Baker Hughes Rig Count- The U.S. onshore rig count was down 1 rig w/w to 731.
WSJ- Clean and Cheap Oil Is a Heavy Lift- Link
FT- The rare earths race entails difficult choices- Link
WSJ- Biden Declares U.S. Arctic Ocean Off Limits to New Oil and Gas Leasing- Link
WSJ- Saudi Aramco Posts Record $161 Billion Profit for 2022 –Link
WSJ -Coal Keeps Germany’s Lights On- Link
WSJ-Is ESG Profitable? The Numbers Don’t Lie – Link
DEP Update: Lots on the docket – let us know if you have interest. We have a number of open spots at our golf outing.
- March 28th – DEP reception/dinner in Midland.
- March 28th – DEP dinner in Shreveport (DUG Haynesville)
- April 3rd – OKC dinner/reception – location TBD
- April 10th – DEP Golf Outing at Kingwood Country Club
- April 19th – DEP reception in Midland
- April 20th – Cooking BBQ for the kids at Bynum. All the donations appear locked down. Thanks to all for offering to help. These kids are great and we’ll likely do this again in the fall.
- May 2nd – OTC BBQ at Sean Mitchell’s House
- May 9th – Cooking for the Barrels & Clays event by Merit Advisors in Gainesville, TX (details coming out next week)
- June 27-29th – Telluride Executive Series (working agenda forthcoming next week)
- August 29-31st – The Executive Series at Pebble Beach (agenda forthcoming next week)
DEP Podcasts: Before THRIVE, the DEP team spoke with Mike Dyson and Chris Caudill of Infinity Water Solutions. The discussion focuses on the important role that water management plays in the energy industry, and how Infinity is helping companies optimize their water usage and reduce their environmental footprint. Shortly after the podcast was recorded, Infinity announced a multi-year contract with XTO Energy to manage their produced water in the Delaware basin. This is an achievement for the company that demonstrates the growing demand for water management solutions in the basin. Our next podcast will be our team recap from THRIVE, admittedly a bit late. We also have upcoming podcast with Infrastructure Networks which we’ll be recording later this month. As always, thank you for listening and feel free to reach out with comments or suggestions. The podcast link is below.
OFS Pricing Thoughts: In our Random Observations section below, we highlight a few recent pricing observations shared by both E&P and OFS contacts. OFS pricing will surely be a topic widely discussed in the coming months as D&C activity flattens. Notably, the BKR U.S. land rig count is now down 33 rigs from its November 2022 high of 764 rigs while a modicum of new market entrants in various OFS segments has emerged. Presumably, further activity moderation materializes given sub-$3 nat gas prices while chatter of more Permian E&P M&A could lead to rig releases should buyers seek to preserve inventory. That’s not a backdrop for constructive OFS pricing, but to some E&P readers who may view this as a moment to strike back at what some have shared as a perceived overzealous OFS pricing environment, we point out recent Q4 earnings results which highlight not all OFS sectors are overearning. In fact, one could argue some sectors still need higher pricing. Case in point, KLXE, NINE, RNGR and NCSM all reported Q4 results this past week. Adjusted Q4 EBITDA margins for the four were 16.7%, 18.0%, 14.0%, and 15.9% respectively. Improved from the trough, but hardly overearning. Moreover, layer in their respective guided capex spend and, in some cases, interest expense and it’s clear, substantial free-cash flow (as a percent of revenue) is not in the cards. Moreover, cost pressures remain acute, so potential price concessions directly hit the bottom line. Further, should industry activity soften further, lower utilization typically yields cost under absorption. So while it is tempting to seek lower prices, actions have consequences and another softening could mean even more OFS M&A – that’s generally not good for the E&P end-user.
- A new frac company will kick off operations in 1H’23. The new enterprise is called Flux Energy Group and will be managed by executives who previously built/sold a frac company. It is our understanding the first fleet is comprised of legacy equipment, but in the coming months, Flux will begin its transition to emission-friendly equipment. Moreover, a one fleet frac company is not an optimal size, thus we would expect Flux to order more equipment in 2024. Lastly, the company, we believe, is contractually supported by an E&P company.
- We take no joy in reporting OFS pricing weakness, but we do try to call a spade, a spade. To this end, we received inbound comments by both OFS/E&P friends that pump down pricing is moving lower in the Permian. A few reasons cited: (1) speculation is some larger companies may be using legacy pumps to chase the pump down work; (2) wind-down of DUC’s means less toe-preps, thus less demand; (3) combination of new start-ups the past two years with assets now leaving gassy areas for oily areas; and (iv) minor activity malaise which disproportionately impacts the spot market. One contact shared a decline from mid-$9,000’s/day to the mid-to-high $7,000’s/day. Another contact was at $10,500/day and was just quoted $7,500/day while another shared an anecdote of nearly $13,000/day to the $9,000’s. Exact numbers not that important, rather it’s the trend. And, to further validate a potential softness in the pump down market, we caught a LinkedIn post noting availability of two pumps available “for all your pump down needs.”
- Additionally, an E&P contact shared with us a recent quote for different classes of land rigs. Basically, the advertised rates are mid-to-high $20’s and according to our contact, the asking prices were characterized as “negotiable”. Rigs in the mid-$20’s do not appear to be super-spec, but one rig quoted in the high $20’s seems to be borderline top quality.
- On the frac side, supply chain contacts report inbound calls from companies alerting them to availability. One E&P recently conducted an RFP. Over 10 companies participated in the RFP and roughly 75% of them had availability. Consequently, too much supply and moderating activity is leading to spot market pricing softness.
- Yet not all is doom and gloom. One E&P, discussing the pump down market, claims it never saw the price spike as others did given its use of dedicated arrangements and efforts to partner with its service providers. For instance, this E&P pays roughly $8,500/day for a pump down unit, well below where spot prices peaked in recent months. Consequently, it is not seeking concessions. Further, we still believe the emission-friendly equipment will be able to maintain better pricing while other businesses such as land drilling and frac sand benefit from take-or-pay contracts. As always, this is a nuanced market and if our rig count forecast in 2024 is directionally right and if consolidation transpires, OFS pricing should firm once again, if not go higher next year.
Is there a silver lining for OFS companies? Yes, but the answer likely takes time. First, we remain optimistic vis-à-vis activity in the medium-to-longer term, an admittedly consensus view. In the short-term, our opinions don’t help spot OFS friends operating in gassy areas as the pricing/utilization pressure likely increase. But don’t forget there is a road map for a nat gas recovery in 2024/2025. Second, we continue to believe consolidation will unfold, particularly as the market softens. This should, in our view, help narrow the bid/ask spread, a point RNGR noted is beginning to occur (on its Q4 earnings call). Perhaps indicative of this narrowing is the fact that KLX Energy just announced/closed its acquisition of Greene’s Energy Group. We don’t have specifics on that negotiation, but broadly speaking, sellers need to be realistic with respect to valuation. That is, one needs to balance EBITDA multiple desires vs. equipment replacement value. Remember, discerning buyers shouldn’t value a business off Q4/Q1 EBITDA run rates if said business is a spot player in a market where OFS pricing may decline and where activity appears to be bleeding lower (which it is). Nevertheless, we remain steadfast in our view that consolidation likely continues. Why? First, multiple private companies continue to tell us they are willing sellers. In fact, one small regional completions-oriented business told us it recently received an unsolicited offer. Second, there are still many OFS enterprises which remain PE-backed and presumably, these PE firms need to find an exit (some have been stuck in their investments for years). Third, we continue to believe pricing/synergy benefits exist for smart buyers. Fourth, contacts in the banking community are busy and report very strong backlog, an indication M&A spirits are alive and well.
To this end and potentially proving our point about M&A, we came across a business being marketed by business brokerage firm. Here are the details which, BTW, are on the internet, so no inside info here. The company for sale is in the pump down and chemical mixing space. Revenues in 2022 were advertised at $22M with EBITDA advertised at $6M. Assets include 14 pump-down trucks among other items. Interesting to us is the company was founded in 2021, so a relatively quick flip if this materializes. Business is located in Midland, TX. We’d be willing to bet that many of the leading OFS M&A shops have good backlog which would further validate our thesis for more potential OFS M&A.
E&P Observations (authored by Geoff Jay): As a few more earnings reports trickled in, a major industry conference was held in Houston, and the future of US shale was front and center. PXD CEO Scott Sheffield predicted that the Permian would peak within six years as the best acreage gets drilled up—a comment that dovetails with the beliefs of some of our panelists at Thrive who agreed that only a handful of companies have more than a 10-year drilling runway. He believes the US will grow oil production by only 400 MB/d in 2023. COP CEO Ryan Lance agreed, signaling that the Permian’s plateau means more market share for OPEC in the future. John Hess, CEO of HES, highlighted that global investment in oil and gas is in structural deficit, and that rising interest rates and tighter financial markets just “make the mountain steeper.”
SWN held an Analyst Day, reaffirming their capex forecast and their decision to drop 2 rigs in the face of lower natural-gas prices. The company highlighted their depth of inventory—both in the Marcellus (~4,800 total locations/~1,150 core) and the Haynesville (~1,550 total/~900 core)—and drilling improvements. In the Haynesville, footage drilled per day increased 10% last year, and days on location dropped 10% as a result. These efficiencies plus access to the Gulf Coast LNG corridor should lead to higher FCF going forward. SWN forecasts that at the strip, it will generate $2B of FCF over the next five years, $7B if natural gas averages $5/mcf.
With earnings largely behind us, here’s how 2023 capex is shaping up vs last year and Q4, annualized: Basically about a ~10% increase relative to the Q4 annualized run rate.
Rig Count Forecast: Amending our rig forecast lower to reflect current realities. Our model was last updated in November 2022. At that time, we were trying to balance feedback from our September E&P survey which indicated a flat rig count in 2023 and then contrasting our survey to the outlooks from the public land drillers, which at that point were more optimistic. With respect to our November 2022 forecast, we opted to go with the more optimistic view from our land drilling friends, which frankly wasn’t that crazy given where nat gas prices were trading at the time. In hindsight, though, the views of our E&P friends proved more right than wrong. Now, to our updated forecast, we model the BKR rig count declining to the ~700-720 range this year but beginning a rebound in early 2024, rising to the 750-800 vicinity in 2H’24. Simplistically, we assume L48 oily basins remain resilient, but gassy areas pullback. Further, we assume public E&Ps will maintain discipline and won’t react quickly to a rebound in commodity prices. Additionally, we assume the recent SVB collapse doesn’t create broader economics risks/slowdown. In other words, this is our 2023 view. Looking into next year, the range of outcome remains wide (see EIA March STEO Summary below). Our forecast loosely assumes roughly $3.00 gas this year, but improving next year (2024 strip in the mid $3’s) with WTI in the high-$70’s. Remember, a sharp acceleration in oil prices didn’t lead to outstripped growth in rig count in 2022/2023 as E&P capital discipline kept activity largely intact. Therefore, we are inclined to believe activity increases in 2024 will be measured given the CY’24 strip is in the mid-$70’s. However, if WTI inflects higher in late 2023 (i.e., during budget season), this would lead to an upward bias for activity. Conversely, if the much-anticipated China recovery fails to materialize and oil prices migrate into the $60’s, we would expect the decline in activity to outpace what we are modeling.
EIA March STEO Summary (authored by Bill Herbert): The EIA’s STEO (Short-Term Energy Outlook), was largely unchanged. The US oil production forecast was tweaked lower for 2023 and 2024. The current industry parlor game is prophesying US black oil production growth for 2023. Most industry protagonists believe that +500 KBD is the upper-bound, with a strong likelihood of something less, while some prominent E&P CEOs expect sub-400 KBD. The EIA is projecting 560 KBD of growth – plausible, but it wouldn’t surprise us if was a bit less, while it would if it was more. The latest (Dec) monthly production print was 12.1 MBD, down 276 KBD m/m due to disruptive weather. Thus, November was the last clean monthly print at 12.38 MBD. YTD weekly production data has been running at 12.2-12.3 MBD, juxtaposed against the 2022 average of 11.88 MBD (1H ~11.6 MBD, 2H ~12.2 MBD). The Permian rig count has remained resilient – for how long will be a function of E&P commodity price and cashflow expectations. While E&Ps aren’t going to front-run tightening market balances, will they do more than trim activity in the near-term? The very near-term outlook for commodity prices remains muddled due to shoulder-season headwinds, the black-box known as China (not to mention Russian exports), Fed policy and USD strength. The intermediate term bull case for crude rests on a cathartic China oil PUD (pent-up-demand) surge beginning in Q2 (IEA = 2022 ~+900 KBD y/y, Q2-Q4 y/y demand growth ~1.2-1.3 MBD y/y). The L-T bull-case is the convergence between obdurate ROW demand growth ex-China and OECD, ongoing deliverability challenges and the acute need to augment energy reliability and security. Getting between here and there is the nuisance.
While the nat gas production forecast was largely unchanged (dry gas production 2022 ~98 BCFD, 2023 ~100.7, 2024 ~101.7) the average projected price for 2023 was markedly reduced from $3.40/MMBTU to $3.02 as Jan and Feb mild weather resulted in reduced withdrawals. As a result, the EIA now expects inventories to close the withdrawal season at the end of March at ~1.9+ TCF (vs. March 2022 ~1.4 TCF), 20-25% higher than the 5-yr average and +36% y/y. Much of the 2023 outlook is contingent on weather vicissitudes and we’ve gotten off to a tepid start. For now, despondency rules but stay tuned.
The focus of the following summary is largely on domestic oil production and US nat gas projections – the IEA OMR and OPEC MOMR will be published next week and from those we glean global insights.
- Brent Price Forecast: 2022 = $101/bbl, 2023E = $83 (prior $84), 2024E = $78 (prior $78).
- US Oil Production: As expected, the 2023 US oil production forecast was tweaked lower from 12.49 MBD to 12.44 MBD, resulting in expected y/y growth of 560 KBD (prior estimate +590 KBD). The projected growth is lubricated, in part, by easy 1H comps (1H’22 ~ 11.6 MBD, 2H ~12.2 MBD ). Thus, the 2023 estimate of average production is flat-to-up vs. November (the latest clean monthly print). YTD weekly production data has been running at ~12.2-12.3 MBD. Accordingly, the EIA’s 2023 estimate looks onside, particularly vs. OPEC’s expectation of +750 KBD. The EIA’s 2024 estimate was tweaked lower from 12.65 MBD to 12.63, yielding 190 KBD of projected y/y growth for 2024. Much of this will be contingent on the slope of China PUD growth. A cathartic PUD surge will yield tightening market balances, higher oil prices, higher E&P CF, reinvestment, and US oil production, while a fitful and anemic recovery will suppress all the above. The messaging out of Beijing last week was relatively tempered (5% targeted GDP growth) while anecdotal ground-level data yields a more vigorous emergence from Covid purgatory. We expect 2023 to be another wild ride with respect to price volatility given the wide range or perceived outcomes for China demand (our view = likely cathartic) and Russian oil/product exports (our view = likely resilient), not to mention domestic nat gas prices and E&P cash flows
- HHUB Price Forecast: 2022 ~ $6.42/MMBTU, 2023E = $3.02 (prior = $3.40), 2024E = $3.89 (prior $4.00).
- US Nat Gas production: 2022 = 98.1 BCFD, 2023 = 100.7, 2024 = 101.7 BCFD.
LNG Exports: 2022 = 10.6 BCFD, 2023E = 12.1 2024E = 12.7. LNG exports are expected to exit 2023 at 12.8 BCFD and 2024 at 14.1 BCFD.
ChampionX Investor Day Observations (authored by Sean Mitchell): We attended CHX’s Investor day in New York last week and there was a good mix of sell-side and buy-side analysts that attended in person. Overall, we were very impressed with the Investor Day as CHX had leaders from each of the business segments discuss how they deliver value for their customers. CHX also hosted an hour plus session of interactive exhibits which allowed everyone to ask more detailed questions. As many of you know, we leave the financial modeling, valuation framework and stock picking to typical wall street research firms. That said, CHX’s message on the financial front was pretty simple. Over the next several years, management expects: 1) High Single Digits Revenue CAGR; 2) 20%+ EBITDA Margins and 3) > 60% of FCF as Capital Returns. We are not going to comment on whether CHX can meet or exceed their financial targets, but rather we will provide you a few key takeaways from the investor day.
- We were impressed by the CHX team, not just the C-suite, but really the engineers and scientists who work in the field. After spending several hours with some of the CHX’s field level engineers, it was easy to see how CHX was chosen as ExxonMobil’s 2022 supplier of the year. The award from ExxonMobil specifically mentioned CHX’s help with their major assets in Guyana and the Permian Basin. While these two basins are very important to Exxon, they are also critical to global supply of oil for the next several decades. The other impressive thing about this award, it highlights CHX’s ability to deliver value both onshore and offshore. In addition to ExxonMobil, CHX’s key customers both in the U.S. and International markets highlights their competitive position as a leading global energy production optimization solutions provider.
- During the chemical technologies presentation, CHX highlighted that their growth framework would encompass: 1) current production; 2) new production offshore/deepwater; 3) new production-unconventional (NAM, LAM, ME) and 4) new production- heavy oil. Growth is not just about the current and new production of hydrocarbons, but rather total fluids (water and hydrocarbons) and chemistry intensity that will drive growth for CHX. As both current and new production are set to become more chemistry intensive, the revenue opportunity for CHX gets better. This is especially true in the Permian Basin with rising GOR’s and the move to drill Tier 2 and Tier 3 inventory.
- During the interactive tour we got to see CHX’s new Aura OGI (optical gas imaging) and MWIR (MidWave InfraRed) Camera that they will be launching in 2H23. The camera will be used for emissions monitoring and captures images with four times higher resolution than other cameras on the market. The team at CHX was very excited about the camera and several investors spent time visiting with the team about the benefits of the new camera. During the interactive tour, we also spent time talking to the Drilling Technologies team about the use of diamond drill bit inserts and bearings. While diamond drill bit inserts/bearings help customers drill faster, reduce interruptions and unprofitable downtime, they only represent approximately 2% of the drilling cost of an average well. Translation small impact on drilling cost, but big impact on drilling efficiency. One example that caught our attention, diamonds bearings used in directional drilling downhole tool vs traditional bearings, increased the bearing life from 300 hours to 3,000 hours.
- CHX expects FY 2023 exit rate adjusted EBITDA margin of 20%, adjusted EBITDA to FCF conversion of at least 50% and return of at least 60% of FCF to shareholders.
- Revs = $154M, -13% q/q
- Adjusted EBITDA = $21.6M vs. $30.3M in Q3
- Well Service revenue = $72.6M.
- Q4 rig hours = 113,600 vs. 123,000 hours in Q3
- Rev/hour = $640/hour vs. $648/hour in Q3
- Wireline revenue = $48.3M.
- Processing/Other Revenue = $33.4M.
- 2023 Guidance:
- Revs = $685M – $715M, +15% y/y at the mid-point
- Adjusted EBITDA = $95M – $105M vs. $79.5M in 2022
- Capex = $25M – $35M vs. $14M in 2022
- Targeting FCF of $55M to $70M.
- Revs = $167M
- Adjusted EBITDA = $30M.
- Converted two wireline units to electric in 2022 with 4 to be converted in 2023.
- Cementing revs = $65M, +2% q/q.
- Rev/Job +8% q/q.
- Wireline revs = $30.3M.
- Stages = 5,879, +3% q/q.
- Rev/stage = flat
- Completion tool revs = $35.3M, -13% q/q.
- CT revenue = $35.9M, +9% q/q.
- CT days +5% q/q.
- Avg blended dayrate = -3% q/q.
- Noted weather impacts of 1-5 days in certain service lines.
- Revs guided to $160-$165M.
- Margins likely compress (DEP view)
- Capex guided to $25-$35M.
- Revs = $40.2M.
- Adjusted EBITDA = $6.4M.
- Cash = $16.2M with $7.9M of total debt.
- 2023 capex budgeted at $4-$5M.
- Q4’22 was down q/q due largely to seasonal factors.
- For all of 2022, NCSM witnessed a 31% revenue increase.
- Anticipates flat-to-10% y/y activity improvement in NAM.
- Believes International activity will be up 10% y/y.
- Operational highlights includes sales of product to new customer in the North Sea while Repeat Precision commercialized its PurpleFire perforating gun system.
- Revs = $223.3M vs. $221.6M in Q3
- Adjusted EBITDA = $37.3M vs. $37.1M in Q3
- Net debt = $226M, -11% q/q.
- Running 2 frac fleets in the Mid-Con and a partial fleet elsewhere
- Acquired Greene’s Energy Group
- 2023 revenue guided to $975M to $1.04B with EBITDA margins of 17-19%
- Capex guided to $55-$65M.
- Production of ~105 MBOE/d (45% oil), up 11% sequentially.
- 2022 average volumes of 78.2 MBOE/d (44% oil).
- Volume guide of 96-104 MBOE/d for FY 2023, 44% oil, 69% liquids.
- Expect a production lull in Q2, with recovery in Q3 and Q4.
- Capex of $181.9mm, brings full year 2022 to $530.6mm.
- D&C will be fairly ratable throughout the year, but 80% of the $70-75mm of non-D&C capex (mostly infrastructure related) will be spent in 1H.
- Maintaining 5 rig program: 3 Delaware basin, 2 Midland.
- Production of 37.3 MBOE/d (85% oil), up 42% sequentially.
- Full year volumes of ~24.5 MBOE/d (85% oil).
- Production guided to 47-53 MBOE/d in 2023, 70-76 MBOE/d in 2024.
- Capex of $321.6mm brings FY’22 to $1.05B.
- Guide for $1.15-$1.26B ($50-60mm infrastructure/land/other) of capex in 2023, $870-930 in 2024.
- HPK expects to run 4-5 rigs this year with 2-3 crews, moderating to 4 rigs and 2 crews in 2024.
- Production of 44.2 MBOE/d (72% oil), up 3.8% sequentially. Winter storms sapped volumes by ~4%.
- Full-year 2022 production of 40.8 MBOE/d (72% oil).
- D&C of $157.1mm in Q4, Total capex of ~$174, brings fully year capex to $481.5mm.
- Merger w/ Baytex expected to close late Q2 this year.
- No guide as a result of deal, but Baytex plans to double EBITDA, increase FCF per share by 20%, and increase shareholder returns to 50% of FCF, including initiating a dividend.
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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