BKR Rig Count- US onshore rig count was down 4 last week from 745 to 741.
You have heard us say this before, Europe was the tip of the spear 10 years ago on ESG, solar, wind, and all things green energy. Today, partially due to the Russia/Ukraine war, Europe is the tip of the spear on reliable and affordable energy. DEP supports adding alternative sources of energy such as solar, wind etc. as we believe the world will need all sources of energy over the next several decades. We also believe when aspirations and economic reality are not aligned the transition from fossil fuels to alternative sources of energy could take longer than many believe. The recent articles out from BP in the FT and WSJ (see below) might suggest providing clean, reliable, and affordable energy are important, but returns are also important.
WSJ- Inside BP’s Decision to Dial Back Its Green Transition- Link to Article
FT- BP’s shift leaves a bigger question on credibility than climate- Link to Article
FT- Cash-rich US oil producers hunt for deals after long M&A dry spell- Link to Article
WSJ- For Mining EV Metals, the Arctic Is Hot- Link to Article
WSJ- Natural Gas: Fasten Your Seat Belts- Link to Article
DEP Update: The DEP team will be cooking for the kids/parents at Bynum School in Midland on Thursday, April 20th. We could use some help, so if anyone out there would like to assist, let us know. Another pit/grill would be helpful, along with some donations for items such as water, sides, paper goods, volunteers to help serve, etc. Working plan is to serve an early dinner to the families of Bynum and then hang out with the kids. Also, our next Houston golf outing is on April 10th at Deerwood Country Club in Kingwood. Thanks to Jack McIntyre from ASAP Industries for stepping up to help sponsor the event. Let us know if you would like to get involved.
Thrive Energy Conference: We are laser focused on Thrive Registrations. Numerous sponsors have yet to submit their registration lists, so get ready for pestering this week. We do this simply because you need to be registered to get in since Houston Police and RIP Security will be there to turn non-registered folks away. Hoping to have SWAT and attack dogs too (for non-clients/competition who try to sneak in). As of Saturday, registration presently stands at 1,011, +23% y/y. The latest agenda is attached. One more thing – we have a last minute sponsorship opportunity. We are seeking a Chick-fil-A Thursday lunch sponsor. You can be the hero with this one!
Land Rig Commentary: Four of the leading NAM land drillers have reported (HP, PTEN, NBR and PDS). Commentary is consistent: (i) rig count is flattening; (ii) dayrates and cash margins still moving up due to contract renewals; (iii) rig churn occurring and (iv) expectations for gradual improvements during 2023. With respect to near-term activity, here’s the guidance/comments as of the date of their calls:
- HP running 185 rigs; expects rig count to exit Q1 at 183-188 rigs,
- PTEN running 131 rigs today; expects its Q1 average to be 130 rigs,
- NBR running 95 with plans to add one rig,
- PDS U.S. rig count at 61 rigs today with the Q1 rig count guided essentially flat.
Collectively these companies are running 472 rigs with the combined exit rate expected to be between 470 and 475 rigs. Most report some churn in natural gas regions, but rigs which have been released quickly find homes (although the BKR rig count declined another 4 rigs this week, down 20+ rigs from recent peak). Several companies, such as PTEN and HP, have committed upgrades in progress, thus visibility for a company-specific rig count improvement is tangible, for now. NBR cited its usual customer survey which points to stable activity this quarter. For those not familiar with this survey, NBR contacted customers who represent 34% of the rig count and solicited their feedback on future activity expectations. The survey yielded a flat view in the near-term.
As for pricing, NBR cited recent contracts with revenue/day in excess of $40,000/day and that excludes NDS revenue content. PDS contracted a Canadian rig with a dayrate in the mid-$40’s (Canadian $$). Discussions with two private E&P’s this week confirm rigs contracted at a base rate of $38,500/day. Q1 guidance for most of the drillers puts blended revenue/day comfortably in the mid-$30,000 range.
While we don’t wish to be a Debbie Downer, we have had inbound comments from E&P companies claiming an increase in sales calls from both drilling and frac contractors. Basically, our contacts claim sales folks are calling and asking if they need equipment. Such calls, we suspect, were less frequent for much of 2022 when the market was tight. The key near-term risk, in our view, is the continued creep in incremental equipment, across all L48 verticals, in a flat-to-down market. Case in point, NOV called out the sale of three new CT units in Q4 as well as sales of new workover rigs. Small potatoes within those respective sectors, we concede, but this is just one anecdote from one OEM. Another example from this week, a pump down friend shared that his pricing ceased going higher in November and he sees new entrants entering the market. All is still good for now (but new competition entering in a flat market doesn’t feel too good to us). Meanwhile, we attended an industry event this week where we visited with several E&P and service contacts. No pushback to our cautionary narrative. Now, to be clear, we are not calling for Armageddon. We simply believe we are hitting a short-term speed bump. Given the recent sell-off in OFS onshore names, we suspect we are not alone in our view.
International/Offshore Is the Story in 2023: Using the land drillers as a proxy for International, the market looks strong. NBR through its partnership with SANAD received an award for another 5 newbuild rigs, taking the tally now to 10 rigs; PDS was awarded four five-year drilling contracts in Kuwait while it renewed three rigs in Saudi for five years as well; HP has a rig headed to Australia while it will also deploy multiple rigs to the Middle East and it will increase activity in Argentina. NOV’s results further validate the pivot towards international as Q4 international land revenue was up 13% q/q while NAM revenue was up only 1% q/q. Management called out 15 offshore rig reactivations in Q4, but also launched 23 new reactivations projects in Q4. Lastly, if further validation of a pending ramp in international is needed, just take to look at the number of awards WFRD received this quarter.
E&P Observations (authored by Geoff Jay): BP’s earnings commentary spiced up an otherwise light (to put it mildly) week of E&P earnings. The company is accelerating traditional oil-and-gas capex to support “energy security and energy affordability.” BP plans to spend an additional $1B/year in upstream, or a total of $8B by 2030 in shorter-cycle, fast-payback projects. It’s unclear how the additional capital will be allocated, but onshore US is a major component. Its BPX division is expected to grow by up to 40% by 2025 (~12% CAGR from 2022), or more than 100 MBOE/d. That’s more than ½ of the 200 MBOE/d of overall growth that BP called out in its presentation. BPX was expected to spend about $1.7B in 2022, and with the addition of two rigs in its Permian program in Q4, it doesn’t seem unreasonable to expect a higher figure in 2023. How much higher is unknown, but BP highlighted that it is seeing deflation, not inflation in the Lower 48, thanks to securing long-term contracts.
NOG provided an operational update.
- Q4 weather impacts of 10 MBOE/d (82% in the Bakken, remainder in Permian), so expects Q4 volumes to be “slightly lower” than Q3 (albeit with a higher oil mix), with full-year volumes of 75,250-75,550 BOE/d.
- Capex expected to be $143-145mm for the quarter.
- Repo of 1.1mm shares in Q4, with $96mm remaining on authorization.
- Retired ~$58mm of preferred, with the rest converting, further reducing share count.
- Dividend of $0.34 (4% annualized yield), up 13% from the prior quarter.
- Management recommending a further 9% increase for the next dividend payout.
APA announced a second successful flow test of its Sapakara South-2 appraisal well offshore Suriname. The test indicated incremental connected resource of more than 200 MMBbls of OOIP. APA has a 50% interest in this prospect, with TotalEnergies (the operator) holding the other 50%.
RRC released preliminary production of ~2,204 mmcfe/d in Q4, up 3% sequentially. Natural-gas production of 1,517 (+2%), NGLs of 108 MBOE/d (+8%), and oil of 7 MBOE/d (flat).
CRK announced Q4 production of 1,445 Mmcfe/d (up 3% sequentially), and full-year 2022 capex of $1.03B (~$262 in Q4). The company’s proved reserves were 6.7 Tcfe at year end, up 9% from 2021.
Social Media Observations: A private frac company posted on social media that it had two fleets available in the STX/Permian regions while another private frac company posted a request to “call for frac dates”. Maybe similar posts were made throughout 2022, but we don’t recall seeing any of them. Moreover, these quotes don’t feel like a market which is sold out. Of course, the equipment is likely not emission-friendly, and one could also reason these fleets are not on dedicated agreements or else why advertise? In other words, the market is nuanced and just because one company might have white space doesn’t mean all companies have white space.
Frac Capital Equipment Thought: We believe several private frac companies are/will introduce Tier 4 DGB later this year. Two reasons. First, dual-fuel equipment is in high demand (more about fuel savings than ESG). Second, for those who may have a desire to sell, an upgraded fleet makes a business more transactable to a larger public player.
Random Observations: Had time to visit with a few industry folks. One private E&P acknowledged it recently let go of two rigs – one in gassy region with the other in an oily region. Reason is simple. Low commodity prices and the company is patient. No reference to service costs. Two other E&P’s also opined on activity with one stating an intent to drop a rig in the Haynesville. That said, the Haynesville E&P contact will still drill 4 more wells in 2023 even with one less rig. The Permian private E&P will drill as many as 10 more wells y/y in 2023 with no change in its rig count. Smells like drilling efficiencies. One report of casing costs down 20% relative to prices paid last summer. Haven’t heard anyone else report that magnitude yet, so not sure if this is a one-off. A private completions-oriented person shared that training costs for new employees can range between $6,000 to $10,000 per employee, but only 1 in 4 new hires actually work out. Presumably, a reason for higher service pricing. Labor still remains tight with one E&P contact pointing out a frustration with so many green hats on location. One OFS contact also notes several 3-mile laterals in the Permian, thus service intensity continues to rise.
EIA STEO Summary (authored by Bill Herbert): The EIA’s February STEO (Short-Term Energy Outlook), while largely unchanged with respect to oil market balances, is markedly more bearish with respect to current-year natural gas prices largely due to “significantly warmer-than-normal weather in January.” January had 16% fewer heating degree days vs. the 10-yr avg and 9% fewer vs. the STEO’s forecasted assumption. As a result, the EIA now expects nat gas inventories to close the withdrawal season at the end of March at 1.8+ TCF (vs. March 2022 ~1.4 TCF), 16% higher than the 5-yr average. Accordingly, the EIA’s 2023 forecast for HHUB nat gas prices has been reduced from $4.90/MMBTU to $3.40/MMBTU (~30+% negative revision) – the EIA now expects nat gas prices to stay below $4/MMBTU until December. HHUB gas prices averaged ~$3.37/MMBTU in January, down ~$2+/MMBTU m/m. Current (Feb 8th) HHUB price is ~$2.40-2.50/MMBTU, Waha ~$1.70-1.80/MMBTU. As a rule, we don’t particularly favor specific price forecasts (prefer a range) for nat gas/oil as they convey a degree of precision that is illusory given the exceedingly high complexity factor governing them, including weather vicissitudes, which can swing wildly bearish or bullish, particularly for natty. Nonetheless, we’ve been of a view that nat gas prices have been an unappreciated threat to E&P cash flow generation and reinvestment, particularly with the takeaway occlusions in the Permian. The popular mythology about the Permian is that it’s an oil play, when, in fact, while it’s an indisputably important oil play, it’s increasingly a hybrid gas play (NGLs + natty ~45% of Permian production and rising?). Anemic nat gas prices, all else equal, will have implications for E&P reinvestment and US oil production growth. The following is a selected summary of the EIA’s domestic energy outlook.
- Brent Price Forecast: 2022 = $101/bbl, 2023E = $84 (prior $83), 2024E = $78 (prior $77).
- US Oil Production: The 2023 US oil production forecast was nudged higher from 12.41 MBD to 12.49 MBD, resulting in expected y/y growth of 590 KBD (prior estimate +550 KBD). While this appears ambitious, the projected growth is lubricated, in part, by easy 1H comps (1H’22 = 11.6 MBD, latest/Nov monthly result = 12.4 MBD). Thus, the 2023 estimate of average production is flat-to-up vs. November (the latest monthly print). Keep in mind that weather gremlins will likely suppress Dec and January production. Nonetheless, at first blush, the EIA’s 2023 estimate looks onside, particularly vs. OPEC’s expectation of 780 KBD of US y/y growth for this year. Conversely, the EIA’s 2024 estimate was lowered from 12.81 MBD to 12.65 MBD, yielding 160 KBD of projected y/y growth for 2024. We’ll see. We expect 2023 to be another wild ride with respect to price volatility given the wide range or perceived outcomes for China demand (our view = potentially cathartic) and Russian oil/product exports (our view = resilient), not to mention domestic nat gas prices and E&P cash flows.
- US Gasoline Demand – Anemic: The EIA is forecasting gasoline prices will decline in 2023 and 2024, after reaching multiyear highs in 1H’22. The forecast calls for retail gasoline prices averaging $3.39/gal in 2023 (2022 = $3.97) and $3.09 in 2024. For 2023, the EIA expects gasoline inventories to rise in the US. The EIA estimates that annual average U.S. gasoline consumption increased by ~300 KBD in 2022 and it forecasts a decline in gasoline consumption in 2023 of ~300 KBD in 2023, and flattish domestic demand in 2024. The EIA expects US refiners will continue to produce gasoline, even as prices decrease, to meet higher global demand for diesel. The EIA expects annual US gasoline demand will remain less than in 2019 (9.3 MBD) through the end of 2024. This is despite the EIA’s estimate that people drove more last year vs. 2019, pre-pandemic. The EIA forecasts a continuation of increased travel in 2023 and 2024, but increased fuel efficiency is expected to offset increases in VMT. And while the importance of the domestic gasoline market, in terms of size and scale, is self-explanatory, and the domestic gasoline ecosystem punches above its weight with respect to Wall Street scrutiny (relevant for domestic refining profitability and earnings), media coverage and US consumer confidence, the real driver of global oil demand growth isn’t the US nor is it OECD – it’s disproportionately China for this year (~1/2 of global projected demand growth), and India, SE Asia, ME and Africa beyond 2023.
- HHUB Price Forecast: 2022 ~ $6.40/MMBTU, 2023E = $3.40 (prior = $4.90), 2024E ~ $4.00 (prior $4.80).
- US Nat Gas production: The EIA estimates that domestic dry gas production in January established a new record at 100.2 BCFD. 2022 dry gas production is estimated to have averaged ~98 BCFD and 2023 is projected to average ~100 BCFD and 2024 ~101.7 BCFD.
- LNG Exports: 2022 = 10.6 BCFD, 2023E = 11.8 2024E = 12.6. LNG exports are expected to exit 2023 at 12.7 BCFD and 2024 at 13.9 BCFD.
Refining Observations: Another week, another sloppy EIA inventory report. Crude and products all showed higher-than-expected builds and anemic implied demand. Inventories remain at challengingly low levels, which has helped buoy margins.
- Production of 2.3 MMBOE/d (74% liquids), down >1% sequentially.
- US production of 618 MBOE/d (64% liquids), up <1%.
- bpx energy (Lower 48) production of 318 MBOE/d (39% liquids), down 8% sequentially.
- L48 rigs: 3 Haynesville, 3 Eagle Ford, 3 Permian (up 2 rigs from last quarter in Permian).
- In Lower 48, seeing deflation as opposed to inflation for 2023, vs. 10% inflation in 2022, thanks to securing longer-term contracts.
- Guide of 2.3 MMB/d by 2025, 2.0 MMB/d by 2030. Expect 200 MBOE/d from nine major-project start-ups, with bpx production growth of 30-40% by 2025.
- Q4 Capex of $7.4B.
- FCF of ~$6B (ex. working capital gains).
- 2022 Capex of $16.3B.
- Capex in $2023 of $16B-$18B, flat to up 10%,
- Increased dividend by 10%.
- Incremental upstream investment of $1B a year, or up to $8B total by 2030, targeting shorter-term, fast-payback projects.
- Committing 60% of surplus FCF to buybacks. At $60 Brent, expects ~$4B a year in repurchases.
- Revs = $511M, +73% y/y (look at y/y given Canadian exposure)
- Adjusted EBITDA = $91M, +43% y/y
- Repaid $106M in debt and repurchased $10M in stock.
- Running 61 rigs in the U.S. today
- U.S. revenue/day = $31,242/day with margins at ~$12,000/day.
- Running 78 rigs in Canada today
- Canadian revenue/day = $29,886 with margins at ~$12,400/day
- C&P Segment revs = $59M with EBITDA = $12M – a 20% margin
- 2022 capex = $184M with 2023 budgeted at $235M
- Targeting debt reduction of $150M in 2023.
- Revs = $788M, +8% q/q
- Adjusted EBITDA = $239M vs. $197M in Q3
- Averaged 131 rigs in Q4 vs. 128 rigs in Q3
- Running 131 rigs today with Q1 guided to an average of 130 rigs.
- PTEN will average 87 rigs under contract in Q1 or roughly 66%
- Q4 revenue/day = $31,830
- Q4 margin/day = $13,450, +29% q/q.
- 2022 capex = $437M with 2023 capex guided to $550M.
- PTEN announced it will reactivate an additional fleet, thus 13 active fleets.
- Rig count is expected to grow modestly as 2023 unfolds (PTEN has 8 upgrades/reactivations pending).
- Pressure Pumping revs = $307M, +7% q/q.
- Pressure Pumping EBITDA = $83.6M or approaching $28M annualized EBITDA/fleet per year.
- Directional revs = $59.5M with gross margin = $11.2M.
- Land Drilling: Cash margins to increase by $1,000/day.
- Pressure Pumping: revs to decline to $280M with gross profit declining to $72M.
- Directional: Revs to decline to $54M with margin of $9M.
- 2023 capex = $550M
- Targeting 50% of FCF for buybacks and dividends.
- Revs = $769M, +10% q/q
- Adjusted EBITDA = $230M vs. $190M last Q.
- Q4 L48 rig count averaged 95 rigs
- Q1 L48 rig count guided to 96 rigs
- L48 daily margins = $14,600 – an all-time high and +31% q/q.
- L48 daily margins guided to $16,100/day to $16,300/day
- International rig count averaged 76 rigs, likely gains 1-2 rigs in Q1
- SANAD awarded an additional 5 rigs, bringing total to 10.
- FCF in Q4 = $101M.
- NBR sees 2023 FCF = $400M – will be used to reduce debt
- Net debt improved $75M q/q in Q4
- 2022 capex = $382M with 2023 guided to $490M.
- Revs = $1.2B, +8% q/q
- Adjusted EBITDA = $266M
- Adjusted EBITDA margins = 22%, +290bp q/q
- Q4 FCF = $171M
- 2022 FCF = $299M.
- Repaid additional 31M of debt in Jan-23. Total debt is roughly $2.2B with cash of $1.1B.
- Numerous international awards highlighted in press release with a total of $6.5B in commercial wins in 2022.
- NAM revenue represents roughly 30% of total Q4 revs. Gained 1% q/q.
- 2022 capex = $132M vs. $85M in 2021
- 2023 capex guided to $200-$230M.
- Guidance: WFRD sees 2023 revs up low double-digits to mid-teens with full year EBITDA margins to improve 100bp y/y.
Product Inventory, Demand, and Margin Charts
(Shaded areas show the 5-year range)
Source for Inventory and Demand Charts: Energy Information Administration, Bloomberg, LP
Source for Margin Charts: Bloomberg, LP
John M. Daniel
Managing Partner, Founder
Daniel Energy Partners, LLC
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