2.27.2023: DEP Industry Observations: Q4 E&P Thoughts; THRIVE Energy Conference Takeaways

Macro/Headlines/Events

Baker Hughes Rig Count- The US onshore rig count was down 7 rigs from 741 to 734 last Friday.  At our Thrive Energy Conference last week, most panelist took the under on the US onshore rig count being 800 by the end of 2023.

Interesting to see several investors seem to be putting less focus on ESG and more focus on returns. See the article below from Vanguard and read the comments from some investors at Thrive.

WSJ-Vanguard’s CEO Bucks the ESG Orthodoxy- Link

WSJ-Frackers Increase Spending but See Limited Gains- Link

WSJ-War in Ukraine Drives New Surge of U.S. Oil Exports to Europe- Link

WSJ-Peacetime Would Be a Black Swan Event For Energy-  Link

FT-US shale oil groups’ record profits threatened by cost inflation-  Link

Long note.  Sorry, we can’t help ourselves, but we are addicted to earnings call transcripts.  First, we kick off with takeaways from the Thrive Conference and then summarize data points from E&P earnings calls this week.  BTW – thank you to those who showed up.

DEP Update:  Sean travels west to Midland on Monday.  JD likely going to Lake Charles on Tuesday to sneak into LOGA’s meeting.  Then up to Dallas on Wednesday and then over to Denver on Thursday night /Friday morning.  Building meeting schedules now, so let us know if you are free. Later this week, we will send out calendar invites to those who replied for our April 10^th golf outing in Houston – we still have lots of spots so let us know if you want to play.  Working on our next Midland reception, Fort Worth dinner and Houston IR/CFO post-earnings season reception – details hopefully next Sunday.

Thrive Energy Conference – Attendee Takeaways.  Real quick as there’s lots of meat to chew on from Q4 earnings and our conference content takeaways.  While most attendees enjoyed the event, the initial critical feedback revolves around (i) the size of the event (i.e., some conveyed too big with some deterioration of exclusivity as we had just shy of 2,100 attendees); (ii) a few contend too much content, insufficient networking time; (iii) more diverse set of moderators needed; and (iv) too many salespeople.  Not agreeing or disagreeing yet with any of these observations, simply passing them along.  In addition, we are looking for more constructive feedback, so please submit ideas where you think we can improve.  We will do an internal debrief soon and will take client/sponsor feedback into consideration as we plan for 2024.  Lastly, the 2024 Thrive Energy Conference is set for February 20-22, 2024.  Ideally, we would have pushed it back one week to have less interference with earnings season, but there is a college baseball tournament already on the calendar at Minute Maid Park.

Research

Thrive Energy Conference Observations (Authored by Bill Herbert, Geoff Jay and Sean Mitchell):

1. Nat gas is complicated: Consensus view is that near-term we’re oversupplied, and drilling and completion activity needs to contract in order to rebalance the market. Weather remains a massive wildcard and a hot summer will accelerate the rebalancing process – on the other hand, a temperate summer will simply prolong oversupply. L-T, the domestic natural gas market will be further supported by the expansion of domestic LNG liquefaction capacity – 5-6 BCFD of capacity underway at present and targeted to be online by 2025-2026 (with additional expansion beyond 2026) – Good slide on this in the CHK IR deck.  NIMBY friction to building pipelines, however, is a severe impediment to a more rational and effective energy delivery system.  Currently, there are only three states where there is limited resistance to building pipelines – TX, OK and LA.  That’s it.  Until a more holistic, rational and long-term energy national strategy and policy framework is crafted and implemented, domestic nat gas will remain regionalized and Balkanized and a fundamentally challenged asset in regions where it has limited export outlet.

1. Oil – Near-Term Challenges, Longer Term Opportunity: Industry protagonists are realistic about near-term challenges and crosscurrents – bearish domestic inventory trends, Russian export resilience and anemic demand. Generally, people are hopeful about a China pent-up-demand surge unfolding in 2H but they aren’t front-running this possibility. They are cautiously optimistic about the longer-term due to obdurate deliverability constraints, inexorably rising demand and the convergence between energy and national security.

1. Permian Takeaway Capacity – Sporadic Solutions: Permian gas will remain quasi-stranded, apart from incremental solutions, until the Matterhorn pipeline comes online late-2024. The math on Permian gas production, according to one panelist, is that for every 1MBD of oil production growth, 3 BCFD (and rising) of nat gas production growth is forthcoming in the form of associated gas. Thus, the governor of incremental natural gas takeaway requirement will be dictated by Permian oil production growth. Some contend that takeaway occlusions will be a recurring problem every 18 months given rising GORs and ongoing production growth.

1. Permian Productivity Supernova of Yesteryear is Transitioning to a more Methodical Industrial Machine: The combination of basin maturation, diminished supply-chain flexibility, increasing GORs and structurally redefined capital allocation is coalescing into less propulsive oil production growth. The days of doing substantially more with the same and unbridled 1-2 MBD growth have become a historical artifact. Virtually without exception all our E&P panelists agreed that the current Permian reality is doing the same with more and that US black oil production growth would be challenged to attain 500 KBD this year. EIA is estimating 590 KBD, in part due to very easy 1H comps (1H’22 avg ~11.6 MBD, November ~12.4 MBD) – doable but not easy and in part contingent on depth and duration of the gas price implosion. Permian production stream is now basically 50/50 oil vs. nat gas/NGLs. Q4 earnings calls, by in large, reflected hotter-than-expected capex for 2023, relatively subdued production growth and cooler than expected FCF (PXD FCF guide for 2023 down more than 50% y/y). E&P margins are getting squeezed due to the confluence of cost inflation and commodity price deflation (#5 below). Winnowing inventory breadth and depth is becoming an acknowledged reality – what used to be perceived as decades of superabundant inventory is now viewed as ~5-10 years. Accordingly, E&P M&A momentum is building as companies look to augment inventory (#8).

1. E&P Margin Squeeze: Meaningful cost inflation converging with imploding commodity prices (HHUB down ~50% YTD) translates into margin and FCF pressure. This was the uniformly articulated current reality. BTW – this will have implications for E&P reinvestment and US production growth.  One large private E&P in the Permian said “today, we are less efficient and paying more, and that is hard”.  Another private E&P said, “we saw better economics in a $50 crude price environment than we do right now on a well level”.   In the Midland Basin twelve months ago a 10,000ft lateral well was $6.5MM and today the same well is closer to $9.5MM.

1. Permian Private E&P Sentiment: Near-term cautious due to the margin squeeze, longer-term optimistic. Feels like the asymmetry for drilling and completion activity, near-term, is lower rather than higher.  One of our private E&P’s in the Permian said, “the Permian Basin is running out of electricity” and views this as a potential headwind going forward.

1. OFS Pricing Has Flattened and Looks to Soften: E&P duress has historically led to OFS pricing moderation.  This moderation can be exacerbated by incremental OFS equipment supply and new competition. Permian activity has been resilient, but it feels like it has room to move lower – ditto OFS pricing.  Yet, some OFS players contend they remain sold out.  Moreover, most leading OFS players contend they will defend price vs. protect market share.  Should activity slow, a possible challenge will be the tension between letting people go vs. preserving what has been rebuilt in preparation for better years in 2024 and beyond.  Our gut says pricing softens, but as we have also conveyed in prior notes, we believe the industry hits a speed bump, not Armageddon.

1. E&P M&A Momentum is Building: Private equity panelists expressed that they are seeing, increasingly, a return of public E&Ps to the M&A arena. The impetus is a desire to reload inventory coupled with increased confidence in the duration of the oil and nat gas cycle. As one prominent Permian E&P humorously expressed, quoting a major integrated CEO, “there are too many CEOs per barrel in the Permian.” The Permian upstream industry remains fragmented and in need of consolidation.  Again, as it relates to the OFS community, there is a growing realism of risk associated with working for smaller E&Ps who may be sellers.  Therefore, does this create reason for some players to lower price in order to win the work of the consolidating E&Ps?  Time will tell, but we know at DEP, it’s no fun when a subscriber gets bought.  Would think the same applies to an OFS company.

1. Labor Challenges: On the one hand, the acute hyper-cyclical labor challenges of the last year are lessening, especially as the rate of activity growth has moderated/stagnated due to the margin squeeze burdening the E&P industry as a result of commodity price deflation converging with supply-chain cost inflation. On the other hand, structural labor challenges are amplifying due to the aging of the workforce, the swelling of retirement age employees, and insufficient regeneration of new and younger workers to offset the growing obsolescence of baby-boomers. All-in, the breadth of reinvestment and regeneration challenges confronting the oil and gas business is rapidly increasing.  The pace of experienced labor force obsolescence vs. the pace of labor force renewal and regeneration will determine, to some extent, the forward path of drilling and completion efficiencies.

1. International Upstream Visibility – Robust 2023 and Visibility Improving: ME, LAM and Africa expected to drive mid-teens capital spending growth and multi- year visibility is firming. SLB’s CEO called the current cycle an “energy super-cycle.” To us, the current fundamental backdrop has similarities with the robust cycle of the early 2000s, when a combination of well-behaved demand, limited OPEC spare capacity and constrained deliverability drove the need for sustained reinvestment over a multi-year period, resulting in durable revenue growth and strong incremental margins. The prominent difference today, is the need to friendshore our energy supply chains due to acute and growing geopolitical tensions.

1. Deepwater Inflecting: While offshore activity has been firming for ~18 months, DW has recently revived and is now inflecting. DW is expected to witness the most pronounced rate of growth this year.

1. Land Rig Commentary: Step-Change Improvement in Performance over the preceding ~decade as premium land rigs today are drilling 55% faster than they did in 2014. In 2014, the daily cost on a rig was approximately $12,500/d and today it is closer to $18,000/d.    One land rig executive believes there are 520 super spec rigs working today in the US (100% utilization) and if we see a moderate decline in rig count he believes it will be in SCR rigs.  Even if you assume high spec rigs get dropped as well and utilization goes to 90%, it is still a very tight market. Longer term contracts in the 2-3 year range are more likely for newbuilds or reactivations with a heavy capital cost.   That said, in Canada some customers are looking for long-term contracts and that is new.  Both executives on our land drilling panel believe that at current dayrates, the industry is not even close to new build economics for land rigs.  Moreover, should there be a call on another 100+ rigs in 2024 (i.e., oil and nat gas rally), there is a preference for dayrate vs. more rig reactivations.

1. Refining Opportunities and Threats: The refining industry appears poised to enjoy supernormal margins again this year.  Jet is expected to be the primary source of product demand growth this year (IEA projecting that ~1/2 of global demand growth will be fueled by Jet), with strong domestic and international demand (China PUD surge), and distillate remains firm.   On the other hand, our panelist suggested that gasoline demand has likely peaked in NAM, due to a combination of growing EV disruption and higher fuel-economy vehicle penetration. Accordingly, gasoline demand is unlikely to return to 2019 levels anytime soon, notwithstanding healthy VMT. While refining capacity is witnessing select expansions, largely in Asia and the ME, net worldwide losses of 4 MBD during the pandemic are an enduring reality.  US capacity continues to wither (apart from recent Gulf Coast expansions) as more facilities are mothballed and/or converted to renewable-diesel production.  This, plus very low levels of US inventory, should somewhat offset demand anemia.  Suppressed domestic natural-gas prices also make US refiners highly cost competitive in the global market.  In the very near term, the industry is seeing extremely high turnaround activity in 1H as a result of running at high levels of utilization in a high-margin environment. This could lead to slowing growth in all product inventories before driving season, and there may be some impact on gasoline production due to the loss of Russian VGO which was used to feed fluid catalytic cracking units.  As a result, “We’re not building the gasoline inventories as robustly as we normally would this time of year.”

1. Public Equity Buyside Perspectives – Constructive but far from a Feeding Frenzy: Buyside sentiment is constructive longer term but cautious and tactical in the current environment. Doesn’t feel like investors, at current prices, are trying to upsize their exposure and reweight higher. Energy has evolved from marginalized to relevant, but it remains a secondary sector for institutional PMs. The current SPX energy weighting of 5% would seem to corroborate this. Subsector preferences seem to lean to IOCs and refining while investors have become considerably more selective with E&P. Steadfast capital discipline, FCF and return-of-cash optionality remain the most important priorities for investors.

1. ESG – Improving Realism: There is virtually 100% alignment between industry protagonists and investors on the need to produce, transport and refine hydrocarbons responsibly. This entails lowering the carbon footprint across the energy value chain. There is also increasing cynicism and fatigue with the broader politicization of ESG, and the hectoring, lecturing and stigmatization of the energy industry. In this age of enhanced energy realism, where energy and national security have converged, the buyside understands that the pendulum swung way too far in what became viewed as an anti-oil and gas movement. At the same time, the need for a successful energy transition remains of vital importance. As a global asset manager expressed, ““an orderly and well-managed transition is good for the world and it’s good for economic growth and it’s good for our clients as investors.” Moreover, this same asset manager observed that he has 2,000 people reporting to him “whose job is to produce returns. None of them get paid based on the temperature of the earth.” A senior executive of a prominent money manager disclosed that they had recently parted ways with their head of ESG, implying that the gap between aspiration and efficacy remained too wide.

1. Energy Private Equity Investors – Some Are Happy with Conventional Energy, Some are Ambivalent and Have Yet to Return, Some Will Never Return: Energy (oil + nat gas) private equity investors can be segregated into three buckets: 1) recurring investors who are happy with their returns, improved capital allocation on the part of the industry and improved duration prospects, 2) prior energy investors who have been disengaged in the sector over the past few years but are now window-shopping due to the need for sustained reinvestment supporting duration, 3) prior energy investors who left the space and are never returning due predominantly to ESG concerns. Bucket #3 is sizeable one. This is yet another manifestation that the industry’s cost of capital remains formidable.

1. What was not Discussed but Should Have Been – Russia/Ukrainian Conflict and Potential Black Swans: While the subtext (the return of energy realism, the need for sustained reinvestment, “friendshoring,” etc.)  of the Russian/Ukrainian conflict was a prominent fixture at Thrive, there was little if any explicit discussion of the war and its broader implications. To us, the convergence of energy and national security is an inescapable, profound and enduring outcome. Are the energy markets currently pricing in the new age of energy realism? Not really. It’s currently all about a warm January. Has energy policy changed substantially to reflect the new energy reality? No, not really – NIMBY is the obdurate reality in the US. What would happen if, at this stage, the “black swan” emerged in the form of a cease fire? Would the world pivot back to the status quo ante and reembrace the illusion of energy superabundance and fungibility?  Or would the market and policymakers have the collective wisdom to recognize the world as it is, as it has become, rather than how we wish it to be? One can always hope.

E&P 2023 Capex Guidance – Q4 Earnings Season:  Budget commentary a tad misleading as folks need to zero in on the change relative to the Q4’22 run rate and not y/y.  Moreover, keep in mind, most companies are budgeting service cost inflation in the 10-20% y/y vicinity, but increasingly companies suggest prices not really going up from here.  Package the two together and the implication is flat-to-down activity as we suspect it’s more likely companies come in under budget than exceed budget given current commodity prices.  Further, a handful of companies report 1H weighted budgets and some contend service pricing concessions will be forthcoming.  And, as Travis Stice conveyed at Thrive – “the budget is the budget” which tells us most public CEOs won’t flex activity higher should commodity prices rise this year.  That said, nearly every speaker at Thrive foresees higher oil prices by YE’23 which would, in theory, portend well for 2024 budgets and activity.

E&P 2023 Capex Guidance:

• APA: $2-$2.1B, up from $1.8B 2022. Q4 annualized capex = $1.94B, so plan up 5% on this basis. US spend is 57% ($1.17B), up 39% from 2022, and up 21% from Q4 run rate due to Delaware tuck-in acquisition.
• CHK: $1,515-$1,575M vs $1,823 last year.  Q4 annualized capex of $2.1B, run rate not comparable due to Eagle Ford divestitures.
• CHRD: 2023 Capex of $825-865M, up 17%. Q4 annualized of $656M.
• CIVI: $800M to $900M vs. $989M in 2022 and Q4 annualized $1.1B.  Down ~14% y/y and down 22% vs. Q4 annualized.  Reinvestment rate around 50%.
• CPE: $1.0B vs. 2022 of $842M, +19% y/y.  Budget is 1H’23 weighted with 55-60% expected to be spent.  Q1’23 = $295M at midpoint vs. Q4’22 at $192M.
• CPE: $1B vs $842M in 2022. Up 7% from Q4 run rate of $936mm.
• CTRA: $2.0B to $2.2B vs. $1.7B in 2022, +24% y/y.  Q4’22 capex annualized = $1.9B or +9% vs. run rate.
• EOG: $5.8B to $6.2B vs $4.6B last year. Infrastructure spend will be ~20% ($1.2B), including a 36” pipeline from Dorado to Corpus Christi and EOG’s first CCS project.
• ERF: $500-550M in ’23 vs. $432M in ’22 and Q4 annualized of $346M.  The ’23 budget will be 60% 1H’23 weighted.
• FANG: $2.5-$2.7B vs $1.9B in 2022.  Not apples-to-apples given recent acquisitions.
• MTDR: D&C of $1,180 to $1,320M, up 62% from 2022, driven by Advanced Energy transaction, which is expected to close in Q2.
• PDCE: $1.35-$1.5B vs $1.1B in 2022. Q4 annualized = $1.38B, suggesting flat to low-single digit increase.  1H weighted—Q1 $400-475M, Q2 $325-400M.
• PR: $1.25-$1.45B vs $779M in 2022 (CDEV/Colgate consummated 9/22). Budget up 4% vs Q4 run rate.
• PXD: $4.45B to $4.75B (not including $150-200M of exploration spending to drill four Barnett/Woodford wells) vs $3.8B in 2022. Up 9% from Q4 annual run-rate of $4.2B.
• SM: $1.1B vs. 2022 of $880M, +25% y/y.  Q1’23 budget = $325M or ~30% of 2023 budget, thus implies spending to bleed lower over the course of the year.
• SWN: $2.2B to $2.5B vs. $2.2B in 2022, +7% y/y.  Q4’22 annualized = $2.1B implying 12% vs. the annualized run rate.
• VTLE: $625M-$675M vs. Q4 annualized run rate of $520M.  Not apples-to-apples given VTLE’s recent $213M acquisition.

E&P 2023 Activity Guidance:

• APA: US onshore of 5 rigs:  3 Delaware and 2 Southern Midland Basin. Dropping North Sea rig in response to windfall-profits tax implementation.
• CHK: Dropping 2 rigs in the Haynesville and 1 rig in the Marcellus, as well as reducing completion activity to address lower natural-gas prices.
• CHRD: 90-94 TILs, 50% 3-mile laterals.
• CTRA: Will bring 150-175 net wells online vs. 148 in 2022.  Permian net wells to rise from 61 in ’22 to ~80 in ’23.  Marcellus flat-to-down while Anadarko flat-to-up.
• MTDR: Running 8 rigs pro forma for the Advanced Energy transaction, a level which is guided flat.
• EOG: Added 2 rigs and 1 frac fleet, activity in EF and Delaware for 2023 will be relatively flat with Q4.
• FANG: Running 16 rigs, three simul-fracs and two zippers.  Will run 15 rigs and 4 simulfracs in 2023.
• PDCE: 3 Wattenberg rigs w/ 1 full-time and 1 part-time completion crew. 1 rig Delaware with 1 crew.  Will drop Permian crew after Q1 and reduce Wattenberg completion activity for a short period of time in Q3.
• PXD: Plans to run 24-26 rigs, including 3 in southern Midland Basin JV area and TIL 500-530 wells.  Added 3^rd simulfrac fleet in Q1.
• PR: 7 rigs currently but dropping to 6 rigs in Q2 due to operational synergies.
• SM: Running 5 rigs and 2 crews.  3 rigs in Permian and 2 in STX.  One crew in each region.
• CPE: Running 7 rigs, but likely drops to 6 rigs in 2H’23.  Running 2 frac crews with likely Q4 seasonal/holiday slowdown.
• VTLE: Running 2 drilling rigs today and throughout 2023.  Running 2 frac crews in Q1 but will drop to one frac crew for the balance of 2023.  Frac fleet is electric.
• ERF: Will run 2 rigs but will allocate some budget to refracs in Dunn county.
• CIVI: Will run 2 rigs and 2 frac crews.  Last year ran three rigs and at some points, three crews.
• CPE: 3-4 rigs in Delaware, 1-2 in Midland, and ~1 in Eagle Ford.
• SWN: Expect to average 10-11 rigs vs. 13 rigs in 2022.  Will average 4-5 fleets vs. 5 fleets in ’22.  Two rigs will be dropped in March and one in Q2.

E&P 2023 Service Cost Inflation Observations:

• CHK:  Expect 10% year over year inflation in the Haynesville, for Marcellus, less than 5% on a cost-per-foot basis.  On corporate level, total in low single digits on a net basis.
• CTRA: +10% over “calendar year 2022.”
• EOG: +10% vs last year, driven by higher costs for tubulars, rigs, and completions.  Seeing surface and intermediate casing costs softening, nothing on rig side yet.
• ERF: Budget assumes 10% y/y increase in well costs
• FANG: +15% year over year for well costs.
• MTDR: +10-20% service-cost inflation.
• PR: seeing “a bit of relief on the tubular side”. Had expected 15% inflation, plus or minus.
• PXD: Still assuming 10% inflation.
• SM: Assume 17% y/y inflation
• SWN: Mid-point of guidance builds in 10-15% inflation y/y
• VTLE: Assume 15% y/y increase vs. 2022 averages.

Interesting CEO Quotes from Q4 earnings calls:

• CEO of Civitas Resources: “So, I think with this environment, with the disconnect between service costs and commodity prices, I think the right thing to do is to sit back a little bit.”
• SVP of Operations of Coterra: “It sure feels like the market is starting to soften.”
• CFO of FANG: “the anecdotes are coming in that somethings are heading our way from a service-cost perspective, and unlike last year, not everything, not every line item will go up in the AFE.”
• CEO of Vital Energy: “This is a challenging time for our industry with oil and gas prices softening over the last few months and service costs remaining high, resulting in lower margins and cash flow.  History says the two will find an equilibrium, but this will take some time.”
• DEP editorial opinion – there is a perception that the decline in oil prices should warrant a price concession from service companies.  On the surface, that’s fair.  However, equally fair is the fact the oil service industry argued for nearly 18 months for price increases as oil prices rebounded throughout 2020/2021, yet service pricing really didn’t start to inflect higher until 2022.  Herein lies the greatest disconnect in the business today.  That is simply using the commodity price as the litmus test to where OFS pricing should be.  Our view is OFS pricing should be dictated by supply/demand, just as commodity prices are.

Random Observations:

• Not going to list all of the impressive FCF metrics this week, but needless to say, FCF guidance for E&P in 2023 is still impressive despite high service costs and low commodity prices.
• Civitas recently drilled a company best 2.5-mile lateral in 2.2 days – 20,600’ total measured depth.
• Vital Energy’s upsized ESPs called out for increasing (outperforming) well productivity – we’ll dig into this next month.
• Permian Resources noted an 11% q/q improvement in drilling efficiency and a 17% q/q improvement in completed lateral feet/day.  Improving drilling times are a contributing reason, we believe, for the expected rig count reduction (despite lateral length guidance rising to 9,300’).
• Solaris noted gas-directed activity slowing likely will yield lower system count q/q, although we suspect margins see uplift due to improving product mix and pricing.
• On the other hand, U.S. Silica guided proppant volumes to increase 3-6% and noted January was the best month ever for Oil & Gas profitability – likely a function of higher effective pricing.  Also, we sometimes talk about the OFS market being nuanced.  The SLCA guidance supports this as it has little exposure to the Haynesville, one reason volumes likely improve.  Longer laterals help as well as a recent mine closure in the Marcellus/Utica.
• E&P companies now talking about production growth not in absolute terms, but on a per-share basis.  Thank you stock buybacks.
• Most execs attending Thrive took the under on the U.S. land rig count at 750 rigs by YE’23.
• Air conditioning at Minute Maid Park is really, really expensive.  Hoping CenterPoint will sponsor next year.

John M. Daniel

Managing Partner, Founder

Daniel Energy Partners, LLC

832-247-8215

jd@danielep.com

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