DEP Update: Grab a coffee as this evening’s note is a tad long, a function of all the market noise this past week. We kick off with the 30,000-foot macro view and then look at things from a micro-perspective. The blend of the two, we believe, helps crystallize some of the unfolding realities. In terms of upcoming events/travel, members of the DEP team will be at the Piper Sandler Energy conference on Monday/Tuesday in Las Vegas. A very timely event. While we don’t envision E&P commentary deviating materially from Q4 guidance, we will be curious to hear the bar chatter about leading edge expectations. In time, one would assume a more tempered messaging will be forthcoming from both service and E&P companies, but we are too soon removed from earnings season to expect radical changes. For any Houston contacts, Geoff Jay will be in town this week conducting meetings and has availability. The following week the team will divide and conquer with some going to Midland (reception on March 28th) and some going to Shreveport. After that, it’s off to OKC/Tulsa to check in with friends up north. On-the-ground intelligence takes on greater importance during periods of market uncertainty, so it’s time to hit the road. For those who would like a day away from the office and who enjoy eating, drinking and/or golf, let us know. We still have about 12 spots left for our April 10th golf outing in Houston.
DEP Podcast: Better late than never. In our latest podcast, the DEP team sat down and recapped the THRIVE Energy Conference. Sean, Bill, Geoff and Bill Herbert go over the most insightful panels and what it means for the rest of the year in Energy. Keep in mind this recording took place before the current banking system malaise. Lastly, we are always looking for folks willing to do a podcast with us. Let us know if you would like to get on the calendar. Next up is our friends at iNet.
Energy Ruminations: Macro Turbulence, Opportunities and Threats (authored by Bill Herbert): Given current market volatility and macro turbulence, our inbound call volume has picked-up. The questions, understandably, are: 1) what now, 2) how bad does it get, 3) are oil supply and demand fundamentals unraveling? We’re in an environment of rekindling system risk and contagion fears. YTD, consensus expectations have evolved from: 1) soft-landing, 2) no-landing, to 3) a rapidly increasing likelihood of a hard-landing due to banking dislocations. While the sustained, multi-year reinvestment thesis for energy is plausible and supported by the convergence of national and energy security, durable deliverability constraints and obdurate demand growth in non-OECD ex-China, there’s nothing like an old school bank-run to eviscerate confidence and animal spirts. Events are in the saddle and moving at light-speed. Investors are now responding to negative momentum and industry protagonists are increasingly focused on near-term threats, rather than overweighting the quasi-secular dimensions of the energy reinvestment thesis as they had been over the preceding 1-2 years.
It’s easy to yell “fire,” when smoke and flames begin to emerge. The question is whether the current banking eruption is containable or the beginning of a conflagration which will have broader macroeconomic implications and aftershocks? The current preventive incantation is “this isn’t 2008.” Hope so. Think so. But are we revisiting the mid-1980s-90s? Larry Fink recently observed, “Prior tightening cycles have often led to spectacular financial flameouts. In the case of the S&L Crisis, it was a ‘slow rolling crisis’ – one that just kept going. It ultimately lasted about a decade and more than a thousand thrifts went under. We don’t know whether the consequences of easy money and regulatory changes will cascade through the US regional banking sector with more seizures and shutdowns coming.”
How will ensuing policy responses and interventions (Fed, Treasury, OPEC, US SPR Replenishment) play out? The Fed faces an exceedingly complex quandary, with core CPI running hotter than expected and cracks in the financial system becoming increasingly visible (SVB was the largest bank failure since the GFC of 2008, soon followed by the failure of two smaller banks, the CS drama is ongoing, and, as we write, FRC, which traded close to $150/sh in early-Feb, is hanging by a thread at ~$30/sh after requiring a $30B deposit infusion from Leviathan banks). Will the need for circuit-breakers and financial stability now supersede inflation as the top policy objective? Good quote: “The Fed now has two fires to put out and only one bucket of water.” All eyes/ears on next week’s Fed presser. While the regulatory response to the unfolding crisis has been swift, the Fed/Treasury are being besieged with cries of dereliction of duty and moral hazard. Given the unhealed scar tissue from 2008, Congressional resistance, on both sides of the political divide, to further federal assistance, is likely to grow. Dems are decrying the apparent supervisory failures and want more regulation on seemingly recalcitrant bankers, and Republicans are loathe to subsidize CA/NY banks/depositors at the expense of local community banks.
With respect to OPEC, earlier last week the Saudi Energy Minister disclosed that the OPEC+ consortium wants to keep production unchanged until YE given the uncertainty of the global economic outlook. We suspect they’re somewhat discomfited by the speed with which sentiment has shifted from the positive afterglow of CERA last week to the current risk-off contagion this week. In typical OPEC fashion, they are granting unattributed interviews and professing that the global oil market is well-behaved and will be in deficit 2H. OK. Sounds good. At this stage we don’t have a profound quibble with this view, although we may differ in terms of degree. Notwithstanding OPEC’s current serenity, we wouldn’t be surprised to hear verbal interventions in the event negative pricing momentum persists, and some have surmised that the pulling-forward of the Joint Ministerial meeting of April 3rd will be the first sign of mounting concern. As a reminder, recent peak OPEC production was 29.7 MBD in September and February production was 28.9 MBD – Saudi, Kuwait, and UAE (collectively, GCC consortium) comprised almost the entirety of voluntary production recalibrations from the September peak. Iraq production is also down from the Sept peak but whether this was voluntary is open to debate. Thus, does the GCC consortium want to cede additional market share? Not unless it’s absolutely necessary.
Finally, the US Govt isn’t exactly displaying a sense of urgency and resolve on its assertions to begin replenishing the SPR at a targeted range of $67-72/bbl. Amos Hochstein, the Special Coordinator for Global Infrastructure and Energy Security, in a recent Bloomberg TV interview was asked about replenishing the SPR and his response was as follows: “Why don’t we take this one day at a time…we should take a deep breath and wait and see how this crisis impacts the oil and gas industry…nothing happens overnight…you wait to see where the prices are going to be landing.” Aren’t we all.
With respect to rubber-meets-the-road industry realities, WTI is currently ~$67/bbl – in early-October it was $90+. HHUB is currently ~$2.40/MMBTU – in mid-Dec it was ~$7. Waha is currently ~$1.40/MMBTU – in December it was $7+. Is the oil market in the early stages of a fundamental unraveling? Don’t think so but we remain vigilant. YTD domestic inventory trends have been uninspired (Jan OECD inventories built at 4x the seasonal average), demand anemic, and the physical market sloppier than recent bullish sentiment implied. Winter weather has been temperate, the seasonal demand-pull a dud, Russian exports resilient. The question is what happens from here? The broader energy trade has seemingly become a game of waiting-on-China. While there is reason to believe that global demand will improve over the course of this year, with market balances transitioning from surplus in 1H to deficit in 2H (more below), we haven’t seen evidence of a cathartic tightening, yet. Many best-of-breed energy stocks are down ~10-30% YTD, with negative momentum accelerating last week. Intermediate and L-T positive fundamentals have given way to near-term threats. The longer commodity pricing duress persists, the greater the response and reset will be in terms of E&P cash flow expectations, reinvestment, and US production growth. Knowing this, we reached out to a number of contacts this week to gauge sentiment and assess what might unfold in the coming quarters.
The Micro – Field Thoughts and Recent Anecdotes (authored by John Daniel): Thank goodness last week was spring break so most DEP energy friends weren’t present to watch the signs of the Apocalypse as concerns over the banking system and growing recessionary fears sent WTI oil prices from mid-$70’s to mid-$60’s. Perhaps that’s a bit dramatic, but the concern in the air is palpable as lower commodity prices are/will lead to some rethinking their 2H’23 activity. At this point, no firm decisions have been made, but the house view at many shops is something needs to give. Either service costs need to come down or activity needs to be tweaked lower. Concurrently, more, but not all, OFS contacts acknowledge some pricing degradation and/or expectations for concessions later this year. The following are a series of observations gleaned from a multitude of industry updates.
- There is more evidence of OFS companies adjusting price. No need to throw gasoline on the fire, so we’ll be discrete, but mid-to-high single digit concessions have been made across multiple service lines according to multiple industry contacts. This is not just E&P contacts talking their books, but service companies acknowledging the emerging trend as well.
- In some cases, the reductions are the consequence of lower raw material costs which are now being passed through to end-users. In other cases, the concessions are a function of too much capacity and/or the onset of price knife-fights as companies vie for market share. Finally, it is apparent that some E&P companies seeking price concessions are attempting to tie more work to the company who concedes price. Others, however, intend to use threats of lower activity to achieve OFS price concessions (more on that in bullet #5).
- What’s interesting is the fact that pricing has moved lower even before activity declines have set in. Yes, anecdotes are remain limited at this point.
- One reason for #3 is we have transitioned from E&P companies calling service companies for availability to the point where service companies are now calling E&P companies to see if they need any equipment. That transition is the green light for attentive E&P companies to seek concessions. In fact, several contacts this week claim plans to put work out for bid in the coming weeks. Our take is the industry has reactivated/ordered too much equipment such that increasingly supply outstrips demand.
- Prices for goods tied to steel are now reporting to be falling (i.e., casing, tubulars, vessels, tanks). One contact claims it has achieved 10-15% reductions within the past few weeks. Others simply claim there is more availability.
- Price concessions are not widespread. Case in point, one sector which has not seen price compression, at least according to one contact, is cementing. Moreover, cement prices for this contact will increase in Q2, thus the company will try to pass through this inflationary pressure. In another instance, we visited with a coiled tubing company which negotiated Q1 price increases for many customers and those have now been implemented. Nevertheless, this same CT company is aware of price concessions in the marketplace and is not naïve to the implications for pricing/utilization in 2H’23. The point is not everything is doom-and-gloom, but we would not be doing our job if we didn’t address the leading-edge changes.
- To see where we may be headed, we conducted a small and survey of E&P contacts last week. Specifically, we received feedback from 25 companies, all but one is largely Permian-focused. These companies presently operate 116 drilling rigs or roughly 32% of the Permian rig count. We asked each company to opine on their respective rig counts at YE’23 should oil prices stay in the $65-$70 oil vicinity. The collective answers yield a total of 104 to 112 rigs running later this year. In other words, a decline of roughly 4% to 11% for our surveyed group. Not a big decline, but a decline nonetheless.
- Other Survey Observations: Public companies generally have little-to-no change to expected rig counts. Privates are mixed. Those with legacy assets are dropping or claim will drop rigs if OFS pricing doesn’t reset lower. The outliers are those who have recently acquired acreage and who seek to build up/develop a portfolio. Those companies, however, are the minority and include two players who are seeking to buy acreage; have no rigs running today; but hope to each have one rig by year-end.
- To cross-check our E&P observations, we visited with a land drilling contact this week. Won’t state the number of rigs that company is running as then folks could zero in on the player. When asked about market, our contact characterized it as “mushy” and had no push back with a potential ~5% decline in its respective rig count this year. Employing dumb guy math and extrapolating to the overall U.S. rig count, this driller’s view, along with our small, but targeted E&P survey, suggests a further ~50 rig contraction is not out of the ballpark.
- Last week we trimmed our rig count forecast. Those changes were made before the banking fears escalated. Our model contemplates a reduction of ~20-30 rigs from here. From the tone of our conversations this week and assuming commodity prices don’t move higher (i.e., +$70/WTI), our gut tells us we are a tad too optimistic. We will reach out to more E&P contacts this week to see what others have to say.
March Benchmark Agency Energy Snapshots (authored by Bill Herbert): The March benchmark agency energy reports yielded modest adjustments m/m. Both the IEA and OPEC continue to project sequentially improving demand (~2-3 MBD) over the course this year, with the market transitioning from surplus in Q1/1H to deficit 2H. The two prominent swing factors remain China demand and Russian oil/products exports.
With respect to China and Russia, IEA and OPEC expectations are converging, with expectations coalescing around ~700 KBD-1 MBD of y/y China demand growth (mostly unfolding in Q2-Q4). Russian total liquids production expectations call for a contraction of ~700-740 KBD y/y, perhaps too penal given the continued appetite for heavily discounted barrels in large parts of the world although there is some evidence of growing friction in clearing barrels. Non-OPEC/Russian production growth is expected to be vigorous at ~1.8-2 MBD y/y, with the US projected to drive the lion’s share of the expansion. We believe US production growth expectations look increasingly assertive given growing E&P cash flow duress.
The projected calls on OPEC production required to achieve inventory neutrality look like reasonable SWAGs (2023 ~29.5 MBD, Q1-Q4 ~28.5-30.5 MBD) but with an admittedly wide range of outcomes on multiple fronts. Yes, while the longer-term reinvestment thesis remains plausible and well-supported, YTD inventory trends remain bearish. The IEA correctly captured the moment in expressing that “the market is caught in the crosscurrents of supply outstripping still-lackluster demand with stocks (inventories) building to levels not seen in 18 months.” Notwithstanding, the global oil market is expected to meaningfully tighten over the course of this year and is largely contingent on assertive China PUD growth, non-trivial Russian production deficits, financial stability and the avoidance of a hard economic landing in the OECD. In other words, buckle-up because a lot of balls are in the air.
BKR U.S. Land Rig Count. +5 rigs w/w to 736 rigs. Gains largely in the Permian.
- Q4 revs = $448M vs. Q3 revs = $438M.
- Adjusted Q4 EBITDA = $76M vs. $91M in Q3.
- Running 10 fleets in the U.S. and 5 in Canada.
- Company will cease reporting Canada / U.S. separately and will start reporting NAM results.
- This means we’ll look at q/q changes going forward, so we start now.
- Nerdy analysts likely bothered by this, but since CFW’s NAM competition is reporting less disclosure these days, we don’t blame them for the change.
- CFW will also begin expensing fluid ends in 2023. Estimated cost in 2022 was about $20M.
- 2023 capex budgeted at $155M vs. $88M in 2022.
- Company is embarking on a Tier 4 DGB upgrade process.
- A total of 59 pumps will be converted to Tier 4 DGB under the current plan.
- We believe three of the company’s ten U.S. fleets are Tier 2 dual fuel.
- Total debt at YE’22 = $332M vs. $388M at YE’21.
In E&P News This Week: COP received the Record of Decision on its Willow Project in Alaska, adopting the BLM’s “Alternative E” plan for three well pads (vs. five originally proposed). The decision likely means the company will officially FID the project, which will ultimately produce 180 MBO/d (600MM Bbls of estimated recoverable oil). COP will invest between $7-$7.5B of capex in the project. There will likely be a detailed update at their Analyst Day on April 12. RRC’s CEO Jeff Ventura is retiring after 11 years in the role (effective in June) and will be replaced by COO Dennis Degner. Interesting given the headlines a couple of weeks ago suggesting the company was being acquired.
Refining Observations: Oil’s pain was refining’s gain, as the Gulf Coast 3:2:1 spread jumped 15%. Product inventories remain challenged, even with gasoline and distillate demand muted (see below). Refining utilization jumped by 2% this week to 88%, perhaps a sign that turnarounds are ending?
XOM announced that its 250 MB/d expansion at Beaumont started production this week. The project brings the refinery’s total capacity to more than 630 MB/d “supported by the company’s growing crude production in the Permian Basin.”
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
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