BKR U.S. Land Rig Count:  +3 rigs w/w to 756.  Although we had a slight uptick in the rig count last week, December 2022 and January 2023 were both lower m/m.


Source: Bloomberg/Baker Hughes/DEP


FT- What China’s reopening means for markets Link

WSJ- Biden’s Green-Energy Mineral Lockup Link

WSJ- The Outlook for Diesel: Supply Woes Aren’t Going Away Soon Link

WSJ- Small Oil Producer Stands to Win Big From Biden’s Climate Bill Link


DEP Update: In Italy this week for the Baker Hughes Annual Meeting.  Rough job, but someone has to do it.  Back in Texas later this week with plans to stay local near-term for the balance of Q4 earnings, a few local meetings and of course, Thrive Energy Conference planning.  BTW – friendly reminder for folks to register for the event.  We have about 590 registrations already (well ahead of last year), so to those who promptly registered, thank you.  And, if you have any interest in serving as an event sponsor, let us know this week.  We intend to shut down the sponsorship-request process very soon so that we have time to get everything finalized.



Activity/Pricing Debate:  Commentary from Q4 OFS earnings calls thus far is largely positive.  Essentially all is fine, pricing moving higher, and activity/job boards are full.  That sounds good and we aren’t here to vigorously debate anyone.  In fact, such commentary is the general feedback we hear from most folks, but not all.  And on the latter point, it is the leading-edge observations which we believe are noteworthy as sometimes, but not always, leading-edge observations become the new trend.  Time will tell as it always does.  That said, we visited with more companies this week and a few chinks in the armor, if you will, surfaced again.  First, one production-services-related enterprise noted activity thus far this year is trending a bit lower than in Q4.  Second, a CT player noted November/December were record months, but January dipped.  It’s outlook for Feb/March is constructive, but January was soft.  Third, a completions-oriented contact received its first request from a customer to adjust prices lower.  Moreover, this contact enjoys dedicated agreements for much of its equipment, so one would think there is nothing to fret over, but not so fast.  Yes, the company should have steady pricing, but there is no guarantee the customer will use its service.  And do you really want to enforce a contract with your customer given the short duration of these agreements and the fact activity should go higher next year?  Probably not.


Recall from our Haynesville trip that we called out various field contacts who foresee a rig count reduction in the basin of 5-10 rigs.  Also recall that we visited with several E&P’s who claimed plans to hold steady but acknowledged a potential adjustment to plans if gas fell another ~50c.  Well, when we spoke with those folks, gas was mid-$3’s, yet today it’s closer to $3/mcf.  That’s a 50c drop, thus worthy of a follow up call to our E&P friends if we stay at these levels for more than a few days.  Lastly, in discussing the natural-gas situation with the leader of a prominent gassy E&P, we were reminded that commodity prices are down significantly while service costs are, in his eyes, extremely elevated, thus something has to give.  This is a shared sentiment with other E&P’s.  Why important?  Long-time readers may recall during 2020/2021 that we often bloviated on service companies’ perception of low prices and the necessity for a material increase.  This sentiment, we argued, would drive service pricing higher when activity rebounded.  Of course, we received a lot of pushback on this notion from our E&P friends because they “weren’t seeing it yet”.   Now this same commentary, albeit reversed, is emanating from the E&P companies.  None claim any success in receiving price breaks yet and certainly no service companies are seeing it yet, but the sentiment is the same and we wonder how it will play out.  To this point, our service companies generally claim they will lay down equipment before cutting price (“it takes too long to get prices back, no sense in cutting it now”).  Easy to say, but hard to do when you potentially risk cutting headcount by laying down equipment.  On the other hand, one can’t dismiss two prominent themes: (1) the rise in LNG-export capacity in ~2 years which should be a key driver of incremental gas demand (read the BKR earnings transcript) and (2) the combination of well-productivity headaches, capital discipline and rising oil demand.  When one sees the forest through the trees, it’s hard not to be upbeat over the medium-to-longer term but possible near-term speed bumps seem possible as well.  Just calling a spade a spade and hoping the commodity prices surge so everyone can go back to a state of nirvana.



E&P Observations (Geoff Jay): Several themes are emerging from earnings, not least of which is the maturation of the Permian Basin.  Chevron (echoing themes from Pioneer) is lowering its growth rate in the Basin, citing DUC exhaustion and development optimization, based on learnings related to interactions between wells and benches.  The company is planning more single-bench developments, as well as targeting deeper zones, both of which will slow the pace of drilling a bit, and lead to volume growth of ~10% in 2023 vs 16% in 2022.


Clarity on 2023 spending is also trickling in.  It’s interesting to see where guidance is coming in vs. annualized Q4 levels.  Chevron is flattish on that basis, Hess is up 13% (mostly Guyana.  Bakken spend will be up about 7%), Murphy will be down modestly (a benefit of offshore exposure), and CNX down markedly (-10%).   Hess indicated that costs will likely increase by 10-15% this year, but like a lot of other companies, efficiencies will offset some of this.  We will assemble a table and publish it when more results are in.


Hess’ CEO brought up a very interesting point on their conference call.  The IEA believes that the industry needs to spend roughly $500B a year to meet growing oil demand.  That’s well north of the $300-400B spent per year over the past five years.  It’s unclear to us if the IEA modeled any inflation into these figures, but even with the year-over-year increases we’re likely to see, industry spending will likely fall well short of that mark.


Matador announced the acquisition of Advance Energy Partners for $1.6B.  Advance has 18,500 net acres in Lea County, NM and Ward County, TX, production of ~25 MBOE/d (74% oil), 106 MMBOE of reserves, and 203 net locations (not including 35 potential in the Wolfcamp D).  Advance is currently running one rig in Lea County drilling 19 net wells expected to TIL in 2024).  Matador estimates that it paid 3.2x 2023 EBITDA for the company.


HighPeak Energy is evaluating strategic alternatives to “capture value” not “presently reflected in our share price,” including a potential sale of the company.  The company has identified 2,500 locations in its Howard County acreage, including 1,300 “delineated primary” locations.  HighPeak is reducing its drilling operations from six to four rigs during 1H 2023 and expects to spend c. $1.2B in capex for the full year (dropping to $850-$900M in 2024).


Big 3 OFS Prominent Themes/Undercurrents from Q4 Calls (Bill Herbert)

  1. International Strength, Building Multi-Year Visibility:   The ME and LAM (and Africa for BKR and SLB) are expected to drive double-digit upstream capital spending and activity gains in 2023, especially in offshore and natural-gas domains. This was consistent across the BKR, HAL and SLB calls. The ME is expected to witness record levels of upstream investment related to expansion in production spare capacity for both oil and natural gas. SLB contends that 5-6 ME countries have committed to multi-year production-expansion projects. The golden age of OFS was during the early part of this century, pre oil shale, when best-of-breed large cap OFS generated ~40% incremental margins due to a combination of pricing and activity gains, propelled by the absence of readily available spare oil-production capacity.  While history may not precisely repeat itself, it often rhymes and the present environment, with the convergence of energy and national security, portends a durable reinvestment cycle, holistically and globally. Duration is strengthening and multi-year project visibility is extending to 2030.   BKR booked record LNG orders in 2022.
  2. Deepwater is Inflecting: While offshore awakened 18 months ago, the industry is witnessing a mix-shift to deepwater.  Overall offshore is expected to strengthen in 2023 due to a combination of tie-back activity and new deepwater projects, and deepwater is in the early stages of a resurgence and SLB believes it will witness the most meaningful rate of growth for 2023 as exploration and appraisal activity emerge from prolonged comas. SLB contends that the DW revenue intensity for OFS is 5x that of onshore. HAL stat: over half of its total revs are international and 40% of revs are offshore.
  3. NAM 2023 Guidance Remains Robust and Nuanced: Notwithstanding imploded domestic natural-gas prices, particularly in the Permian, the Big 3 outlook for NAM is robust.  Major oils are expected to maintain strong onshore-drilling activity while GOM is expected to witness a material increase in upstream spending. Onshore, the outlook isn’t as uniformly positive. SLB calling for 1H increases, 2H plateau. HAL calling for continued strength into 2023 with activity surprising to the upside along with rising service intensity. Majors are expected to drive the preponderance of Permian activity growth this year. Cash flow expectations for a number of domestic E&Ps have likely been revised lower due to anemic natural-gas prices – highly relevant as the Permian becomes gassier with rising GoRs. We’ll find out more on this front during E&P earnings season.
  4. Domestic Shale Less Generous: This isn’t a particularly surprising observation for energy blackbelts but, nonetheless, we found the following quote from SLB’s CEO noteworthy: “I think it’s very well known that the limited access to Tier 1 inventory and acreage and the stretched capacity in the market has created a negative inflection on well productivity.” HAL observation: “Domestic E&P capital spending increased by ~50% last year and US oil production expanded by ~6%.” US shale, not too long ago, used to be a productivity dynamic of doing more with the same or less. This may no longer be the case as capital and service intensity appear to be rising.  CVX growth downshift for 2023, and its review of an optimal development plan, is emblematic of the transitional reality unfolding in the Permian from productivity supernova to a more mature phase which continues to be exceedingly consequential but less cathartic than was the case during the first decade+ of Permian unconventional development.
  5. Projected Big 3 FCF Yields Respectable but Fall Short of Inspiring Relative to Other Energy Subsectors: On average, Big 3 OFS stocks have doubled over the past two years. The doubling in equity values has been driven by a dramatic reassessment of cyclical duration and earnings power. All good and all justified. The challenge with global OFS, however, is that FCF yields, relative to other energy subsectors, fall short of cathartic. Average projected FCF yields for the Big 3 OFS are in the vicinity of ~5% – respectable but paltry in relation to the high-single/double-digit FCF yields being fetched by best-of-breed Major Oils, E&P and Refiners.   Another challenge for OFS will come from the continued mix-shift skewing international where the working-capital intensity is higher than the US. Expansionary cycles aren’t uniformly frictionless for OFS precisely due to the working-capital requirements and, indeed capital-spending requirements should the increasingly persuasive reinvestment and duration narratives play out. Capital-spending intensity is expected to oscillate in the ~5-7% range, rising for some, staying at last year’s levels for others.
  6. Distributable FCF is Generous: Guidance on the HAL and SLB calls for a FCF distribution of more than 50% for 2023, and BKR 60-80%. Dividend increases have been meaningful and in combination with buybacks, shareholder distributions are expected to be generous.
  7. Clean-Tech/New Energy an Afterthought on Q4 Big 3 Earnings Calls: Very little discussion about clean-tech and new energy on the Q4 calls. New energy has regressed from a momentum tsunami to a very strong undercurrent – seemingly unseen in the current renaissance of energy security and fossil fuels but nonetheless powerful and accelerating. The front-burner issues are now energy reliability and security given growing geopolitical threats. Reducing carbon intensity is of indisputable importance, but fortifying security and reliability of energy supply, holistically, is the pressing concern of the day and this is likely to persist for years rather than quarters. So, it’s not one or the other in terms of conventional vs. new energy. It’s all the above and all hands on deck. The difference between the two is that conventional energy has and is emerging from stigmatized and marginalized, to now being viewed as critical, and currently has renewed and much needed momentum and improving duration; whereas new energy is normalizing from frenzied to merely essential with a very long runway and high ceiling. According to BloombergNEF, oil and natural gas global investment for upstream, midstream and downstream, collectively, totaled $1.1T in 2022. Likewise, total annual investment in renewable energy, electrified transport and heat, also totaled $1.1 T last year. 2022 was also the first year when investment in decarbonized energy surpassed $1T, with the y/y increase of more than $250B being the largest ever recorded.


Refining Observations (Geoff Jay):  The EIA continues to report uninspiring demand data (although inventories remain supernormally low).  Valero addressed demand in its earnings call, suggesting that the government figures may just be wrong and need revision.  Their wholesale volumes are well north of pre-pandemic levels, but they acknowledge that those may not be reflective of overall demand.  They believe that, given VMT and other data, gasoline demand is likely closer to 98% of pre-Covid “normal.”


Earnings Summaries



  • 4Q22 Total Revenue was $5.6B up 4% q/q and 31% y/y.  NAM was down slightly q/q due to weather-related downtime late in the year.   International revenues were up 9% q/q mostly due to LAM and Middle East.
  • HAL international revenue growth q/q outperformed SLB’s revenue growth q/q by 400bps.  Both HAL and SLB have highlighted LAM and Middle East will drive international growth in 2023.
  • C&P 4Q22 revenue $3.2B (+1%q/q) and op margins of ~21% +200bps q/q, which is the highest operating income margin since 2012.   D&E 4Q22 revenue of $2.4B (+8%q/q) and op margins ~16% +150bps.
  • FCF during the quarter was ~$850MM and capex came in at $350MM.
  • FCF for the year was $1.4B and full year capex of $1B was in line with HAL’s guide of 5-6% of revenue.
  • HAL provided a framework around the return-of-capital strategy:  They will return a minimum of 50% of free cash flow to shareholders via dividends and buybacks.
  • HAL increased its quarterly dividend by 33% to $0.16/sh and repurchased $250MM of its shares in 4Q22 ($5B remaining on buyback).
  • 1Q23 Guide—The quarter will be subject to typical weather-related seasonality and roll-off of year-end product sales.  C&P revenue likely flat with Q422, with margins declining by 75-125bps. D&E revenue expected to decline low- to mid-single digits, with margins down 25-75bps.
  • 2023 Guide—Expect customer spending to increase by at least 15% in 2023 and believe international activity will grow at least mid-teens.  Capex guide is 5-6% of revenue in 2023 and likely comes in at the high end of the range due to supply-chain constraints.  Working-capital intensity expected to increase due to growing prominence of international.  HAL CEO mentioned on the call that street estimates today are about right for the years ahead for both revenue and margins.
  • HAL electric fleets will eventually replace existing equipment in the HAL portfolio, but not in 2023.



  • Revs = $5.9B, +10% q/q.
  • Adjusted EBITDA = $947M, +25% q/q with margins up 190bp q/q.
  • FCF = $657M with $1.6B returned to shareholders in 2022.
  • BKR seeks to return 60% to 80% of FCF to shareholders.
  • Total company orders for Q4 were $8B, +32% q/q driven by IET segment.
  • LNG highlights featured prominently with $3.5B of orders booked in 2022.
  • BKR noted 36 MTPA of LNG FIDs in 2022 with an expectation of an additional 65-115 MTPA of LNG projects reaching FID in 2023.
  • In addition, BKR sees opportunities beyond this.
  • Within OFSE, BKR sees growth trends in international and offshore while NAM levels off.
  • OFSE Q4 revs = $3.6B, +5% q/q.
  • OFSE operating income = $416M with EBITDA at $614M or 17.1%.
  • Objective is to get OFSE EBITDA margins to 20%.
  • OFSE Q1 revs guided to $3.3-$3.5B with full year revs guided to $14.5-$15.5B, implying a nice pick up as 2023 unfolds.
  • Q1 OFSE EBITDA guided to $515-$585M, down due to Q1 seasonality.
  • IET orders in 2023 expected to total $10.5B to $11.5B with IET backlog at $25B today.



  • Revs = $482M, +5% q/q.
  • EBITDA = $136M vs. $113M in Q3.
  • EBITDA margins = 28% vs. 24.6% in Q3
  • Both revs and EBITDA came in ahead of expectations.
  • Q4 capex = $49M with full-year 2022 capex around $140M.
  • 2023 capex is budgeted at $250-$300M.
  • RES will take delivery of a Tier 4 DGB fleet in Q2, but it is geared towards replacement capacity as the company intends to stay at 10 HZ fleets during 2023.
  • We believe RES also operates 2 vertical fleets.
  • CT revenue = $40.5M with most units now active, we believe.
  • Cash = $126M with no debt.
  • RES increased its quarterly dividend by 2c to 4c.



  • 2022 Revenue = $4.1B, +68% y/y with EBITDA = $860M, the highest in company’s history
  • Q4 revs = $1.2B, +3% q/q
  • Q4 EBITDA = $295M, +7% q/q.
  • Capex $116M in the quarter and reduced net debt by $55 to end the year at $175M.
  • Initiated commercial deployment of electric digiFrac pumps.
  • Expect 3 fleets in the market by end of 1Q23 or early 2Q23.
  • $134M returned to shareholders via share repos and a quarterly cash dividend.
  • Reinstated the dividend at .05/sh in Q422.
  • Increased share repo authorization from $250M to $500M with $375M still remaining.
  • CEO at stated on the call “with share price in this neighborhood, I think you will continue to see aggressive buybacks.”
  • Targeting ~40-50% growth of adjusted EBITDA y/y in 2023, with no meaningful change to fleet count from today.
  • If industry reduces activity in gas-related plays due to lower natural-gas prices, LBRT will move equipment to oilier plays.
  • LBRT will unveil new gas pump at the Frac Conference this week in the Woodlands, Texas.
  • Capex of 50% of EBITDA in 2023, or ~$600M.  Should decline to 30% of EBITDA in 2024.
  • DigiFrac expected life vs traditional: 20-25k hours between engine overhauls for traditional and 84k hours for digifrac Rolls-Royce engine.
  • CEO comment on the call: “Two factors summarize today’s frac market: full utilization of existing frac capacity and strong demand for gas-powered fleets that significantly reduce fuel costs – natural gas is much cheaper than diesel – while driving down frac-fleet emissions. This transition to natural-gas-powered fleets is happening at a measured pace, roughly aligned with the attrition of the industry’s older generation diesel-frac capacity.”



  • Production of 1,192 MBOE/d (75% liquids), up ~1.4% sequentially.  Permian volumes of 738 MBOE/d, up 5% sequentially.
  • Full year 2022 production of 1,181 MBOE/d (707 Permian).
  • Full-year 2023 volume guidance is flat to up 3% for the full year, or +35 MBOE/d at the high end.
  • Interestingly, Permian production is now expected to grow ~10%, or +70 MBOE/d, vs. nearly +100 MBOE/d last year.  Reasons for the deceleration are DUC exhaustion in 2022, more single-bench developments, and deeper targets.  The latter two will affect rig movements and the pace of drilling.
  • Q1 guidance contemplates upstream maintenance/downtime impacts of 25 MBOE/d and refinery turnarounds (largely El Segundo, CA) of $200-300mm.
  • Upstream capex in Q4 totaled just more than $3B ($2.2 US), with full year of $9.6B ($6.8 US).  Guidance for 2023 of $11.5B ($8B US), up 20% from full-year 2022, but flattish with Q4 annualized.
  • Increased quarterly dividend by 6% to $1.51/shr (>3% annual yield).
  • Repurchased $3.8B of stock in Q4, forecasting similar levels in Q1.
  • Board authorized buyback of $75B (20% of market cap) without expiration.



  • Production of 386 MBOE/d (59% oil) in Q4, up ~5% sequentially.  Bakken production 158 MBOE/d (50% oil) was impacted by Winter Storm Elliott.
  • Volume guide for 2023 of 360 MBOE/d (up nearly 5% from 2022) at the midpoint, with Bakken production of 165-170 MBOE/d (up 8%).
  • Q1 Volumes of 345-355 MBOE/d reflect lingering winter-storm impacts, with Bakken volumes forecast at 155-160 MBOE/d.
  • Worldwide capex of $818mm ($258mm in Bakken) brings 2022 to $2.7B ($807mm).  Guide for 2023 is $3.7B (up 36% from 2022, up 13% from Q4 annualized), with Bakken portion at $1.1B (+7% from Q4 annualized) based on a four-rig program.
  • Management sees cost inflation of 10-15% for 2023.
  • CEO John Hess highlighted the IEA’s assertion that the global oil industry needs to invest $500B each year for the next 10 years to meet demand growth, compared with $300-400B per year over the past five years.
  • New discovery in Guyana:  Fangtooth Southeast-1, encountering 200’ of oil-bearing sandstone.  The well was the first standalone deep exploration prospect on the Stabroek Block.
  • Hess returned $405mm to shareholders in Q4:  $310mm in buybacks and $95mm of dividends.



  • Production of ~174 MBOE/d (~56% oil, down >7% sequentially). Eagle Ford production of 32 MBOE/d, down 18% from Q3.  The figure was impacted by winter weather (1.2 MBOE/d), unplanned GoM downtime, and lower Tupper Montney performance.
  • 2023 Guidance of ~180 MBOE/d for 2023 (55% oil), up 8% from 2022.  Oil volumes are slated to grow 10% this year.
  • Q1 volumes expected at 161-169 MBOE/d (56% oil), with planned downtime of 7 MBOE/d.
  • Capex of $240mm in Q4.
  • 2023 capex guide of $950mm at the midpoint, down 6% from 2022 levels, and flattish with Q4 annualized.  Eagle Ford capex of $325mm, with three-rig program going to zero in Q3.  Offshore spend of $365mm, with remainder in Montney/Duvernay.
  • Increased dividend by 10% to $0.275/share (2.5% yield).



  • Production of 1,528 MMcfe/d (92% natural gas), down 4% sequentially.
  • Volume guidance of 1,548 MMcfe/d for 2023, an decrease of >2%.  The company expects production to exceed 1.6 Bcfe/d in 2024.
  • Capex of $173mm in Q4, leading to FCF of $276mm for the period.
  • CNX bought back ~$215M of its stock in Q4 and more than $22M worth Q1 to date.
  • 2023 capex guide of $625M at the midpoint, up 10% from full-year 2022, but 10% lower than annualized Q4 levels.
  • CNX estimates that 2023 FCF will be $375M, or 13% of current market cap, given that it is >80% hedged.



  • Throughput of more than 3MM B/d (97% utilization), up more than 1% sequentially.
  • Margin of $22.58/Bbl, up 6% sequentially, largely driven by increases in the Gulf Coast and North Atlantic.
  • Q1 volume guide suggests relatively high turnarounds.  Throughput of 2.7 MM B/d suggests <91% utilization.
  • Port Arthur Coker project nearing completion in Q2, which will increase residual and sour-crude feedstocks.  Strong diesel margins and wide sour-crude discounts suggest annual EBITDA of about $700mm for the unit, vs. estimates of $420mm at FID.
  • Valero met its goal of paying back the $4B borrowed during the pandemic, and as a result, has stepped up its share buybacks ($1.8B for Q4).  Management believes that they will pay now meet or exceed their mid-level payout targets.
  • Management is puzzled by the EIA’s reported drop in gasoline demand recently and suspect it will be revised.  Valero’s wholesale volumes are running about 12% above pre-pandemic levels, and while they don’t believe those figures are indicative of demand growth, they do believe that gasoline demand is more likely around 2% below pre-pandemic levels.
  • Lower volumes of Russian VGO are tightening the market.  Strong distillate cracks will preferentially push VGO to hydrocrackers, leaving less for FCC units, which could have an impact on gasoline production during the summer.





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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