BKR U.S. Land Rig Count: Declined 10 rigs this week with rig count now below 700 rigs for the first time since May 2022. Stepping back and looking at the decline relative to the Q4 peak, the biggest percentage decline has occurred in the Mid-Con, down nearly 30% while the Eagle Ford and Haynesville are down ~17%. While we don’t want to be the bad guy, we should point out that an area where we have heard multiple anecdotes on price concessions is the Permian, yet the Permian rig count is down only one percent. Stepping back, price weakness in places like the Haynesville and Eagle Ford reflect the fall in activity and people trying to work. In the Permian, that, in our view, is a case of too many service providers. Remember, everyone flocked to the Permian in the last two years and as we’ve repeatedly said over the years, actions have consequences.
BB- Chord Energy to Buy Williston Basin Assets for $375MM from XTO Energy Inc. (Exxon Mobil). 62k net acres (77% undeveloped), 123 net 10,000 ft equivalent locations, current production of 6 Mboepd, acreage 100% held by production and expected to close by June 2023.
BB- CVX to Acquire PDC Energy for $6.3B, Total enterprise value, including debt, of the transaction is $7.6B. All stock deal for $72/sh to Friday’s close is an 11% premium. Assets are in DJ (275k net acres and Permian Basin 25k net acres).
WSJ-Biden’s Billion-Dollar Oil Trade Faces a Big Test Link
FT- Boomy’ talk about the Chinese economy is a charade Link
WSJ- Exxon Joins Hunt for Lithium in Bet on EV Boom Link
WSJ- Europe’s Energy Crisis Subsides as Natural-Gas Prices Fall Link
DEP Update: We accomplished a personal best last week, having driven 1,049 miles in one day. As a result, we are proud to announce that we have the best-looking right calf muscle in the entire U.S. upstream energy complex. This week, mostly short distance driving with the DEP team dividing and conquering in both Houston and Midland. The following week we will attend and moderate a panel at the Louisiana Energy Conference to assist our friend Al Petrie. Lastly, with drilling activity fading and several anecdotes of Q2 white space surfacing, we feel now is an appropriate time to host either a whiskey tasting or a brewery tour. Date will be June 8th somewhere in Houston. Invites to go out shortly.
Energy Ruminations = Benchmark Agency (IEA, OPEC, EIA) May Reports (authored by Bill Herbert): While the May IEA OMR and OPEC MOMR didn’t yield meaningful m/m changes to their respective outlooks (punchline = the global oil market is expected to transition from surplus in 1H to deficit in 2H – although we agree, the range of outcomes remains wide), the latest salvo on the part of the IEA didn’t inspire confidence given the lack of synchronization between top-down messaging and bottoms-up analytics. Specifically, while the IEA’s messaging, in this month’s OMR, extolled China’s demand recovery continuing to “surpass expectations,” it failed to adequately acknowledge and illuminate non-trivial negative revisions to baseline historical data, resulting in an increase in projected 2023 y/y growth but a decrease in the projected absolute level of China oil demand.
The two prominent oil wildcards coming into this year were China PUD (pent-up-demand) recovery and Russian production and export resilience (coming into 2023, the IEA expected a 1.3 MBD y/y contraction in Russian liquids production – now it expects a decline of 350 KBD). We are of the belief that the China PUD recovery is underway, but the slope is unclear as macroeconomic data has been weaker than expected and oil data opacity unyielding. Negative revisions to 2021 and 2022 demand (300 KBD each) reinforce the unreliability of China oil data. The complexity factor for energy has never been higher and the range of outcomes for China demand and Russian production remain wider than many appreciate. Near-term broader crosscurrents continue to be pronounced. The opacity and unreliability of energy data doesn’t help in trying to “figure it out.”
The world of oil analytics and projections isn’t particularly inspiring on the best of days. Supply and demand projections are burdened by the prominence and unpredictability of government policies, persistent macroeconomic crosscurrents, daunting geopolitical complexity, and poor data quality, particularly from the non-OECD – not only is divining future outcomes a Sisyphean endeavor, accurately capturing historical data is a challenge.
While the market’s judgment of current oil supply and demand will vary depending on the day or the hour, the intermediate term reinvestment thesis for oil is well-supported by obdurate deliverability challenges, secular non-OECD ex-China oil demand growth (high-birth rates, above-avg nominal GDP growth, ongoing industrialization, urbanization, etc.), depleted OECD inventories and reawakened energy security. Total March OECD crude/products/govt stocks declined to the lowest level since 2004 and are ~400 mbls below the 5-yr avg (US crude/SPR stocks ~25% below their 5-yr avg). Some have argued that there is a disconnect between financial and physical markets – while this may seem like a preventive incantation, OECD/US inventories do not currently reveal an oversupplied market (again – total OECD stocks at their lowest level since 2004). Yes, the global economic outlook is fraught with uncertainty and market sentiment has switched from sanctifying the positive and rationalizing the negative, to sanctifying the negative and rationalizing the positive. Can things worsen? Certainly – the current macroeconomic environment is exceedingly fluid. Notwithstanding current oil price volatility and what it ultimately may or may not portend, the domestic E&P industry needs sufficiently accommodating oil prices to generate cash flow, induce reinvestment and drive production growth. While many expect the US to be the primary driver of multi-year global oil production growth required to fuel demand growth, arguably current E&P cash flow generation does not support such an outcome.
The following is a summary of the benchmark agency (IEA, OPEC, EIA) reports for the month of May, which were published last week.
- OPEC April vs. Recent Peak Production: OPEC April Oil production, according to OPEC secondary sources, averaged ~28.6 MBD (down 191 KBD m/m) vs. recent (September) peak production of 29.8 MBD. April production by prominent OPEC members was as follows: Saudi = 10.5 MBD (+95 KBD m/m, recent peak ~11 MBD), Iraq = 4.1 (down 203 KBD m/m, recent peak ~4.5), Iran = 2.6 (+48 KBD m/m, recent peak 2.6), UAE = 3.0 (flattish m/m, recent peak 3.2), Kuwait = 2.7 (flattish m/m, recent peak 2.8). It will be interesting to see how OPEC’s flamboyant targeted oil production cut of 1 MBD unfolds. As we expressed last month, we believe that Saudi/GCC will do “whatever it takes” to stabilize the oil market, should an intervention be needed. Saudi, in early-April, declared its intent to reduce production by 500 KBD as a “precautionary measure aimed at supporting the stability of the oil market.” UAE and Kuwait concurrently announced production cuts of 144 KBD and 128 KBD, respectively. Collectively, the targeted GCC production recalibration is ~770 KBD. We observed at the time that Saudi’s objective was firming downside support for oil prices and squeezing shorts. Mission accomplished, for a nanosecond. Crude vaulted from the mid-to-high $60s/bbl in mid-March to ~$83/bbl in mid-April, and has subsequently retraced to the low-$70s/bbl. Back to you Saudi.
- Call on OPEC Required to Achieve Inventory Neutrality: Unchanged m/m. The IEA’s call on OPEC production for 2023 is 29.6 MBD, progressing from ~28.9 MBD 1H to ~30.5 MBD 2H. Meanwhile, OPEC’s projected call for 2023 is 29.3 MBD, expanding from 28.4 MBD 1H to ~30.1 MBD 2H.
- Global Demand: Demand expectations were largely unchanged m/m. Global demand is expected to grow by ~2.2 MBD y/y to average ~102 MBD, with non-OECD comprising ~90% of the y/y growth and Jet ~50% (IEA). The IEA’s global demand trajectory for this year has consumption expanding from ~100.5 MBD (OPEC 101.6 MBD) in Q1 to ~103.1 (OPEC 103.3 MBD) in Q4.
- China Demand Growth: China remains the fulcrum of global oil demand growth and is expected to vault by ~810 KBD-1.3 MBD y/y (OPEC lower-end, IEA higher) – CNPC, however, recently projected China 2023 oil demand growth of 750 KBD y/y (or ~5.1% vs. OPEC’s estimate of ~5.5% growth and the IEA’s 8.8%), thus benchmark agency projections look optimistic. China’s economic recovery has been less cathartic than hoped, with trade and manufacturing data (latest PMI back into contractionary territory) being weaker than expected, ditto recently released industrial production and retail sales, and youth unemployment continues to hover at 20%. Real estate remains an albatross. All of this points to the need for more aggressive policy support. Largest of breed commodity houses and most of the sell-side have been max bullish on China but this is changing as evidenced by the following quote from JPM: “April data points at a big loss in recovery momentum.” Regarding energy benchmark agencies, the IEA has been an outlier, even among broadly optimistic perspectives, with its unvarnished, unrestrained, damn-the-torpedoes China fervor. Notwithstanding its professions of China demand continuing to “surpass expectations,” and the PUD recovery being “stronger than previously expected,” the IEA lowered 2021 and 2022 baseline historical demand by ~300 KBD for each year. Accordingly, while its 2023 China demand growth estimate was flat-to-up m/m, its absolute level of projected demand was flat-to-down at 15.96 MBD (OPEC ~15.66).
- Non-OPEC Production Growth: Non-OPEC ex-Russia total liquids production growth is forecast to rise by ~2 MBD, with the US and, to a lesser extent, Brazil serving as the most prominent sources of expansion.
- US Oil Production Growth: We focus on the EIA’s US production estimate which we view as more reliable than those of OPEC/IEA. The EIA’s estimate, in the latest STEO, was ~tweaked lower m/m to 12.53 MBD (+640 KBD y/y vs. prior +660 KBD – on the surface, seems extravagant but keep in mind that 1H’23 y/y growth is being fueled by very easy comps). While the domestic oil rig count (per BKR as of May 19th) has contracted by 46 rigs or ~7.4%, the Permian oil rig count continues to display resilience, as it’s down only 7 rigs or ~2% from recent peak levels. That said, the longer E&P CF duress persists, the greater likelihood of a non-trivial Permian rig count correction. However, with OFS costs moving lower, our ongoing activity survey (see below) suggests stability vs. collapse is the current E&P outlook. For 2024, the EIA is projecting oil production of 160 KBD y/y and flat-to-up vs. projected YE’23.
- Russian Oil Production: The IEA is now projecting a y/y contraction in Russian total liquids production of only 350 KBD (vs last month 530 KBD) to ~10.7 MBD, whereas earlier this year it was prophesying an implosion of 1.3 MBD. According to the IEA, Russian exports “edged up in April to a post-invasion high of 8.3 MBD,” with oil shipments increasing by 250 KBD, more than offsetting a products decline of 200 KBD. Black oil production of 9.6 MBD was flattish m/m. OPEC is projecting a Russian production contraction of ~750 KBD y/y to ~10.3 MBD.
- Inventories: Global observed inventories declined m/m in March by ~8 mbls, while OECD inventories declined by 56 mbls to a six-month low of 2,753 mbls, with the deficit to 5-yr avg levels, widening to ~89 mbls. Total OECD crude/product/govt stocks fell to their lowest level since 2004 and are ~400 mbls below their 5-yr avg level. As a rule, the reliability of OECD inventory data is far greater than that of non-OECD. April OECD data shows a preliminary build of ~24 mbls in US, Eur, Japan. Based on the latest weekly DOE inventory data-dump, total US crude/SPR inventories are almost 25% below the 5-yr avg – in other words, this isn’t a market which isn’t currently swimming in surplus oil and products. Over the most recent two weeks, however, US inventories have built – one-off or the beginning of a trend? Stay tuned.
DEP Rig Count Forecast. We are gathering E&P feedback for our rig count forecast update. Our initial outreach yielded feedback from 24 E&P companies thus far. The companies are collectively running 142 rigs or roughly 20% of the U.S. rig count (per BKR). We expect more responses in the coming days, so look for our formal rig count forecast revision next Sunday. We prefer to get more ground level color as we build out the forecast. That said, responses from our sample, which is admittedly small, point to a reduction of another eight rigs in 2H’23 from these companies, but then an expected 9 rig recovery in 2024 (+7%). If you’re into things like extrapolation, the survey suggests the overall rig count could slip another 35-40 rigs. That feels a tad too much for us, however. A couple prominent themes from our discussions: (1) notable service cost reductions with certain E&P’s; (2) several private companies stating plans to go to maintenance mode in 2024, thus their recent rig count reductions likely don’t reverse; and (3) efficiency gains with frac fleets which is leading to white space on their calendars. Some openly question filling the gaps with additional work which would increase capex or stay within budget and keep the gaps, but potentially lose some efficiencies. Our contacts are opting for the latter, a sign of continued discipline. One final note – the survey is based on a $70-$75 WTI scenario with an expectation for nat gas prices in the $3.50 range next year. Also, we should highlight that many of our contacts have not yet finished a 2024 budget, so the longer-term view is more gut vs. set in stone.
E&P Observations (Authored by Geoff Jay): We spent most of the week meeting with companies in Houston (and seeing the best 9th inning of baseball I’ve ever witnessed on Wednesday night). Thanks to everyone who took the time. The first question from virtually everyone was whether we’d heard of any significant move in leading-edge pricing for rigs and frac spreads. This is an interesting question. On the one hand, the DEP team has written about leading edge price concessions for most of the year and Q1 E&P earnings calls certainly featured growing evidence of price concessions, notably on OCTG. On the other hand, we recognize the market is nuanced with some companies having contractual and/or dedicated relationships with service providers, thus in those instances, there is likely to be less price relief. Here are a couple real-time anecdotes. This week the OFS arm of DEP had an E&P report a 20% drop in its dayrate (i.e., high $30’s to low $30’s). Yet in another discussion this week, another E&P noted its services wouldn’t reprice until this summer, thus no relief on dayrates or completion spreads as of yet. Meanwhile, multiple private frac companies, who largely play in the Tier 2 spot market, acknowledge spot market price concessions in the 15%+ range. So why the question then on price when multiple anecdotes exist? Perhaps, an information lag between field contacts who see the data points real-time vs. when the C-suite is made aware of the trends. We can’t prove this necessarily, but years of experience dealing with field vs. c-suite often suggests some information disconnect, which we chalk up to timing.
The bigger takeaway, however, is every single E&P person with whom we visited is expecting price relief. This makes sense when the rig count just fell for the third week in a row. The Baker Hughes land-rig count is now down 9% from the Q4 peak. That, coupled with incremental supply of OFS equipment within many segments, is enough to drive prices lower. Now, some E&P contacts questioned whether OFS companies would simply idle equipment rather than lower price. Perhaps in isolated instances, but a broad-based industry-wide effort to hold price and let equipment go idle is, in our view, a pipe dream. Two reasons. Utilization is key while labor challenges remain. Given most OFS contacts are generally optimistic for a 2024 recovery, the idea of slashing and burning now doesn’t make a ton of sense. Further, when we used to model these things intensely, utilization was very important to service providers’ ROIC, and the only lever we’re aware of to manage that factor is price.
That said, the operators we spoke with all expressed a desire to maintain their best rigs and crews, worrying about a loss of hard-won efficiencies in their programs. In theory, this could keep activity from falling far enough to affect service pricing significantly, but leading-edge data points suggest otherwise. Again, the overall rig count is down about 9% yet we are tracking multiple cases of double-digit price concessions. Another theme from this week’s meetings is the fact that E&Ps recognize service providers need to make money. Unfortunately, most also believe a glaring mismatch exists between rates today (largely reached when oil was in the mid $80’s) and a forward strip of ~$68 in 2024. One management team with whom we met opined price reductions of 10-15% felt about right. Another team wondered why rates couldn’t just revert back to Q4 levels, which they believed would offer service providers adequate margin but also give producers some cost relief. This is, however, debatable from the service company perspective, but we understand the view of the ultimate end-user of the service. Multiple c-suite teams conveyed a desire for partnerships with service providers. Going back to the theme of keeping the best rigs and crews, the partnership concept can work, but it requires give-and-take on both sides. If one wants price relief given the decline in commodity prices, would they then be willing to allow for an automatic price increase when commodity prices rally? We have not heard anyone advocate that premise, at least not yet.
Finally, the lack of love from the stock market was another frequent subject of discussion. The question of when generalist investors will care about the group came up over and over. We’re now solidly in year three of the capital-discipline/cash-return experiment, and relative underperformance for the group (~20% for both YTD and trailing 12 months) is getting old. Despite this frustration, some were encouraged to see successful offerings of both debt and equity this week: OVV issued $2.3B of senior notes to partly fund its recent Permian acquisition. NOG revealed it bought 30% of Forge Energy II (VTLE to operate and own 70%) in a deal announced a week ago. As a result, NOG did a secondary offering of 6.65 million shares to fund the purchase, raising nearly $200mm. Some wondered if the current environment might lead to some larger M&A activity. Time will tell.
Other News: PUMP announced a $100M share repurchase program. PUMP joins numerous other OFS enterprises that seemingly wish to capitalize on the perceived disconnect between the industry’s view of activity and stability vs. the market’s view which is run away from energy in the face of recessionary fears and negative trends (i.e., lower commodity prices, declining rig count, growing white space, developing pricing pressures, etc.).
Refining Observations: If last week’s release was one step forward, this week’s is two steps back. Apparent demand looked significantly weaker, with jet fuel giving up all last week’s gains. Gasoline demand is still running ahead of last year, while distillate and jet are now running behind. This data is notoriously noisy week to week, and demand could still surprise to the upside as we move into summer. On the inventory front, commercial crude built by 5mm Bbls this week, but that was partially due to a 2.4mm Bbl SPR release. Jet inventories have built considerably over the past few weeks, whereas gasoline and distillate levels remain supernormally low, despite refineries increasing runs ahead of driving season. A pretty healthy setup for margins, in our opinion.
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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