a point we made following a similar drive-by of a shop in OKC two weeks ago. As for equipment quality, we had an E&P note its two recent spudder rigs both broke down on the job. Delays in securing new parts are a problem.
Tactical M&A: Very small deal but Cathedral Energy Services bought the directional business from Precision Drilling for $6M, along with a $3M cash investment by Precision as well. Consideration comes in the form of Cathedral shares to PDS. This deal provides consolidation in the directional market and allows Precision to exit a non-core business.
Q2 Earnings: Our abbreviated observations. Not a stock opinion.
HAL: Revenue of $3.7B +7% q/q and operating income of $434M +17% q/q. C&P revenue was $2B +10%q/q and operating income was $317M +26% q/q. D&E revenue was $1.7B +5% q/q and operating income was $175MM + 2% q/q. C&P was driven by higher activity across multiple product service lines in NAM. Interest expense was $120M for the quarter and will remain flat in 3Q. HAL will redeem $500M of 2021 Senior Notes ahead of schedule in August as they continue to delever, which will reduce interest expense after 3Q. Capex for the quarter came in at $190M but is expected to stay in the 5-6% or revenue for the full year. Guide for C&P is high single-digit revenue growth q/q with slight 25-50bps margin improvement. D&E expecting 3-5% revenue growth and similar to C&P margins expansion q/q. HAL believes we are in the early innings of a multiyear upcycle and mentioned they are currently getting net pricing in some businesses today. They also mentioned Electric and Tier 4 Dual fuel is in very short supply, which is consistent with what we are hearing as well.
PDS: Strong Q for PDS with adjusted EBITDA (excluding a large stock-based comp charge) coming in at $55M. This compares to $55M reported in Q1. Activity is up, not surprising. PDS averaged 39 rigs in the U.S. in Q2, up from 33 rigs in Q1. Today, the U.S. rig count is running 42 rigs with 45 rigs expected to be running by mid-Q3. Management noted leading edge dayrates are now ~$20,000/day. In Canada, PDS averaged 27 rigs in Q2, up from 9 rigs in Q2’20. Today, Canada is running 52 rigs, a level which now exceeds 2018 and 2019. Management sees the rig count rising to the upper 50’s later this quarter with more reactivations expected in Q4. Most impressive for PDS is the sharp turnaround in the company’s well service business where Q2 activity was up 700% vs. Q2’20 and is now back to 2019 levels. Other things which jumped out to us. First, the company’s success with its AlphaAutomation continues with days up 30% q/q. And, this technology helped PDS secure a long-term contract for three rigs with a new customer. PDS did not disclose the price, but every discussion we have had with any land drilling contact leads us to believe a long-term contract likely has a price above the leading-edge spot rate. Internationally, PDS is running 6 rigs, but will participate in new tenders, thus additional rigs may go back to work in 2022. Feels reasonable given current commodity prices and OPEC+ plans to raise production. The balance sheet, meanwhile, should continue to improve as PDS sees strong FCF in 2H’21 which will be used to continue the company’s well-established plan to reduce debt. Since 2018, PDS has reduced debt by ~$600M. The goal is a cumulative reduction of $800M by YE’22.
BKR: Revenues of $5.1B (+8% q/q) with adjusted EBITDA of $611M (+9% q/q). Strong Q2 FCF generation of ~$385M (down from $500M in Q1 but had been guided by management). Balance sheet remains solid at ~1.1x leverage. Segment results, NAM OFS revenue increased 11% q/q and Int’l OFS revenue increased 6% (overall OFS rev: +7% q/q to $2.4B). In OFE (Oilfield Equipment), revenue increased 1% q/q ($637M) with margins expanding to 4%. In TPS (Turbomachinery & Process Solutions), rev: +10% q/q ($1.6B) with margins declining to 14%. In DS (Digital Solutions), rev. +11% q/q ($520M) with margins declining to 4.8%. As an equipment manufacturer book/bill matters for BKR, TPS book/bill 0.93x, DS book/bill 1.04x, and OFE book/bill 1.07x. OFS remains the near-term driver of earnings growth but remember the long-cycle opportunity set in TPS and DS will grow in importance over time.
As for Q2 highlights, BKR noted progress with its pursuit of new energy with comments on its arrangement with Samsung Engineering on CCUS and hydrogen technologies, its collaboration with Bloom Energy, its 15% investment in Electrochaea and a collaboration agreement with Air Products. All of these endeavors are part of BKR’s pursuit of low-to-net zero projects and highlight where, we believe, BKR’s focus will be medium-to-long-term. On that point, BKR alluded to improvement near-term with the traditional oil and gas business, but broadly speaking characterize traditional oil and gas as mature. As for guidance, BKR is committed to ~20% EBITDA margins in the OFS business, noting this likely occurs in 2022. TPS outlook is improving, largely driven by LNG growth with 2022 likely to see more orders (2021/2020 relatively consistent). Industry subsea tree awards characterized as some improvement in 2021 followed by some additional growth in 2022. Getting back to 2019 levels will be tough, however. Lots of meat in the transcript with constructive segment guidance in the prepared remarks. Of note, BKR’s ability to turn EBITDA into cash flow is commendable with a 50+% ratio expected. In the coming quarters, BKR will likely have the opportunity to return cash to shareholders although the company did not commit to a buyback in the Q&A.
FTI: Q2 Revs= $1.67B vs. Q1 Revs = $1.63B. Adjusted EBITDA Q2 /Q1 = 144.3 / 165.2 (-12.7%). Orders Q2/Q1 = $1.60B / $1.72B (-9.4%) – Subsea – $1.3B (50% of which = Integrated Projects (more profitable less competition). International awards continue to be a majority of surface activity with strength coming primarily from the Middle East (trees = 10x value of surface trees delivered to NAM). 60-70% of Surface business remains International, but company also saw an increase in orders from The Americas. Company remains optimistic on both sectors, but unsure of timing on 2H / 1H 2022 potential subsea awards. While FCF actually was negative for the quarter the company maintained their guidance for FCF in 2021 of $120-220M. Guidance: Subsea slight increase to revenue $5.2-5.5B (up from $5.0 – $5.4B) with EBITDA margins of 10-12%, Surface EBITDA margin expectations increased to 10-12% from 8-11%. No change to capex guide of $250M but comments suggest could be a bit lower
SLB: Adjusted EBITDA = $1.2B driven by 8% top line growth and 35% incrementals. Margins up 100bps to 21.3%. NAM grew 11% with US land up 19% q/q and int’l growth of 7%. FCF of $869M (including a $477M tax refund) improved from Q1 of $159M. SLB continues to expect double-digit international growth in the second half YoY while North America drilling upside could be driven by private E&Ps. Digital & Integration revs: $817M (+6% q/q) with margins up from 32% to 34%. Reservoir Performance revs: $1.1B (+12% q/q) with margin expanding from 10% to 14% (47% q/q incremental). Well Construction revs: $2.1B (+9% q/q) with margin up from 11% to 13% (36% q/q incremental). Production Systems revs: $1.7B (+6% q/q) with margin up from 9% to 10% (36% q/q incremental). SLB continued to delever its balance sheet, net debt declined to $13.0B due to the solid FCF generation and SLB repurchasing $665M of senior notes, resulting in a net debt/annualized EBITDA of below ~3x.