DEP Updates: We have a couple spots remaining at our November 10th golf outing. If the Astros lose tonight, which after the grand slam by Duvall looks likely, then you’ll see us in Midland on Tuesday/Wednesday. We’ll be in the DFW area late next week. Also, we are starting the outreach for THRIVE 2022 as we need sponsorship support. It’s no fun asking folks for money, so apologies in advance when we solicit you. The good news is our speakers list is nearly complete and it’s solid. We’ll present the working agenda within the next several days. As a reminder, the conference will be held at Minute Maid Park on February 22-24th.
BJ Energy Solutions. We visited with BJ Energy Solutions (BJES) this past week to learn more about its emission-friendly frac solution, the TITAN technology. Today, BJES owns/operates five fleets – 4 conventional and 1 TITAN. Given strong demand for emission-friendly frac equipment, the company now has contracts in place to build another four TITAN fleets; however, strong customer inquiries are expected to translate into additional contracts before year-end. Presently, BJES expects to have at least a total of seven TITAN contracts within the next few months.
Most of the new TITAN fleets are destined for the Haynesville, but discussions for the future fleets would take TITAN to other markets. A social media post from a BJES employee late this week indicates TITAN is looking for employees to staff the first Canadian TITAN fleet. Presumably, TITAN will also find its way into other U.S. basins. What’s notable is all new fleets are backed by term contracts with purported returns which we would characterize as attractive. Frankly, securing term contracts makes sense; it’s good business; and it is a practice the industry should pursue. According to BJES, it won’t build a fleet without contractual support.
The TITAN design is unique relative to most other emission-friendly solutions. Here’s a super brief overview. It is a direct-drive turbine unit with 5,000hp power ends. Runs on field gas, CNG and LNG, but can use diesel if needed. Also, the turbine technology allows for shutdown and start-up cycles between stages, thus less idle time. The company contends its footprint is smaller than other emission-friendly solutions while its headcount per fleet is similarly smaller, a positive for fleet level margins. Specifically, BJES believes the TITAN design requires ~40% less trailers and ~30% fewer employees. Moreover, BJES contends its third-party emissions study would suggest the TITAN emissions profile is superior to most other solutions, including both Tier 2/Tier 4 dual fuel. There is, however, a dissenting view by companies who employ natural gas reciprocating engine solutions vis-à-vis those who use turbine solutions. Sadly, the truth is we have no idea which is best as DEP is a bunch of finance folks, not engineers. Further, DEP has and never will personally measure emissions so we won’t opine on the “lowest” solution. We’ll let those who write/publish white papers fight this out, something we believe BJES intends to do.
Another truth is we are somewhat indifferent as to which design is the best on emissions. And with all due respect to our frac friends, we don’t believe the customer really cares either (at least not now). Why? If having the actual lowest emissions profile was the key factor in the procurement decision, then why are we seeing newbuild fleet announcements/purchases/upgrades by HAL, RES, USWS, ProFrac, PUMP, LBRT, BJ Energy Solutions, Rev Energy Services, among others. For the most part, they all have a different solution. If, in fact, the contracting decision was strictly based on an emissions threshold, one would think there would be fewer offerings. Instead, the magnitude of the emissions reduction, in our opinion, doesn’t matter today as customers simply need something that reduces emissions. The good news for the frac participants is the inventory of equipment which address that need is sold out, thus the rise in newbuilds with contractual backing. In our view, the real driver for the E&P company is lower well costs, a benefit from using a fleet which reduces diesel consumption, an attribute which essentially all the new emission-friendly designs offer.
What we learned about the TITAN technology is it appears to be working. BJES claims its TITAN fleet is achieving ~400 pumping/hours per month, with one month nearly 10% better than that average. This performance is nearly 30% better than what is being achieved by conventional fleets. Also, BJES data suggests its first TITAN fleet has displaced over 4M gallons of diesel, a healthy savings to the customer. The combination of efficiency and fuel savings justify the contractual support, in our view, and is likely a key reason for the rapid growth in TITAN contracts. As for IP protection, BJES has been awarded 30 patents with more pending.
Field Anecdote: We had a service company reach out this week. Company claims the legal department for one E&P customer which operates on Federal lands purportedly determined the E&P is a Federal contractor. Thus, the service companies who work for a Federal contractor are now deemed to be Federal sub-contractors. This, in turn, necessitate all service companies’ employees who work for this E&P need to get vaccinated. Our service company said no way and is preparing to reallocate its equipment elsewhere. It will be interesting to see if other E&P’s will take a similar position.
BKR U.S. Land Rig Count: +2 rigs to 529 rigs.
Q3 Earnings Highlights/Observations: We did our best to get through as many transcripts as possible. Some got more love than others while a few we simply ran out of time and didn’t review. Apologies to anyone who is offended, but we’ll try to address some more next Sunday.
Service Costs (E&P Perspective)
- MTDR did not offer formal guidance but did say a 10-12% increase in service costs in 2022 would not be surprising. As important, MTDR noted the offset opportunities surrounding efficiencies. Specifically, MTDR cited reduced drilling times, reduced trips and completion efficiencies such as average completed lateral feet per day increasing from 1,250 feet/day in 2020 to ~2,500 feet/day on recent simulfracs. And best days where MTDR completed nearly 3,600 feet/day thus an indication the efficiency averages can rise.
- CVX acknowledges higher onshore dayrates for rigs, but states they remain below pre-COVID levels
- CNX wouldn’t address service costs, noting most of its equipment is contracted.
- EQT noted single digit inflation on thinks like steel, diesel and labor.
- No specific discussion and/or quantification by XOM, AR, SM, although several acknowledge higher steel costs and labor tightness. As with MTDR above, E&P’s rightly expect to see further efficiency gains which should mute some of the service cost price increases.
Efficiency / Technology Observations
- LBRT announced the achievement of 24 hours of continuous plug and perforation pumping time on two occasions.
- Vine Oil & Gas announced the longest drilled well in Louisiana. The well had a lateral of 15,240 feet with total measured depth of 27,520 feet. It was drilled in 35 days at a cost of $400 per lateral foot.
- NBR deployed the industry’s first fully automated rig. The PACE-R801 is operating in the Permian Basin and recently drilled its first well.
- Range Resources: Drilled 16 wells in Q3 with an average lateral of 10,600 feet, a 16% increase vs. Q2’21. YTD the company has drilled nine laterals over 17,000 feet. RRC also completed an average of 7.7 frac stages/day in Q3, a +23% improvement on a y/y basis. The company’s electric frac fleet eliminated 3.7M gallons of diesel this year, a savings of $6.8M.
- Antero Resources: Brought 16 Marcellus wells online with an average lateral length of 13,448 feet. AR set a company record on stages/day in Q3 with a second simulfrac completing 23 stages, a 28% increase from AR’s first simulfrac and a 64% increase from the prior zipper frac record of 14 stages per day.
- SM Energy: Drilled a 4-mile lateral in 20 days; longest lateral in Texas. The simulfrac well achieved a max of 26 frac stages a day with an average of 16 stages.
Frac Capital Equipment
- RES announced the purchase/deployment of a new Tier 4 DGB fleet.
- LBRT announced two multi-year agreements for its DigiFrac fleets. New fleets total two, but we suspect there will be more given the E&P zeal to go emission friendly.
Q3 Earnings Highlights/Observations
- Revenue = $654M, +12% q/q.
- Adjusted EBITDA = $32M vs. $37M in Q2
- LBRT claims Q2 results burdened by higher transportation costs ($12M) along with higher maintenance costs ($8M). COVID disruptions also negatively impacted operations.
- LBRT will acquire PropX for $90M, of which $13.5M is in cash. No financial details provided, but the PropX transaction allows LBRT to fully integrate a last-mile solution.
- Announced two multi-year agreements for DigiFrac. Not a surprise and more agreements would seem reasonable.
- The DigiFrac contacts are further validation of the push by E&P companies to adopt emission friendly fleets.
- No mention of working fleets during Q3, but we will assume low 30’s (i.e., 33). Annualized EBITDA/fleet would appear to be roughly $4M. Adjusting for the unusual trucking costs and other issues, one could argue the “clean” number would be closer to $6M. Keep in mind, LBRT benefits from vertical integration of sand, it sells fluid ends to 3rd parties and it operates a wireline business, thus the actual EBITDA/fleet would be lower than $6M.
- The challenge with EBITDA/fleet comparisons between the frac companies is it is increasingly an apples-to-oranges comparison (i.e., vertical integration, effective vs. active reporting, who has more simulfrac, etc.).
- Cash = $35M with $121M in debt.
- Q3 capex = $56M, up from $38M in Q2
- Revenue = $225M, +19% q/q.
- Adjusted EBITDA = $26.5M vs. $17.3M in Q2.
- Operated 7 fleets in Q3, but will average 8 fleets in Q4.
- Deployed 1st Tier 4 DGB fleet into the Permian in late Q3.
- No current plans to add a 2nd Tier 4 dual fuel fleet.
- No formal earnings guidance, but Q4 is likely flat with Q3.
- Cash = $81M with no debt.
- Q3 capex = $19M with 2021 capex budgeted at $65M.
- The new fleet is being leased.
- Revs $1.3B, Adj EBITDA $56MM (includes $41MM of eliminations and corp costs)
- FCF = $66M; Cash = $1.67B and LT Debt =$1.7B
- Wellbore: Revs $507M, EBITDA $77M
- C&P: Revs $478M, EBITDA loss of $5M, Orders $384M, book to bill 144%, Backlog $1.1B
- Rig Tech: Revs = $390M, EBITDA =$25M, Orders $300M offshore wind installation vessels drove ½ of orders. Book to Bill 190%, Backlog $2.7B
- NOV sees improving outlook in 22’ driven by higher economic activity and higher backlogs.
- Offshore wind installation business remains on track to achieve revenue run rate of $400M/yr by Q422’.
- Coiled steel up 200% y/y, hope the worst of steel inflation behind us.
- Spot ocean container rates from Asia are 5x what they were last year and 14x what they were in 2019.
- Most interesting trend in 3Q per NOV was rising number of inquiries on offshore rig reactivations.
- NAM seeing higher quoting activity particularly around dual fuel conversions.
- 4Q Guide: Wellbore – Revs should be up 3-6% with incremental margins around 20%; C&P Revs should be up 10-15% with incremental margins in mid-30% range; and Rig Tech Revs should be up 8-12% with incremental margins in the mid-teens
- Revenue = $524M,
- Adjusted EBITDA = $125M vs. $117M in Q2 (increased despite NBR sale of Canadian rigs)
- L48 drilling rig count averaged 68 rigs in Q3, up from 64 in Q2.
- Current L48 rig count at 72 rigs.
- NBR sees its Q4 L48 rig count averaging 73 rigs, thus implying 1-2 more rigs go to service.
- L48 cash margins were $7,025/day in Q3. Q4 expected to be flat.
- International rig count averaged 67 rigs and is expected to increase 4 rigs in Q4
- International cash margins were $14,375 but should decline to $13,000-$13,500 in Q4 as Q3 benefitted from non-recurring early termination revenue.
- Net debt declined to $2.3B from $2.42B.
- Q3 capex = $63M. Fully year 2021 capex is expected to total $270M, thus Q4 capex should total $91M.
- Revenue = $358M, +23% q/q.
- Adjusted EBITDA = $51M, +44% q/q.
- Q3 rig count = 80 rigs vs. 73 rigs in Q2.
- Q4 rig count guided to 106 rigs, which includes 13 Pioneer rigs (apples to apples 93 PTEN rigs)
- Cash margins = $6,300/day in Q3 but will dip to $5,500 day in Q4 due to rig reactivation expenses and cost inflation, but margins should rise in Q1.
- Frac revenue = $153M vs. $112M in Q2, +36%.
- Frac gross profit = $17.9M
- Frac EBITDA = $16M, up nearly 100%
- Q4 revenue guided to $167M, +9% q/q with gross profit = $18.5M.
- PTEN running 10 crews now with one crew returning in Q4 and going to 12 crews in Q1.
- Two crews focus on simulfrac, one in Permian and one in Northeast
- The 12th crew will be PTEN’s 2nd Tier 4 dual fuel fleet.
- 2021 capex budget remains $165M with YTD spend at $91M.
- Revenue essentially flat at $118M vs. $119M in Q2.
- U.S. top improved but was offset by decreases internationally.
- Negative impacts to Q3 include GOM weather, supply chain headwinds and international COVID restrictions.
- EBIT essentially flat at $13M, equating to an 11% margin.
- Inventory up $5M q/q as CLB carrying higher levels given supply chain constraints. Mgmt noted some product sales which were expected to ship in Q3 were held up due to shipment delays.
- Net debt improved by $5M to $171M.
- FCF in Q3 = $9M, most of which went towards debt reduction.
- 2021 capex budgeted at $12-$14M, no change.
- Guidance: Q4 revenue guided to $121-$124M (+4% at midpoint) with operating income of $13-$15.5M, an implied margin of ~12%.
- Items of interest to DEP include commentary on CLB’s oriented perforating technology as CLB sees growing acceptance of this technology as testing indicates well performance is highly correlated to
- Q3 FCF = $91M with Q4 FCF expected to exceed $300M.
- 2021 FCF expected to total over $900M which should increase to $1.5B+ in 2022.
- AR has repaid nearly $700M in debt since the end of 2020.
- Presently running 3 drilling rigs and one frac crew (vs. 3 rigs/2 crews at time of Q2 earnings release)
- Q3 capex = $161M vs. $168M in Q2
- Long term plan calls for a cumulative 310 gross wells drilled from 2021-2025 with 80-85 drilled in 2021. Plan calls for a cumulative 315 gross well completions with 65-70 completed in 2021, thus completion cadence increases slightly over time.
- Q3 capex = $298M
- Q4 capex budgeted at $300-$350M.
- EQT plans to drill 32 net HZ wells in Q4 vs. 24 wells in Q3
- EQT plans to complete 33 net wells in Q4 vs. 23 wells in Q3
- In response to a reserves questions, EQT noted reserves could go up if the company ramped activity, but that wouldn’t be the case. Further confirmation EQT likely stays at/near maintenance spending.
- FCF very strong. Expects $950M in 2021 and potentially $1.9B in 2022 and perhaps as much as $2.6B in 2023.
- Company cited improved drilling times on the Alta acreage.
- EQT not focusing on further M&A today.
- Generated FCF of $130M in Q3, up from $117M in Q2 and $101M in Q1.
- Q4 implied FCF expected to approach $150M.
- Company increased the share buyback plan by $1B.
- Debt reduction continues with net debt reduced by $29M in Q3 while total reduction since YE’19 exceeds $520M.
- Share repurchases since last year total $175M.
- No deviation from the one rig and one frac crew program.
- 2021 capex range tightened to $460-$470M from $430-$470M.
- YTD total capex = ~$350M, implying ~$115M for Q4 (up from $97M in Q3).
- 6 wells drilled in Q3; 8 wells completed.
- Average lateral length = 12,329 feet
- Company’s 2021 plan calls for 37 wells to be brought online.
- Commentary suggests CNX doesn’t plan to deviate from its maintenance capex strategy.
- FCF will continue to go towards buybacks and debt reduction.
- No discussion of a potential spin-off of the company’s Industrial Sand Products segment.
- Our focus is on the SLCA’s Oil & Gas segment.
- O&G Q3 revenue = $142M, – 2% q/q.
- O&G volumes = 2.9M tons, -4% q/q.
- SandBox loads = Down 5% q/q.
- Contribution margin down 24% q/q to $8.83/ton in Q3
- SLCA noted Q3 completions activity slowed (i.e., HAL, FTSI data corroborates) – another confirmation that certain third-party frac count reports are wrong.
- Q4 O&G volumes expected to be down due to seasonality, but SLCA sees a stronger market in 2022, claiming completions activity could be “frothy”. We think completion market is better next year, but we are not quite ready to embrace “frothy” – simply too much purported capital discipline by most reporting E&P’s (EQT, CNX, AR).
- SLCA sees E&P spending growth up 20-25% with particular strength in 1H’22. Believes completion activity could increase similar amounts. Our concern with this forecast is rising service costs and how much that eats into activity.
- SLCA noted spot prices remain below contracted. Case in point, we were with a sand contact recently who claimed contracted prices for them were ~$20/ton, but spot was more like $16-$18/ton.
- Cash = $251M with total debt = $1.2B.
- Full year 2021 capex budgeted at $25M, lower from prior guidance. Q3 capex totaled $8.3M.
- Q3 FCF an impressive $66.5M.
- Q3 E&P capex = $498M and $1.2B YTD. HESS will spend $650M in Q4.
- Bakken capex = $169M in Q3 and $369M YTD.
- HESS now running 3 rigs in the Bakken.
- Company drilled 18 wells and completed 22 wells in Q3.
- Q4 drilling plan consistent with Q3.
- HESS may add a 4th rig but not until YE’22.
- Company repeats it will not need to return to peak level of 6 rigs.
- Bakken production was 148,00 boepd in Q3 vs. 198,000 in Q3’20. Q4 production expected to increase to 155,000 to 160,000 boepd.
- Bakken spud-to-spud averaged 11 days in Q3
- Q3 capex = $180M.
- Q4 capex to range between $111-$116M.
- Q3 production up 15% sequentially to 14.3 MMBoe.
- FCF = $147M with net debt reduced by $148M in Q3
- Nearest debt maturity is 2024
- SM drilled 14 net wells and completed 24 net wells in the Permian
- SM drilled 10 net wells and completed 11 net wells in South Texas
- 70-75% of Q4 production hedged at $41.70/bbl.
- Midland Basin: Running two rigs and one frac crew
- Average Midland Basin lateral is 11,300 feet
- Roughly 80% of the Midland Basin wells completed with 2,300 lbs of proppant with some wells testing at 3,000 lbs. SM noted wells with higher loading designs performing better.
- Drilled a 4-mile lateral in 20 days – longest lateral in Texas. The simulfrac well achieved a max of 26 frac stages a day with an average of 16 stages.
- South Texas: Running one rig and one frac crew. Average lateral is 12,000 feet.
CVX: EPS $2.96/share, CFFO $9B, $2.6B Dividends Paid, $625M of Share Repurchases, Repaid $5.6B in Debt. Capex budget for 21’ was $14B, then revised guide to $13B in 2Q21’ and now lowered guide to $12-13B. On lower budget, about half is deferrals and half is efficiencies. Non op spend in Permian lower than expectations and deferred spend tied to Hurricane Ida and the Delta variant wave. Expect higher capex in Q421’ as only spent $8.1B through 3Q21. Q4 adding 2 rigs and 2 completion crews in Permian and higher activity levels at Tengiz, as well as some exploration wells. Capex guide for 2022 not changed and still in the $15-17B range. At the low-end spending will be +20% y/y. 5 year outlook in Permian shows CVX can grow production with capital and carbon efficient development from 600,000 bbls/d to 1MM bbls/d. Net debt ratio is just below 20%, the targeted range for CVX is 20-25%, so fast approaching a ratio where CVX could raise buyback guide. The goal on buybacks is for it to be ratable and maintain it through cycle.
Company summaries are not investment advice or investment opinions…