2.06.2023 DEP Industry Observations: Rig Count Down, EIA Takeaways, BKR Annual Meeting; Frac Conference; Q4 Earnings

Macro/Headlines/Events

Baker Hughes U.S. onshore rig count was down 11 rigs last week to 745.

FT-Breakdown of gas storage talks leaves UK exposed to price surges, say experts  Link

WSJ-Oil Industry’s Windfall Fails to Excite Wall Street Link

WSJ-Caribbean Seeks Venezuela’s Oil and Gas as U.S. Relaxes Sanctions Link

DEP Update: In Houston this week for local meetings and Q4 earnings calls.  Considering a quick Midland trip next week, but otherwise we are knee-deep with Thrive Conference stuff (registration at 731 as of yesterday, tracking +12% y/y – be sure to register if you plan to attend).  Looking ahead, we will host our next golf outing on Monday, April 10^th at Kingwood Country Club.  Normally, we would prefer to play on a Thursday/Friday, but course availability was limited.  The good news, however, is our outing will be held on the Deerwood course.  This is where Tin Cup was filmed.  If you would like to play or even sponsor, please shoot us an email.

Research

E&P Observations (authored by Geoff Jay): Reports by a couple of Permian heavyweights this week are keeping the basin’s growth rate front and center. Overall, an increasing number of prominent Permian producers are materially downshifting their growth expectations for 2023 relative to the torrid pace of the past 1-2 years.  We expect this recalibration could prove to be the rule rather than the exception.  With respect to this past week’s earnings calls, XOM guided its Permian volumes to about 600 MBOE/d for 2023, up 40 MBOE/d or ~8% from 2022 levels.  Last year, production grew by 90 MBOE/d or 19%, boosted by DUC liquidation.  The company now believes its Permian production will reach 1 MMBOE/d by 2027 (a goal originally set for 2025), a 13% CAGR from here.

COP’s L48 production (heavily weighted to the Permian) is slated to grow by “mid-single digits” this year, suggesting an addition of at least 50 MBOE/d.  The figure isn’t comparable to last year’s growth of 19% which includes volumes from the acquisition of Shell’s Permian business (180 MBOE/d of production in 2022 per footnote in release).

On the capex side, there was no change to Exxon’s spend announced in December.  Conoco’s budget for 2023 is $11B, up ~37% from 2022 “base” spending.  Most of this increase is due to spending on LNG projects in the GC and Qatar, as well as some investment in its Willow project in Alaska.  Excluding these, Conoco’s capital budget is growing by about 14%, pretty evenly split between inflation and increased activity.  Comparing 2023 spend to annualized Q4 levels, COP is budgeting an increase of ~4.5%, excluding LNG and Alaska.

BKR U.S. Land Rig Count:  Down 11 rigs w/w to 745 rigs.  Q&A on the H&P earnings call, the first driller to report, touched on rig count direction from here.  At this point, HP didn’t give a formal U.S. outlook, but its guidance suggests up-and-to-the-right is hardly a certainty as the company’s current active rig count is 185 rigs with an expected quarterly exit rate at 183-188 rigs.  In other words, the rig count could moderate a smidgeon.  To this point, we are increasingly of the mindset that a minor speed bump, not a sinkhole, is looming.  A few reasons why we aren’t panicked.  First, as HP noted, the super-spec rig market remains tight at near 100% utilization, thus a significant retrenchment in dayrates seems unlikely, although we do believe we will hear some anecdotes of compression relative to leading-edge; (2) anecdotes regarding potential rig count declines stem largely from the Haynesville, a basin which accounts for only 9% of the U.S. land rig market; (3) land drillers are generally well contracted, we believe.  Case in point, H&P claims it has roughly 55% of its total rig count under some type of contractual commitment; (4) to the extent rigs get laid down, there’s a decent chance those are contracted rigs, thus the drillers would get some standby charge which we would assume (hope) would be equivalent to a daily margin; (5) rigs can be subleased which means if a contracted rig gets released, a nimble E&P might be able to pick up a high quality rig at an attractive dayrate – in other words the rig count doesn’t change; and (6) we remain upbeat medium-to-longer term given the long-term call on gas demand (i.e., LNG).

The DEP rig count forecast, which was last updated in November, still shows the U.S. rig count rising to the low 800’s in 2H’23.  That forecast is stale and will be amended in a couple weeks to align better with our recent rhetoric – we’d like to hear from PTEN/PDS this week as well as gather thoughts from a few more E&P’s before we formally amend/publish.  Our gut tells us we find ourselves migrating into the 725-750 vicinity in the back-half of the year.  BTW – flat is not bad.  Last comment comes from an E&P call we had this week.  Contact is a gassy E&P who about two weeks ago told us it would hold activity flat, but that a review would unfold should gas prices moderate.  Since our discussion two weeks ago, gas prices, in fact, faded further, thus activity discussions at this E&P are now underway.  No decision has been made yet, but our take from the company’s tone is a retreat is reasonable, but at the same time tone also suggests a constructive medium-to-longer term outlook.  Same as us, so again, not a reason to run for the hills just yet, but could we see a ~30-40% reduction in a market such as the Haynesville?  Perhaps if gas stays sub-$3, but that’s about 20 rigs and perhaps as many as five frac crews.  Hardly a reason to fear when the U.S. rig count stands at ~745 rigs and our active crew tally is in 275 range (working is a tad less).  To the extent further industry M&A is prosecuted, this can help soften the decline.  Alternatively, if a slug of new entrants emerges, or animal spirits lead incumbents to depart from the replacement vs. growth strategy, then problems could develop.  Time will tell, but one good thing about a speed bump in this environment is that it allows FCF-generating companies with active buyback plans to buy more shares given the recent sell-off in OFS names.  That was a key takeaway of ours from the LBRT call.  Moreover, speed bumps may also cause generalist players/PE to take a breather (i.e., willingness to finance start-up’s in uncertain environments may soften).

Refining Observations:  Earnings reports from MPC and PSX confirm that (like VLO) Q1 will likely be a very high maintenance quarter for them, with utilizations in the 80%’s for both.  For Marathon, turnarounds will persist into Q2.  This will likely keep inventories supernormally low as we head into summer driving season.  Regarding demand, the latest weekly DOEs show gasoline improving but distillates declining, with inventories for both marching higher this week (charts below). On the recently released higher quality monthly data (3-month lag so November is the most recent dataset), while gasoline demand wasn’t as weak as the weekly prints conveyed (-4% vs. -11%), it was, nonetheless, anemic.  Marathon echoed Valero’s comments regarding apparent demand, suggesting that gasoline is likely about 3% below pre-Covid levels, an area that they believe is “sticky.”  Jet is expected to recover to pre-Covid levels. You wouldn’t know it from the weekly inventory data, which showed builds across the board, pushing Gulf Coast 3:2:1 crack spreads down by more than 20%.

BKR Annual Meeting Observations:  Perhaps one of the best annual meetings/investor days we have ever attended – a combination of tremendous global industry participation (~1,500+ attendees), well organized technology/equipment displays and of course, great Italian wine.  From our standpoint, no parting-of-the-seas financial revelations were revealed. Presumably a swath of sell-side notes this coming week will provide more thoughtful reviews of the direction of BKR numbers and valuation, but as loyal readers know, that’s no longer our bailiwick, so we’ll leave the financial opinions to others.  We, however, will summarize a couple of our key takeaways.

• As expected, much of the Q&A focused on financial metrics (i.e., guidance, capital allocation, timing of margin progression, etc.).  Our sense is a key question/concern surrounds peak orders, particularly in the IET segment.  Several attendees zeroed in on this theme, both in and out of the meetings.  However, what jumped out to us was the broader conference discussion surrounding increased use of natural gas as a means to achieve net zero targets.  This discussion didn’t just emanate from U.S. natural gas producers, but rather from global enterprises from the likes of Qatar, Indonesia and a smattering of other worldly venues.  This international need for LNG seems poised to grow thereby presumably driving greater demand for LNG-related facilities – good for BKR and ultimately, the U.S. E&P space as well.  Multiple international speakers, and not just BKR, called out the need to transition from coal as well as noted the unreliability of solar/wind power (without meaningful storage capability).  Consequently, natural gas/LNG should be the obvious answer, at least for the next decade and that bigger theme resonated more with us than any near-term financial discussion.

• The emphasis on and investments in new technology presents seemingly the most intriguing long-term consequential opportunity set for BKR.  This was, in our view, one of the discussion session highlights.  BKR has previously cited ~$400M of New Energy orders but called out a target of $6-7B by 2030.  Twelve portfolio investments/partnerships were cited with two receiving more relative emphasis – NET Power and Mosaic Materials.  Management acknowledged not all of these opportunities may prove out but growing R&D spending coupled with broader investment in other carbon capture, hydrogen and clean energy projects should be expected.  This is due to BKR’s regular review of new opportunities – a normal course of business process which helps identify potential investments. If we understood correctly, this process is measured by a program called the Technology Readiness Level (“TRL”) approach and in the course of chatting with several BKR on-the-line folks, they referred to individual projects’ TRLs, so this doesn’t appear to be some wishy-washy plan developed by consultants, but rather a process understood and followed by the rank-and-file.

• What makes investor days beneficial is not long speeches from the CEO/CFO.  Sure, they are important, but the rank-and-file are the ones who actually develop, drive and ultimately deliver revenue.  Therefore, their perspectives are invaluable.  To this end, a huge swath of BKR business-line managers were present at their respective product line booth and all were available for questions.  To be clear, these folks were well trained on FD, so no “new” revelations were disseminated, at least not to us.  In fact, many answers to our questions were so technical that the one-sided conversation may as well have been in Latin, not a stretch since we were in Italy.  Observing who was at each booth became, perhaps, a more important takeaway as BKR customers were seemingly engaged.  They didn’t just come for the free drinks or the plenary sessions in the main ballroom.  Instead, they were walking the exhibit hall and engaging with BKR employees.  Just how many deals developed as a result of this year’s annual meeting is not clear, but we understand several MOU’s were prosecuted, although size/scale is unknown to us.  Importantly, the benefit of the captive event is that customers were at the booth, not unwelcome vendors trying to sell something to BKR (something you see at OTC and other industry events).

Frac Conference/NAPE Observations (Authored by Sean Mitchell):  We have been busy with earnings and getting ready for Thrive, so we only attended one day of the Frac Conference in the Woodlands and the Raymond James NAPE Dinner at Houston Country Club. Thanks to our good friend Marshall Adkins, we were honored to attend his NAPE dinner which included more than 250 guests enjoying good food, wine and conversation.   We believe the Frac Conference had record attendance this year and the parties were packed with people, extending well beyond our bedtime.  If attendance at these events has any correlation to the health of the industry, the industry is healthy with most attendees remaining optimistic that 2023 will be another busy year.  That said, several industry people at both the Frac Conference and the NAPE dinner expressed their concern about the massive drop in gas prices.    We had several conversations around Frac Demand, Frac Sand and New orders for Equipment, which all started the same comment:  “business is good, but we need gas prices to move higher”.  We heard similar comments on gas from our E&P friends at the NAPE dinner.   Several guys at the Frac Conference mentioned the drop in natural gas prices had not impacted their activity “yet”, which is similar to what we have heard on several of the earnings conference calls so far this quarter.  While some are concerned about lower gas prices and a slowdown in gas related activity, others are confident that they could redirect activity to oil basins if a slowdown did occur.  Last year at the Frac Conference we heard rumblings that Northern White Sand might be needed to address regional challenges and there must have been some truth to that as sand prices last year went vertical pretty fast.  While spot sand prices have returned to earth from the stratospheric level reached last year, prices remain healthy, and several have contracted volumes for most of 2023 and part of 2024. Several frac companies see frac activity as very busy and some were excited about their new generation equipment that is getting more and more attention with their customers as the new equipment not only reduces emissions, but also reduces fuel costs.   Lead time on new build equipment seems to be getting a little better, but still have a couple of examples of extended delivery dates due to major delays with engines.  Still lots of demand on rebuilding frac equipment, but the message is nuanced as one contact mentioned the Tier 2 to Tier 2 rebuilds are being impacted by availability of rebuild slots at engine dealers, but Tier 2 to Tier IV DGB upgrades are impacted by Tier IV DGB engine delays.

Random Anecdotes:

• E&P supply chain contact reports two Eagle Ford sand plants were/are down due to maintenance / weather issues, thus spot prices surged.
• Presumably cold weather will impact Permian activity.  Weather gremlins are an annual reality, thus not a structural big deal.
• Private frac-related contact associated with the capital equipment world indicates it is assisting a private company with potential electric fleet expansion.  More to follow.

EIA Monthly Report Takeaways (Authored by Bill Herbert): The EIA released its 914 monthly production data on Tuesday Jan 31^st. The 914 data is the highest quality domestic production data and has a three-month lag. Thus, the following summary pertains to data as of November. US oil production, in 2022, has largely performed in-line with EIA projections (11.8-11.9 MBD) while nat gas has outperformed. EIA oil production projections for 2023 look reasonable (1H’23 flattish with YE’22, 2023E +550 KBD y/y) and y/y growth optionality will be fueled, in part, by easy y/y 1H comps (1H’22 avg production ~11.6 MBD, Nov ~12.4 MBD). Nonetheless, as Permian GoRs continue to increase and the basin becomes gassier, we wonder about cashflow generation and the willingness to increase activity as nat gas prices, particularly Waha, continue to wallow in torpor. Lastly, December/January production data will likely be impacted by weather gremlins.

Oil

• Total US Oil Production for November:  12.375 MBD flat-to-down m/m and up 585 KBD y/y.
• YTD 2022 Avg production through November:  11.859 MBD.
• L-48 Onshore Production: 10.1 MBD, +558 KBD y/y, – 22 KBD m/m.  December/January weather gremlins will likely result in lower m/m production for next two 914 releases.
• YTD 2022 Avg L-48 Production through November: 9.7 MBD, +620 KBD.
• TX and NM Oil Production: TX (largest US oil producer, by far, with over 50% of L-48 production) and NM (3^rd largest producer behind TX, GOM ~1.8 MBD) production drove the lion’s share of the y/y gains, collectively generating 519 KBD of growth. Sequential m/m production was flat-to-down. TX November production = 5.2 MBD (+216 KBD y/y, -21 KBD m/m). NM production = 1.7 MBD (+303 KBD y/y, -1 KBD m/m).
• 2022 US Oil Production vs. Beginning of Last Year Forecast: 2022 US oil production will likely land in the vicinity of 11.8-11.9 MBD. This compares with the January 2022 CY’22 production forecast of 11.8 MBD – not too shabby.
• EIA 2023 US Oil Production Forecast (Jan STEO): 12.81 MBD, +550 KBD y/y.  The EIA is projecting ~flattish production vs. November through July ‘23 and then exiting the year at 12.6 MBD – plausible. Notwithstanding, nat gas derived cash flows are a more prominent wildcard than many may imagine.

Nat Gas

• Total US Nat Gas Production for November: 122.6 BCFD, +4.4 BCFD y/y, +1 BCFD m/m.

• L-48 Production: ~110 BCFD, +4.2 BCFD y/y, +0.2 BCFD m/m. December/January weather gremlins will likely result in lower m/m production for next two 914 releases.

• YTD 2022 Avg L-48 Production through November:  106.8 BCFD, +4.7 BCFD.
• Biggest Nat Gas Producers:  TX, by far, is the largest nat gas producer at ~31 BCFD (close to 30% of L-48), followed by PA (20.1), LA (11.8).
• 2022 Marketed Gas Production (basically ex-AL) vs. Beginning of Last Year Forecast: 2022 marketed gas production is expected to average ~106-107 BCFD which compares with January 2022 projection for CY’22 of 104 BCFD.
• EIA 2023 US Marketed Gas Production Forecast: ~109 BCFD (~+2 BCFD y/y). The EIA is projecting flattish (vs. November) US production over the course of this year – we’ll take the over.

Nat Gas Pricing Despondency: For those keeping score = Waha nat gas price, as of Feb 1^st, was $2.67/MMBtu and it was 27 degrees, and snowing, in Midland. HHUB was $2.57/MMBTU. According to Bloomberg, the near-month contract for HHUB has been trading below its trailing five-year average price for the first time since 2021, and it’s currently below the $3.21/MMBtu average price seen through the 2010s. As Bloomberg observed, the 2010s was a period when the gas glut was a driver of mass coal-plant closures, a reorientation of the petchem industry from crude oil by-products and exacerbated by the cathartic increase in wind and solar generation. Notwithstanding, the world has changed. The US is becoming Europe’s baseload supplier of nat gas (current TTF price ~$17/MMBtu) and the convergence is only going to become more pronounced over time. Russian nat gas exports into the UK and Europe are down ~90% vs. 2021. As Neil Brown of the Atlantic Council Global Energy Center observed, “It’s one of those moments when a decade, two decades, in the case of gas dependence, maybe even three decades, happens in the course of a few months.” (WSJ). Markedly increased LNG export capacity, over the next ~two years, will help bridge regional gas pricing disparities and lead to some convergence with global gas prices.  But energy is a long-lead time business and meaningfully increased domestic LNG export capacity won’t happen overnight.

Earnings Observations:

XOM

• Production of 3.8 MMBOE/d (64% liquids), up ~3% sequentially.
• Full-year 2023 production forecast at 3.7 MMBOE/d (from Corporate Update in December).
• US production of 1.9 MMBOE/d (66% liquids), up >1% sequentially, Permian was more than 560 MBOE/d (flat w/ Q3).
• WW Q1 production forecast flat with Q4.
• Permian production of 600 MBOE/d in 2023 (up between 7-8% from 2022), 1 MMBOE/d by YE 2027 (13% CAGR).  XOM liquidated its “large inventory” of DUCs built during Covid.
• Upstream capex of $5.4B in Q4 ($2.1 US), up 33% sequentially (US up 15%), bringing full-year 2022 to $17B (~$7B US).
• For full-year, XOM sees being at upper end of its capex range ($23-25B previous 2023 guide)
• Refining profits up 6% sequentially, despite lower volumes.
• Refining will remain tight.  Russian ban will have short-term implications, but market will be efficient at finding workarounds to short-term disruptions.
• 250 MBbl/d expansion at Baytown refinery completed; however, XOM highlighting higher turnarounds and planned maintenance systemwide.
• Chemicals profits dropped nearly 70% sequentially, as global supply growth met softening demand in North America and Europe.

COP

• Production of 1.76 MMBOE/d (52% oil), flat sequentially.
• Full-year 2023 production guide of 1.76-1.80 MMBOE/d (up ~2.5%).  Lower 48 growth “mid-single digits.”
• Q1 production guide of 1.72-1.76 MMBOE/d.
• Q4 Capex of $2.5B (0.3B for acquisitions), FCF of $4B.
• Full-year 2022 spend of $10.2B ($2.1B acquisitions), FCF of $18.4B.
• Guide for 2023 capex of $10.7-$11.3B.  $9.1-$9.3 Base, with Willow (AK) and LNG investments making up the difference.
• Seeing low-single digit inflation in 2023 from 2022 exit, higher in the Permian.  Seeing some areas of spend plateauing.  Called out OCTG as raw-material prices are declining and onshore rigs where rate of price increases is slowing.
• COP’s portion of Port Arthur LNG will be $2B over 5 years, but $1B will be needed this year.
• Willow range of $100-400mm, will be at high end if sanctioned this year.
• Dividends of $2.4B, share repurchases of $2.7B during the quarter.
• Forecasting $11B return of capital in 2023.
• Reserve replacement of 176%.

MPC

• Throughput of 2,895 MB/d (94% utilization), down 3.7% sequentially.
• Margin of $28.82/Bbl, 109% capture rate, up 68% year over year.  Target capture rate of 95%.
• EBITDA of $5.8B, more than doubled from Q4 ’21.
• Q1 Forecast of 2.5 MB/d (88% utilization—driven by 80% utilization in the Gulf Coast due to turnarounds).
• Turnarounds will be heaviest this year in Q1 and Q2.
• Q1 opex per Bbl guided to $5.60, largely due to higher weighting in CA, where energy costs remain high.
• 2023 Capex guide of 1.3B, 20% lower than 2022 levels.  Maintenance capex of $350mm, traditional R&M growth of $550mm, and Low-Carbon Growth of $350mm.
• MPC bought back $1.8B in shares for Q4.  Incremental $5B share repurchase authorization.  More than $7B in authorizations remain outstanding.
• Continued to buy back shares in January.
• Outlook bullish—4 MMB/d of capacity lost WW and expect demand to continue recovery. Demand Commentary: “We expect to see continued increases into 2023 and beyond.”  Gasoline—post-Covid demand down about 3%, and “that’s probably pretty sticky.”  Expect full recovery in jet fuel domestically to pre-Covid levels.
• Q4.  Saw WC gasoline demand up 5% and overall gasoline demand up 2% year on year.

PSX

• Throughput of 1781 MB/d (91% utilization), flat sequentially.
• Margin of $19.73/Bbl, 84% capture rate, up 70% year over year.
• Capture weakness primarily in the Atlantic Basin (67%) and West Coast (61%).
• PSX says biggest impact was turnaround activity in GC and Pacific Northwest and product differentials—particularly European distillate price vs. NY price.  Keystone pipeline outage and winter-storm effects also influenced.
• West Coast utilization of 74% in Q4.
• Q1 Outlook is for mid-80% utilization, with turnaround expenses of $240-270mm.  Chems utilization of mid-90% utilization.
• Full-year outlook for R&M turnaround costs of $550-600mm.
• Chems:  83% utilization in Q4, with adjusted pretax income down >60% sequentially.
• FID reached on integrated polymer facilities in both US Gulf Coast and in Ras Laffan, Qatar.
• Marketing & Specialties margins were lower sequentially, leading to pretax income falling by 35% sequentially.
• Heavy spring turnarounds will likely lead to a tight refined-product market in 2023.

HP:

• Revs = $720M vs. $631M in Q3, +14% q/q.
• Averaged 180.2 rigs in Q4, up from 175.8 rigs in Q3.
• Active rigs at 12/31 = 184 rigs, up from 176 rigs at 9/30.
• Rig count today = 185 rigs with two rigs to go out in February/March.
• Worth noting guidance for the end of this quarter is 183-188 rigs.
• HP still expects to activate as many as 16 rigs in FY’23 with the peak rig count hitting 191 rigs.
• Of the 16, there 12 that have either been activated and/or are in process.
• Four more could be reactivated, but HP would need contractual support.
• HP called out leading edge spot pricing at $38,500/day.  This, we believe, is revenue per day and not a pure day rate.
• Recent anecdotes from private land drilling contacts and a few E&P contacts who report leading edge is closer to the low $30’s.  Rig specs likely explain some of the difference, in some cases.
• HP still sees average revenue per day rising as legacy rigs are repriced.
• Guidance: North America Solutions: Gross margin = $280-$300M which includes $4M of rig reactivation costs.  This compares to revs of $260M in fiscal Q1.  U.S. land rig count to exit the quarter at 183-188 contracted rigs.  International gross margins expected to be $7-$10M, burdened by Middle East start-up costs while GOM gross margins expected to be $8-$10M.  Recall, HP has six rigs destined for the Middle East with a start-up in FY’24 while a rig is also heading to Australia.
• HP decommissioned eight rigs in Argentina.
• FY’23 capital expenditures still guided to $425-$475M.  Q1 capex was $96M.
• FY’22 capex totaled $251M.
• Stock repurchases this fiscal year total $60M.

CLB

• Balance sheet improvement continues as net debt reduced by $12M or 7%.
• Revs = $128M vs. $126M in Q3, +2% q/q
• Revs burdened by F/X and impact from Russia/Ukraine conflict
• EBIT ex-items = $14.7M vs. $13.3M in Q3 with margins up 100bp q/q
• Q4 FCF = $11.2M or a shade under 10% of revs.
• 2022 capex = $10.2M with 2023 guided to $12-$15M.
• CLB tied more to International/Offshore, presumably a plus for 2023/2024
• Interesting product called X-SPAN called out on the earnings call.  Possible solution to traditional workover rigs.  We will explore more about this post earnings.
• Guidance
  • Reservoir Description revs down low-to-mid single digits
  • Production Enhancement revs up mid-single digits
  • Consolidated revs to be $125M-$129M, essentially flat q/q
  • Operating Income guided to $11.5M to $14.5M

CHX:

• 4Q22 Revenue was $985.9M -3%% q/q and +20% y/y
• Sequential revenue decline was driven by NAM seasonality, weather and temporary inventory destocking.
• EBITDA $178.8M  +8 q/q and +34% y/y, achieved target exit rate EBITDA margin of 18%.
• Returned $95M  to shareholders during Q4 with $15M cash dividend and $80M of stock repo.
• Ended year with $889M of liquidity, $250M cash and $638M on R/T facility.
• Analyst Day in New York March 7, 2023.
• CHX was named XOM’s supplier of the year for 2022.
• 1Q23Revenue Guide in the range of $952M to $982M.
• 1Q23 EBITDA Guide in the range of $164-172M.
• FY23Expect EBITDA margins to improve during 2023 from the Q1 seasonal low.
• FY23 exit rate adjusted EBITDA margin of 20%,
• FY23Expect to return at least 60% of free cash flow to our shareholders.

Product Inventory, Demand, and Margin Charts

(Shaded areas show the 5-year range)

Source for Inventory and Demand Charts:  Energy Information Administration, Bloomberg, LP

Source for Margin Charts:  Bloomberg, LP

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