Macro/Headlines/Events

 

BKR- U.S.  Land Rig Count was down 1 rig week/week to 753 rigs.

 

For those that attended our Event in Scotland in late August, you will appreciate the Offshore Article below in the WSJ over the weekend.

 

WSJ- The Offshore Oil Business Is Gushing Again  Link to Article

WSJ- China’s Reopening Complicates Global Fight Against Inflation-  Link to Article

 

DEP Update:  We will be in Fort Worth on Monday/Tuesday and then off to an analyst day in Italy later this week.  For those in Fort Worth who are free, let us know.  Ditto those in Florence.  Next week we will publish an update on the CT market, so to all our CT readers with whom we haven’t yet chatted, let us know if you are willing to catch up this week.

 

Housekeeping: Thrive Registration Update: We are in the process of sending out the Thrive registration link.  Here’s how it works.  If your company is a sponsor, then the registration link went to your company’s point of contact (likely the person on your sponsorship agreement).  That person is then responsible for registering your attendees.  If you are a subscriber, but not a sponsor, you should have received a link already.  Speakers and moderators also should have received a link.  If someone is neither a subscriber, a sponsor nor a guest of a sponsor, but attempts to register using our subscriber passcode, we most likely will reject that registration.  Some people are already trying to sneak in.  If all of this has confused you, reach out to Bill Austin at bill@danielep.com.  He can help you.

 

Earnings This Week

Mon- BKR

Tues- HAL

Wed- RES, HES

Thurs- MUR, VLO, LBRT, CNX

Fri- CVX

 

Research

 

 

East Texas Recap:  Last week we wrote about potential rig count reductions forthcoming in the Haynesville.  Rather than simply accept a few anecdotal stories as the official emerging trend, we elected to drive to the Haynesville to verify the veracity of these prophesies, thus a quick Blitzkrieg tour through Kilgore, Longview and Marshall on Thursday/Friday with ample truck time to make additional calls.  Feedback, go figure, varies, but first know that the Haynesville rig count per BKR stands at 69 rigs.  This compares to a recent peak count of 72 rigs in December and a Q4’22 average of 70 rigs.  As for speculation, we had E&P contacts speculate a rig count moderation of 5-10 rigs, potentially a ~10% reduction from here.  Not a collapse, but what some see as a short-term softening driven largely by pipeline constraints.  Local contacts called out three private E&P companies presently facing issues with some having dropped a rig already and/or delaying completions.  Timing of more takeaway capacity is not yet clear to us, because we just did the tour, so we refer readers to chase down research commentary by others.  What did give us medium-to-longer term hope is the reality that more gas is going to be needed for the onslaught of LNG export capacity in the coming years.  According to one local contact, it takes roughly 4 drilling rigs on high quality rock in the Haynesville to produce 1 Bcf/day.  According to BloombergNEF, the global LNG market is projected to expand from 387 MTA (~51.6 Bcf/d) in 2021 to 460 MTA (~61.4 Bcf/d) or by ~10 Bcf/day in 2026. The US alone is projected to supply ~25% of global LNG in 2026. There is a “second wave” of LNG FIDs that could expand domestic export capacity total by ~95 MTA (~13 Bcf/d, basically a doubling in capacity) by 2028.   Someone can correct us if we are wrong, but that seemingly suggests more gas-directed drilling will be required.  Moreover, we had one E&P contact share with us that industrial users are already reaching out to secure gas supplies for fear of losing gas to LNG.  That seems bullish to us.

 

What is worth noting is that the vast majority of our service contacts “haven’t seen anything” yet vis-à-vis an activity slowdown.  Only one rental tool company reported completion delays due to takeaway issues.  There were a couple folks who claim one frac crew has been released due to the gas situation, but no name was provided.  Hard to know if the crew simply didn’t complete a project, thus it’s not working.  One well service company reports no change in activity, but purportedly one of its peers suffered a soft December/January.  A small private E&P claims it has released its well service rigs due to low gas prices and higher service costs.  In other words, our takeaway is the market is “nuanced” as a wholesale slowdown is not underway (at least not yet), which is consistent with our observations from our recent Permian trip.  Rather, some are slowing while most others are steady. Management teams remain thoughtful and vigilant, balancing near-term crosscurrents with longer-term opportunity.  Therefore, be careful not to Xerox concerns across the entire sector.  Notwithstanding, multiple E&P companies did claim that another ~50c reduction in nat gas prices would likely yield a reduction in their activity.

 

Three additional observations from this trip.  First, the oilfield is full of entrepreneurs – from our vantage point this continues to be the unappreciated genius of the American energy industry.  Example: we visited with a new CT player, Diamondback Energy Services.  The company is run by those who have ample experience in the business, but who have decided to branch off on their own.  Diamondback is focused on the small-diameter CT market and sees a runway for future growth across multiple basins.  Similarly, we visited with another CT player who emerged about a year ago and continues to add new capacity to its fleet.  Meanwhile, we visited with another contact who opportunistically purchased pumps for an emerging pump down business.  Second, driving around the East Texas region, we passed by many yards where fleets/units were all sorts of different colors.  Reminds us of our bowl of Fruity Pebbles each morning.  What this is, however, is the amalgamation of units, either from acquisitions and/or auctions, but it is older equipment which is finding a home at other service companies.  We recall a time when older equipment from the U.S. found its way into international markets.  Now it stays in the U.S. as several players tell us it simply doesn’t make financial sense to buy new equipment.  Third, we all know the Haynesville can be abusive on equipment.  Driving by the Holt CAT facility in Kilgore and seeing all the units presumably waiting on service is a great way to visualize the challenges.

 

Mammoth Energy Services: Announced this week the reactivation of its fifth frac fleet.  Expected.  As noted in our weekly epistle last Sunday, we believe several of the smaller frac players (i.e., fleet size less than five fleets) have ambitions to reactivate more equipment and/or supplement with new equipment purchases.  We are aware of three enterprises who each intend to deploy an incremental fleet in 2023.

 

E&P Observations (Authored by Geoff Jay):  We had a chance to catch up with a few E&Ps this week, focusing on activity, pricing, and industry-growth potential.  None of the people we spoke with saw any rig- or service-pricing weakness, but some did see evidence that activity was stalling a bit.  One of our contacts pointed out that “productivity per foot is dropping across the US, cost per foot is up more than 40% since 2021, and commodity prices are WAY off their highs.  Something has to give.”  Another said that he is seeing more “flexibility,” especially with rigs right now, but largely thinks that whatever the privates drop will be picked up by the larger publics (he is looking to add this year).  No one we spoke with thinks that we’ll see massive activity growth this year, even if prices surge.  “It just isn’t capital efficient.”

 

Still, estimates for 2023 spending may be too low.  One executive observed that Wall Street expects 2023 capex growth of less than 20% for number of companies, coupled with volume growth of 5% or more.  “No way.”

 

As a result, no one is looking for big volume growth from the US this year either.  Several people also echoed Pioneer CEO Scott Sheffield’s concerns about rising GoRs in the Permian.  “We can see GoRs increasing, and if he’s right that we need a pipeline every 18 months, that’s an issue.  And if the Permian is going to 30 Bcf/d like he says, you better start building more LNG export facilities now.”

 

Chesapeake sold its Brazos Valley assets in the Eagle Ford (which it purchased from WildHorse in 2018) to WildFire Energy (led by former WildHorse executives).  The package sold for $1.425B and consists of 377K net acres (out of CHK’s total EF acreage of ~611K net), 1,350 wells, production of 27.7 MBOE/d (85% liquids) and proved reserves of ~97 MMBOE.

 

Permian Resources acquired 4,000 net leasehold acres, 3,300 net royalty acres and production of 1,100 BOE/d (73% oil) in Lea County for $98mm.  PR also divested 1,800 BOE/d (44% oil) on 3,500 acres for $60mm, 300 net non-op acres in Eddy County for $10mm, and a portion of its saltwater-disposal wells and produced-water infrastructure in Reeves County for $125mm.  The deals have no impact on the company’s 2023 preliminary outlook.

 

Refining Observations:  Gasoline prices have been moving significantly higher (up 8% YTD) despite soft demand.  Production has been below average as well, partly due to Winter Storm Elliott, but also possibly impacted by lower volumes of Russian VGO (vacuum gasoil) which are used in FCC units (fluid catalytic crackers) that primarily make gasoline.  We have asked our contacts if this phenomenon portends higher gasoline prices this year.  No one would commit to that, with one suggesting that the problem might be alleviated by Spring.

 

 

Benchmark Agency Summaries (authored by Bill Herbert):  The following are our observations from recent agency reports.

 

The January oil market reports of the benchmark agencies yielded very little change m/m in terms of projected market balances. Latest IEA demand and inventory data has been bearish and leading-edge US EIA weekly data continues to be sloppy.  Notwithstanding, both the IEA and OPEC continue to call for a relatively balanced market in 2023, evolving from surplus to deficit as the year unfolds. China and Russia continue to be prominent wildcards in 2023. An assertive China PUD (pent-up-demand) surge will very likely lead to tightening market balances, even with resilient Russian production. An anemic and fitful emergence from Covid purgatory, however, especially in combination with resilient Russian exports, will lead to a sloppy oil market.

 

Global demand, over the course of last year, markedly decelerated, devolving from torrid growth to stagnation (IEA = Q1 ~+5 MBD, Q4 ~-400 KBD). Demand growth projections for 2023, with the opposite trajectory from last year, range between 1.9-2.2 MBD and are back-end weighted. OECD demand projections look optimistic while China demand estimates look restrained-to-reasonable. US oil production projections for 2023 oscillate between ambitious and optimistic, while the EIA’s 2024 estimate looks realistic. Russian production estimates, particularly those of the IEA, look penal. The projected calls on OPEC production required to achieve inventory neutrality (29.2-29.9 MBD) look like reasonable SWAGs but with an admittedly wide range outcomes given the prominence of China and Russia in these assumptions. Current OPEC production is hovering at ~29 MBD and recent peak OPEC production was ~29.7 MBD (September). This is hardly a comforting ceiling as we ponder the growing likelihood of a China PUD (pent-up-demand) surge. Effective OPEC spare capacity (~2.6 MBD) is caressing the low-end of the historical range at ~2.5% of global demand.

 

Given the relatively guarded outlook among US producers, the opacity of Russian barrels, diminished spare capacity within OPEC, and projected acceleration of global demand growth as the year unfolds, the world is hardly in a comforting place when it comes to production flexibility in the event of a cathartic China PUD surge or a supply disruption. Buckle-up.

 

IEA OMR

  • Summary = The January OMR was largely unchanged m/m, with IEA projecting global demand growth of 1.9 MBD y/y (with China expected to drive ~1/2 of the increase) and non-OPEC ex-Russia production growth of ~1.9 MBD. The projected call on OPEC production required to achieve inventory neutrality is unchanged at 29.9 MBD. Global observed inventories surged ~79 mb m/m in November hitting their highest level since October 2021.

 

  • Demand = Global oil demand is projected to expand by ~1.9 MBD, with ~3/4 of the increase expected to come from non-OECD. As a reminder global demand decelerated meaningfully last year, devolving from ~5 MBD of y/y growth in Q1 to 420 KBD of contraction in Q4. The IEA is projecting relatively flattish y/y growth in Q1, followed by cathartic growth Q2-Q4.  Jet (and Kerosine) is expected to account for close to half of the increase in demand this year. OECD projections (+470 KBD) look optimistic (Q4’22 demand contracted by 910 KBD). Non-OECD demand growth is expected to be in the vicinity of 1.4 MBD y/y, with China generating ~850 KBD (jet, diesel, naptha, ethane ~95% of growth). The China demand growth trajectory for 2023 looks like a reasonable SWAG and is as follows: Q1 = -400 KBD, Q2-Q4 = +1.2-1.3 MBD. The global 2023 demand growth trajectory is as follows: Q1 = +160 KBD, Q2-Q4 = +2.1-3.0 MBD.

 

  • Supply = Non-OPEC ex-Russia production growth is forecast to rise by 1.9 MBD, with the US, Brazil and Norway comprising ~75% of the increase. While the IEA is projecting 960 KBD of US total liquids production growth, it acknowledges that the operating environment for E&Ps is increasingly challenging with only companies operating at requisite scale and possessing strong purchasing power able to deliver production gains of any consequence. We concur with the increasing demands on the L-48 upstream energy industry.

 

  • OPEC/Russia = The IEA’s estimate of OPEC production aligns with that of OPEC secondary sources at ~29 MBD (flat m/m). The projected call on OPEC production required to achieve inventory neutrality is unchanged 29.9 MBD and is expected to increase sequentially over the course of the year from 28.2 MBD to 31.4 MBD.   Russian black oil production of ~9.8 MBD was flat m/m and total liquids output of ~11.2 MBD was only 190 KBD below pre-invasion levels. The IEA is projecting 1.6 MBD of shut-in Russian production by the end of Q1 due to embargo/price-cap friction and average y/y decline of 1.3 MBD – debatable.

 

  • Inventories = Global observed inventories surged by ~79 mb m/m in November, reaching their highest level since October 2021. The increase was propelled by non-OECD (~44 mb) and oil on water (38 mb). OECD stocks were flattish m/m. By the end of November, non-OECD inventories had increased by ~75 mb y/y vs. a ~233 mb decline in OECD with a 270 mb release of government reserves. Oil on water increased ~180 mb y/y “as Russian exports were diverted to buyers further afield.” November OECD inventories were ~37 mb higher y/y but ~126 mb below the 5-yr avg.

 

OPEC MOMR

  • Summary = The January MOMR yielded very little change from the December report. Global demand is projected to expand by 2.2 MBD y/y and non-OPEC ex-Russia production by ~2.4 MBD. The projected call on OPEC production required to achieve inventory neutrality is 29.2 MBD. OPEC production, according to secondary sources, was flat-to-up at ~29MBD (+90 KBD m/m).

 

  • Demand = OPEC is projecting global demand growth of 2.2 MBD (unched m/m), with OECD generating 330 KBD of expansion and ROW ~1.9 MBD. Global demand is expected to oscillate between ~100.7-101.9 MBD Q1-Q3 and vault to ~103 MBD in Q4.  We quibble with the OECD (too hot) and China (too restrained) projections.

 

  • Supply = Non-OPEC ex-Russia liquids production growth is expected to grow by ~2.4 MBD, with the US, Canada, Norway, Brazil expected to generate ~3/4 of the expansion. With respect to the US, the projections (total liquids +1.2 MBD) look optimistic although the Q1 comp is an easy one given the anemic output in the first Q last year. OPEC is projecting 780 KBD of shale black oil production growth this year and flat-to-up GOM. Based on our latest discussions from our extensive slate of meetings last week in Midland, no one is adding rigs and a few-to-several are trimming. It’s not just the backsliding in oil prices over Q4 (although oil is up ~10% over the past month and now has an 8-handle) impacting E&P CF expectations but the implosion in nat gas prices (as well as non-trivial y/y well-cost inflation). Moreover, a continued relatively tight supply chain isn’t yielding frictionless activity increases nor seamless and resilient drilling and completion efficiencies on incremental rig/frac crew additions.

 

  • OPEC/Russia = Basically no change in the expected call on OPEC production required inventory neutrality for 2023 at ~29.2 MBD with an exit-rate call of 30.2 MBD in Q4. December OPEC production increased ~90 KBD m/m to ~29 KBD, with Nigeria delivering the preponderance of the gain.  The Russian production outlook is riddled with uncertainty – OPEC is projecting a contraction of 850 KBD. Time will tell.

 

EIA STEO

  • Oil Production = The EIA projects US black oil production growth of ~550 KBD for this year and ~400 KBD for 2024, with the lion’s share of the expansion driven by L-48. Based on our channel-checks with Permian producers on the realities of expected CF generation and capital allocation, the 2023 projection looks ambitious and 2024 more realistic.

 

  • LNG Exports = According to the EIA, the US became the largest LNG exporter in 1H’22 (~11.2 BCFD). While 2H’22 exports were occluded by the unplanned outage of the Freeport facility, the EIA projects average LNG exports of ~12.1 BCFD (too low?) in 2023 and 12.6 in 2024 (Q4 ~13.2)

 

Author

Daniel Energy Partners is pleased to announce the publication of its first market research note. In this note, we reached out to executives across the oil service and E&P sectors to gauge leading edge sentiment.

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