04.03.2023 DEP Industry Observations: Ovintiv buys Encap Permian for $4.3B, OPEC Announces Cuts; Haynesville/Permian Takeaways; Fed Survey

Macro/Headlines/Events

Exciting Monday as OPEC surprises the energy world with 1MM BBL/day cut to production and a nice size M&A transaction in the market.

BB- Ovintiv to Buy EnCap Permian Oil and Gas Assets for $4.3B ($3.1B cash and 32.6MM shares)  Deal includes EnCap’s Black Swan Oil & Gas, PetroLegacy and Piedra Resources.

WSJ- Saudi-Led Oil Producers to Lower Output Further New cuts to total over a million barrels a day; the move led to a surge in oil prices Link

WSJ- Japan Breaks With U.S. Allies, Buys Russian Oil at Prices Above Cap-   Link

Source Baker Hughes/DEP

DEP Update:  Excellent turnout at last week’s Midland reception, so we are hosting another one in less than three weeks!  Truth be told, we will be back in Midland to cook for the Bynum kids, so we are assembling another get together for those who really like wine.  The reception will be on April 19^th – let us know if you are interested.  Before then, we travel north to OKC/Tulsa for meetings on Tuesday, followed by our Houston golf outing on Monday, April 10^th – capacity is 68 golfers, we have 65 – someone needs to skip work and join us.  Special thanks to Jack McIntyre and ASAP Industries for helping us with this golf event.

DEP In Basin Observations Podcast.  In honor of opening day this past week we released one of our panels from THRIVE as a podcast. In this episode, Sean Mitchell and Bill Herbert sat down with Rich Kushel from BlackRock in a fireside chat to discuss his views on the energy industry, BlackRock’s relationship with the industry, the current investment landscape, and his experience leading BlackRock’s portfolio management group. As always, let us know your thoughts and pass along to others you think might enjoy. Our discussion with iNet is coming up next.

https://linktr.ee/inbasinobservations

Research

30,000 Foot Comment:  Lots of color below from our trip to the Haynesville and the Permian, but all of the field anecdotes gleaned in recent day very likely take a back seat to today’s OPEC news which implies an unexpected cut is coming.  More on that below.  With respect to the field trips, the big picture takeaway is feedback from very recent discussions is getting better (and again should be even better with the OPEC+ announcement).  From the E&P perspective, (1) WTI is back above $70/bbl, trading recently near $76/bbl; (2) service costs are easing as equipment availability is rising while (3) market fears associated with banking uncertainty appear to be calming as well.  Collectively, the mood suggests a pronounced industry deceleration is less likely.  From the service perspective, two private Permian frac companies shared growing inquiries for work with both expressing more confidence in 2H’23 as schedules are now full.  This contrasts somewhat from others who we believe do have some white space on the calendars.  Private land drilling contacts acknowledge some price concessions, but no imminent risk of a major rig count decline.  One contractor has reduced price while another is doing “horse-trading” whereby some rig package items are thrown in for free.  OCTG pricing characterized as moving lower, but comments from OCTG contacts implies to us the concessions are manageable. Sand comments remain constructive as no real pricing pressures yet, despite some expansion of sand capacity which at least a few view as a headwind later this year.  Again, views were expressed prior to the OPEC news.  So, put it altogether, in some respects this feels like a normalization of activity with the magnitude of potential OFS pricing changes being the big unknown and frankly, a bit nuanced.  Moreover, if oil prices vault higher on today’s OPEC news, then the need for price concessions diminishes, although we presume the asks for concessions will persist.

Energy Ruminations – OPEC/Saudi Surprise (authored by Bill Herbert)

• Saudi and five additional OPEC members have announced a production cut approximating 1 MBD.
• The Saudi Press Agency (SPA) announced that Saudi Arabia will implement a production cut of 500 KBD beginning in May and targeted to last until YE. The SPA conveyed that this is a “precautionary measure aimed at supporting the stability of the oil market.”
• In typically elliptical fashion, further sporadic production recalibration announcements have been forthcoming from Iraq (211 KBD), UAE (144 KBD), Kuwait (128 KBD) and Algeria (48 KBD).
• According to OPEC secondary sources, most recently reported OPEC production was 28.9 MBD (Feb). Saudi Feb production was ~10.4 MBD. Recent peak OPEC production was 29.8 MBD (Sept) and recent peak Saudi (Sept) output was ~11 MBD.
• Should this production cut be fully implemented, pro forma OPEC production would land in the vicinity of ~27.9 MBD (down 1.9 MBD from recent peak) and Saudi 9.9 MBD (down 1.1 MBD from recent peak output).
• Further, Kazakhstan is expected to trim 78 KBD and Oman 40 KBD. And in the Russian hall of mirrors, 500 KBD of cuts have been announced.
• This is somewhat of an unexpected development as the consensus view heading into the OPEC conclave was blithe serenity (coupled with mounting rationalizations as to perceived trading vs. fundamentally driven price weakness) and full steam ahead with pre-existing production levels.
• With OPEC+, it’s always wise to watch what they do rather than what they say.
• The consensus sell-side view has been China is super-awesome vs. growing evidence that the PUD (pent-up-demand) recovery from Covid dystopia is mixed, with pockets of considerable strength and pockets of unforeseen anemia.
• Moreover, by now we all know that the global economic outlook is fragile and subject to exceedingly turbulent surprises, with banking dislocations being the latest disturbance.
• In truth, there is a lot we don’t know: 1) Slope and duration of China PUD recovery, 2) Resilience of Russian exports 3) Depth and duration of banking dislocations, 4) Hard/Soft/No landing for US economy, 5) How much will OPEC cut, 6) When will SPR replenishment begin, to name a few.
• What this does indicate is continued vigilance and rational guardianship on the part of Saudi with respect to market balances and oil prices.
• We’ll see how much of the production recalibration is rhetorical vs. de facto as it could well converge with the early stages of a foreseen global demand inflection – if the latter does indeed happen then the concern will revert from too loose to too tight. Stay tuned.
• Energy supply/demand outcomes continue to be disproportionately influenced by government policies, globally. Key drivers continue to have wide range of outcomes.
• The wild ride for oil continues.

Haynesville and Midland Thoughts:  Travelled north on Tuesday/Wednesday to Shreveport for the DUG Haynesville (well attended) with stops along the way for meetings in East Texas.  First, apologies in advance to our NLA friends, but Shreveport is a nasty city which, upon departure, often requires an industrial soap-based bubble bath and a visit to confession.  Thankfully, our oil and gas contacts are great people, which makes the trip much more palatable.  What made this particular trip a good one is the doom-and-gloom we anticipated hearing was, in fact, quite balanced and positive relative to expectations.  Recall, conversations with E&P contacts nearly two months ago led us to believe upwards of a 40% rig count reduction could be a reality in 2023 should nat gas go sub-$2.50.  Interestingly, gas prices today are even weaker, yet apocalyptic messaging is fading.  Let’s use the BKR rig count to assess activity and where we may go from here.  Per BKR, the Haynesville count peaked at 72 rigs.  It now stands at 66 as of this past Friday.  In our most recent rig count forecast, we model the rig count declining to an average of 54 rigs later this year.  That’s an 18-rig count decline or roughly 25%.  As we surveyed local contacts this week, we queried their bet on high 50’s vs. low 50’s by YE.  All took the high end.  One E&P who had previously alluded to a potential 40% drop in its activity shared this week the expected decline will not be as severe.  So, the trajectory is still down, but perhaps not as bad as originally feared.  Meanwhile other members of the DEP team went to Midland on Tuesday as well.  With WTI vaulting higher late last week, we couldn’t help but get the sense that stability will likely rule the day, assuming some service price relief develops (again, a pre-OPEC takeaway).  True, not a major revelation, but tracking sentiment in this business matters and it’s amazing how different one’s mood can be based on the tape.  Following today’s OPEC news, we would anticipate the mood in Midland will be even better in two weeks when return.  Look for more color then.

Here are a few trip anecdotes:

• One Haynesville completions-oriented contact reports its February revenue was down over 50% vs. January with March flattish with February (mostly utilization driven).  Two other Haynesville service companies, also tied to completion-related work, report record months in March.  The oilfield is nuanced and one’s customer matters.

• One Haynesville contact reports labor pressure is easing.  To prove the point, we were shown a stack of resumes on the desk.  The resume influx began about six weeks ago and includes rig hands from competitors (well service, not drilling) seeking work as their rigs went back to the yard. On the other hand, a wellhead company is still struggling to find ‘good’ people.

• Labor rates have not declined yet, but the company flush with resumes will offer positions to two people at $2/hour less than the existing hourly rate ($28/hour to $26/hour).

• Our Uber driver is a mechanic at Barksdale Air Force Base.  The young lad’s tour is almost up and he has an offer at $35/hour outside the oilfield.  Tough to compete with those starting wages.

• We believe 3-4 four frac fleets have left the basin.  Contacts claim two from one company and one fleet from two other companies.  In Midland, one contact confirmed a rig has recently moved from the Haynesville to the Permian and is now purportedly rigging up.

• One of our friends in Midland said he drives by a yard every day that has historically been used for storing drill pipe and casing.  This yard has been empty for over a year, but in the last 2 months the yard is purportedly filling up with casing and pipe.  This is consistent with the message we have been getting on casing, that pricing has softened.  In Midland, we heard anecdotes that E&Ps are not having to prepay for casing 6 months out anymore.

• Pricing comments mixed.  One company reports quotes for certain services now down 30%.  That’s the most extreme example.  Most other anecdotes are much more subdued, but we did have someone who operates “dedicated” equipment report a mid-single digit price concession.  To be fair, we also have multiple other contacts who have not seen any decline in their pricing.  Again, the market is nuanced and it’s not all doom-and-gloom.

• Multiple contacts foresee a bigger Q4 seasonal/budget-related slowdown this year in the Haynesville.  This, we believe, is from specific customer guidance vis-à-vis their completion schedules.

• E&P operators in the Delaware claim well costs of $11-$12M/well do not jive with $70 WTI.

• Bally’s Casino advertises it has the loosest slots in Louisiana.  We found no evidence to corroborate this claim.

Energy Ruminations: Q1 Dallas Fed Energy Survey (DFES) – Growing Frustration and Uncertainty

Unsurprisingly, Q1 DFES results deteriorated sharply q/q. The business activity index gapped lower q/q from 30.3 in Q4 to 2.1 in Q1. The “Outlook” index dropped materially q/q while the “Uncertainty” index increased considerably.

E&P and OFS commentary/opinions (below – we combined/edited several submissions for efficiency) reveal a growing sense of frustration and uncertainty. The frustration is largely directed at government energy policy and the gap between what is said (energy security is paramount, SPR replenishment at ~$70/bbl) and what is done (unabated regulatory burden, continued pipeline permitting difficulty in most of the country, zero pull-through on SPR replenishment, to name a few). The uncertainty relates to an exceedingly complex macro outlook, recently compounded by the domestic banking trauma, not to mention the current moment of polycrisis and its likely durability, and the prominence of government policies, globally, in driving energy outcomes. Ultimately, however, the industry’s angst, particularly for E&Ps, is likely being driven by weaker-than-expected commodity prices and relatively unyielding operating costs.

E&Ps were consistently aggrieved over OFS pricing (one submission observed that pricing was easing, however, which is consistent with our channel-checks). Our supposition is that the pricing frustrations relate to what has happened (massive well cost inflation over the past twelve months as opposed to continued leading-edge pricing increases) and what isn’t happening (OFS pricing isn’t sufficiently responding to oil/nat gas price deflation), resulting in a colossal margin squeeze. E&Ps also consistently conveyed that the forward path for drilling and completion activity was lower as was the rate of US production growth. Improving oil prices and expanding margins, should they eventually be forthcoming, will likely alleviate E&P angst. Oil has become a waiting on China trade. Recent PMIs were mixed (services super strong m/m, mfg weaker) as have been multiple leading-edge indicators. Nonetheless, CNPC (China’s largest oil producer) earlier last week prophesied 2023 China oil demand growth of 5.1% or ~740 KBD y/y (IEA +970 KBD) – decent and it will need to be at least this given the current crosscurrents in oil (resilient Russian exports, growing uncertainty with the global economic outlook, etc.).   Notwithstanding, survey participants expect WTI to move higher over the course of 2023 and exit the year at ~$80/bbl (prior expectation ~$84/bbl), and HHUB to increase to ~$3.45/MMBTU by year-end.

The primary concern emanating from OFS relates to labor shortages and wage inflation. While the aggregate employment index eased q/q, the wages/benefits index increased q/q for both E&P and OFS (running hotter for OFS).  For OFS, the equipment utilization index collapsed from 32.8 to 3.9 and the operating margin index swooned from 25.9 to 1.9 – a bit surprising given the resilience of the rig count. The OFS pricing index moderated q/q but remained positive.

The following are highlights from the Q1 DFES.  Data for the Q1 survey was collected March 15-23 and 147 firms (E&P = 95, OFS = 52) participated.

• E&P Business Indicators: Level of activity = -2.1 (Q4 29.9); Oil Production = 10.5 (25.8); Nat Gas Production = 7.4 (29.4);  2023 Cap ex = 11.7 (38.2); 2024 Cap ex = 6.4 (35);  Supplier Delivery Time = -16.5 (18.6); Employment = 8.4 (14.4); Wages/Benefits = 37.8 (36); F&D Costs = 46.8 (52.5); LOE = 37.6 (48.4); Outlook = -18.9 (6.5); Uncertainty = 64.2 (45.4).

• OFS Business Indicators: Level of activity = 9.6 (Q4 30.9); Utilization = 3.9 (32.8); 2023 Cap ex = 27 (43.6); Supplier Delivery Time = -9.6 (7.3);  Service Delivery Time = 0 (20); Employment = 25 (45.5); Wages/Benefits = 53.9 (47.3); Input Costs = 61.6 (61.8); Service Pricing = 25 (43.6); Operating Margin = 1.9 (25.9); Outlook = -5.8 (24.5); Uncertainty = 59.6 (30.9).

• WTI price needed to cover operating expenses for existing wells: Permian (MB) = $29/bbl; Permian (DB) = $29/bbl; EF = $31/bbl; Other Shale = $33/bbl.

• Oil price required to profitably drill a new well: Permian (MB) = $58/bbl; Permian (DB) = $61/bbl; EF = $56/bbl; Other Shale = $61/bbl.

• Expected headcount changes in 2023: More than ½ of the respondents expect their headcount to remain unchanged this year vs. exit-2022. Slightly less than 40% expect headcount to increase (modestly), and less than 10% expect a contraction.

• Greatest influence on profitability this year: Cost inflation and the health of the global economy were each selected by 30% of respondents (collectively 60%) as the greatest driver of profitability this year.

• Primary cause of labor shortages: Forty percent of respondents cite the cyclical nature of conventional energy causing labor shortages while slightly less than 30% attributed the perception of limited career runway due to the energy transition.

• E&P respondent commentary/opinions: 1) The biggest threat to our business is the federal govt – multiple comments, along these lines, conveying increasing frustration with government policies, 2) Between govt regulations and oil and gas prices, it is becoming more and more difficult to remain in the energy business, 3) Capital providers have been politicized, hurting the entire industry, climate change activists are causing disruption, 4) Oilfield inflation is the number one problem, the dramatic increase in 2022 inflation has severely impacted project economics – service cost inflation combined with weaker commodity prices will negatively impact drilling plans, resulting in less activity, still waiting for OFS costs to catch-up to new commodity price levels, activity and production will likely decline due to higher well costs, 5) Oil prices have reached the threshold at which the govt said it would replenish SPR and yet no action has been taken, 6) The EIA’s L-T oil production outlook is a fantasy – the collapse in shale production will likely be forthcoming within the next five years, 7) Service costs keep rising and AFEs keep climbing, 8) Commodity price weakness feels like the sword of Damocles – where is oil going to bottom?, 9) The natty air-pocket has significantly shifted priorities from growth to preserving margins, 10) Oil in recession trades like a financial product as supply/demand fundamentals matter less, chickens seem to be coming home to roost, 11) Current low oil prices, coupled with the banking scare, will be harder on smaller, undercapitalized companies, resulting in tougher credit and lower reserve values due to lower new price decks, 12) There have been no direct impacts to our company, yet, but we are monitoring tremors in the banking system, 13) Cost relief for several OFS is buckets is unfolding and supply chain pressures have eased significantly, 14) Labor productivity is impaired due to market tightness and a less experienced labor pool, 15) W TX power generation capacity isn’t sufficiently growing while power consumption has grown by 50% over the past two years, 16) Outside investors seem to be losing interest in hydrocarbons, 17) The road ahead looks difficult but passable – we expect another “muddle through” period in a cyclical business where more players will be winnowed out.

• OFS respondent commentary/opinions: 1) Macro and regulatory uncertainty rule the day, 2) The likelihood of recession has increased, government at all levels is out of control, regulation is killing the nation, environmental issues are overblown to the point of the absurd, 2) Labor remains the most significant challenge, with shortages caused by inadequate wages and the volatility of the industry, and drug tests don’t help,  3) Finding skilled labor is the biggest challenge and wage inflation is impairing profitability, 4) Cyclicality and the perception that O&G is a dying industry make it hard to retain existing personnel and attract new ones –  would not recommend this industry to young people, 5) Bank failures have added to recession concerns, credit was already tight for OFS and conditions will likely tighten further making it tougher for companies without scale, 6) The adage “go hard now, bank as much as you can, and hope it is enough to get you through lean time we know are coming” is still true today.

E&P Observations:  No new bank failures meant that panic took a holiday this week, which combined with Iraqi disruptions and strong DOE inventories, led oil prices higher.  No such luck for natural gas, despite reports that Freeport LNG is finally back to full capacity (~2 Bcf/d) after an explosion closed the plant last June.  CHK clarified its rig activity in the Haynesville this week.  The company is moving from 7 rigs to 5 by Q3 in the basin, where it intends to stay through 2024.  CHK’s HV volumes will drop during this period, as the company estimates that it needs 6 rigs/2 crews to keep production flat.  FANG joined the UN’s Oil and Gas Methane Partnership 2.0, committing to monitor methane emissions on at least 90% of its operations by the end of this year.  FANG is targeting a 70% reduction in methane intensity from 2019 levels by next year.

The 2 Bcf/d Mountain Valley Pipeline is one step closer to resuming construction.  The Fourth Circuit upheld the project’s water-protection permit in Virginia.  A similar suit regarding the West Virginia permit is pending in the Fourth Circuit, and a decision is expected soon.  The project will move incremental Marcellus and Utica natural gas to the Mid and South Atlantic regions of the US.

EIA Monthly Report Takeaways (Authored by Bill Herbert): The EIA released its 914 monthly production data on Friday, March 31st. The 914 data is the highest quality domestic production data and has a three-month lag. Thus, the following summary pertains to data as of January. While Jan oil production, following Dec’s m/m weather-related contraction, was expected to be up m/m, the sequential gain was nonetheless stronger than expected, with total output averaging 12.462 MBD (+347 KBD m/m). The GOM registered the largest m/m gain with a sequential increase of +125 KBD, followed by ND (+97 KBD) and TX (+76 KBD).  EIA oil production projections for 2023 (12.44 MBD), which previously looked ambitious, now look plausible. Notwithstanding, we believe that Jan’s m/m gains will be the largest for some time given the increasing difficulty of sequential comparisons and the current stasis in drilling and completions activity. Going forward, E&P reinvestment, activity and production will be governed by commodity prices and E&P cash flow which has been meaningfully squeezed due to the collision of lower commodity prices and relatively unyielding well costs (starting to moderate on a leading-edge basis). The longer E&P cash flow duress persists the greater the eventual contraction in reinvestment and activity. But to date, resilience is ongoing.

Oil

• Jan US Oil Production:  12.462 vs. 12.1 MBD for Dec MBD, +347 KBD m/m (+87 KBD vs Nov 12.375 MBD – cleaner comp given the absence of weather gremlins) and +1.1 MBD y/y (easy y/y comp due to weather last year).
• Jan L-48 Onshore Production: 10.1 MBD, +200 KBD m/m, +890 KBD y/y.
• TX, NM, GOM Jan Oil Production: TX (largest US oil producer, by far, with over 50% of L-48 production) Jan production of ~5.237 MBD, +76 KBD m/m and up 384 KBD y/y. NM (3^rd largest producer behind TX and GOM) production of~1.792 MBD was up 19 KBD m/m and 449 KBD y/y.  GOM production of 1.914 MBD was up 125 KBD m/m and 206 KBD y/y.

Nat Gas

• Jan US Gross Nat Gas Production: 122.851 BCFD, + 2.75 BCFD m/m +7 BCFD y/y (again, easy weather comp).

• Jan L-48/GOM Gross Production: ~112.3 BCFD, +2.9 BCFD m/m, +6.5 BCFD y/y.

Refining Observations:  Another week of strong gasoline demand, with Q1 TD running about 2% higher than last year.  Distillate is another story, running 6% below last year QTD.  Warm weather is a contributor, but some fear consumer weakness could be impacting diesel demand.  Jet-fuel demand has also weakened noticeably over the past couple of weeks, but it is still running about 6% higher than last year.

California passed a law establishing a maximum gross gasoline refining margin and established a full-time watchdog to monitor refineries and retailers.  The state plans to penalize any “profit gouging” above its mandated level but will consider exemptions.  Capping margins in a capacity-constrained state looks to us like a recipe for shortages (or loads of exemptions).  Time will tell.

BKR U.S. Land Rig Count:  Down 3 rigs w/w.

Product Inventory, Demand, and Margin Charts

(Shaded areas show the 5-year range 2017-2021)

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

832-247-8215

jd@danielep.com

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