05.08.23 DEP Industry Observations: Q1 Earnings Takeaways; EIA Monthly Report; Rig Count – 8 rigs w/w

Macro/Headlines/Events

BKR U.S. Land Rig Count: Down 8 rigs w/w to 725 rigs.

WSJ- Big Oil Has $150 Billion in Cash and Investors Want a Share   Link

FT-Falling crude prices and recession fears bring US oil and gas rally to a halt   Link

WSJ- Shell and BP’s Hidden Spark- Link

WSJ- Warren Buffett Has Been Betting Big on Oil. It’s Time to Find Out Why Link

DEP Update:  We will be in Gainesville this week – cooking for Merit Advisors and 250+ of their guests.  Also, conducting several meetings in both Fort Worth and Dallas.  Let us know if you are in town.  Also, kicking off the Permian Basin BBQ Cook-Off planning process.  Be on the lookout for details.

Research

Activity / E&P Spending Observation.  After reading through a zillion transcripts as well as chatting with industry contacts, the messaging is largely the same.  That is, essentially no change to ’23 capex budgets. Stability is the theme for most oil-focused players.  Nat gas players, on the other hand, cite rig and/or frac crew declines (CRK, CHK, SWN).  But while most budgets were reaffirmed, there are a number of cases 2023 spending is 1H’23 weighted.  As a result, rig activity is poised to moderate into 2H’23 (MRO, CTRA, CPE, RRC).  Meanwhile, in other cases, rig counts will decline simply due to M&A integration (i.e., FANG, OVV).  Emerging signs of deferring well completions also emerged as both MGY and EOG cited plans to moderate completion activity.  This comment was echoed to us by a small private Eagle Ford E&P who contends it will do the same.

A key question to both E&Ps and OFS companies is how much more downside does the Haynesville have and how much equipment could be relocated from the basin?  CHK noted that from what they’re seeing in non-op activity, they would expect another 10 rigs to leave the basin.  Recall, per BKR the Haynesville peaked at 72 rigs in December, but as of this past Friday, the Haynesville rig count totaled 62 rigs.  It is worth noting most of what is drilling now will produce in 2024, so movements in next year’s strip (now at $3.55/mcf) will drive decisions around activity going forward.  That was a point made by CHK.

Service costs were a big topic as well, with most agreeing that costs have at least plateaued and many claiming they are descending.  Essentially all OFS verticals are reported to be partaking in some form of concessions.  E&P companies don’t necessarily report widespread concessions, but when one reads through all the various transcripts, one will find references to concessions with the following services: cementing, wireline, drilling rigs, frac, OCTG, diesel, among others.  Not a big surprise as we’ve been citing price concession anecdotes for some time.  Keep in mind, some service companies have defended pricing on Q1 their earnings calls, thus nuances exist, but the big picture is pricing likely moves lower in a low $2 gas environment as activity bleeds lower.

Other items of interest this quarter are more E&P companies highlighting diesel displacement due to the adoption of dual-fuel and/or electric frac (MUR, PDCE, CRK).  Others cite the virtues of refracs, with MUR, for instance, noting a healthy uptick in production.

A final point worth considering.  A number of the rig and frac crew reductions appear to be nothing more than budgetary.  That is the spending is 1H’23 weighted.  For instance, several Marcellus E&Ps cited this two weeks ago whereas this past week, our interpretation of MRO and CPE’s commentary suggests the same thing.  Presumably, for some companies to maintain production at current rates, activity levels may need to inch higher in 2024.  Then, consider CHK’s comments that reducing activity at this point doesn’t necessarily do any good (our translation) given the limited impact on today’s production.  Much of the gas from new drilling would come online in ’24 so with the forward curve for gas presently in the mid-$3’s, it makes sense to maintain activity.  Moreover, the growing reference to more drilled, but uncompleted wells is similarly something to pay attention to.  The numbers, admittedly, aren’t that high, but we are starting to see some pivot by E&Ps to defer spending.  This, in our view, is short-term noise. If the CY’24 strip holds and nat gas next year stays in the mid-$3 range, then these DUCs should be completed next year. Finally, don’t forget the emergence of new E&P companies who will need rigs as acreage is acquired.  Again, not huge numbers yet, but several of our E&P friends who sold within the past year are likely to reemerge – at least that’s what they tell us.  In some cases, they already have.   If all four of these observations are correct, it reaffirms our view that the L48 market is hitting a speed bump and not driving into a sink hole.  Furthermore, if the large public OFS players are true to their words – that is, they hold price and cede some market share to others, then the incremental suppliers for some services next year might be few, not many (i.e., land rigs).  Time will tell, but our gut tells us a re-tightening in the OFS market is a real possibility in 2024, barring a more pronounced recession and/or another unusually warm winter.  Between then and now, don’t forget the trend for more OFS consolidation remains at the same time expansionary capex plans within OFS are being trimmed given prospects for near-term activity moderation.

2023 E&P Budgets

• SBOW = $450M to $475M, no change.  Roughly 48% to be spent in 1H’23.
• MGY = Lowered budget 10% to $440M to $460M.
• CTRA = $2.0B to $2.2B, no change.  Roughly 52-54% to be spent in 1H’23. (at mid-point)
• MUR = $875M to $1.025B, no change.  Roughly 60-65% to be spent in 1H’23. (at mid-point)
• CRK = D&C capex = $950M – $1.15B, no change.  Roughly 54% to be spent in 1H’23 (at mid-point)
• FANG = D&C capex = $2.25B to $2.41B, no change.  Roughly 52% to be spent in 1H’23 (at mid-point).
• CHK = $1.765B to $1.835B, no change.  Roughly 60% of the budget to be spent in 1H’23.
• MRO = $1.9B to $2.0B, no change.  Roughly 60% of the budget to be spent in 1H’23.
• ESTE = $725M to $775M, no change.  Roughly $400M of the budget to be spent in 1H’23.
• CIVI = $725M to $825M, no change.
• ERF = $500M to $550M, no change.
• CHRD = $825M to $865M, no change.  Roughly 53% to be spent in 1H’23 (at mid-point).
• PDCE = $1.35B to $1.45B.  High-end previously $1.5B but reduced due to cost savings.  Roughly 53% to be spent in 1H’23 (at mid-point).
• CPE = $1.0B, no change.  Appears ~55% of ’23 budget is 1H’23 weighted.

E&P Data Points

• SBOW will maintain 2 rigs.
• MGY will maintain 2 rigs.  Deferring some completions.
• CTRA will drop 1 Marcellus rig and 1 Marcellus frac crew.
• MUR highlighted refrac success with wells seeing a 10x improvement in production.
• CRK will drop a rig – moving from 8 rigs to 7 rigs.  Will continue to re-evaluate both its rig count and completion timing.  Will turn-to-sales 12 wells with laterals of 15,000 feet.  Cited wells in the Western Haynesville which IP’d at 36 mcf/day.  Highlighted virtues of its TITAN fleet.
• FANG dropping two rigs, as expected.  Drilled 82 gross wells in Q1 or 24% of expected ’23 wells drilled.  Now running two HAL electric fleets.
• CHK: Will release 2 rigs in the Eagle Ford in Q2 and one rig in both the Haynesville and Marcellus in Q3.  The company will also drop one frac crew in the Haynesville this quarter.
• MRO:  We believe the company will reduce rig count by ~2-3 rigs.
• ESTE will maintain 5 rigs.  Cited a 34% improvement in lateral feet drilled per day on wells vs. what the prior operator had achieved.
• CIVI continues to run 2 rigs and 2 frac crews.  Spud-to-spud for a 2.5 mile lateral in Q1’23 = 5.3 days, a 17% improvement vs 2022 drilling times.
• EOG will defer completions in their Dorado play.
• ERF continues to run 2 drilling rigs.  Completion activity accelerates in Q2/Q3, then moderates.  Cited 10% reductions in each of the past two quarters for its casing/steel costs.
• CHRD picked up a 2^nd frac crew in Q1 but will drop it at the end of Q3.  Noted 14.2 days spud to rig release times for 3-mile laterals.
• PDCE operated 4 rigs and 3 frac crews in Q1.  Cited use of local sand in the Wattenberg, the transition to an electric fleet in Q2 and utilizing an electric drilling rig.
• BP’s L48 business, bpx, added two Permian rigs during Q1, bringing its total in the basin to five (Haynesville and Eagle Ford are both unchanged at three rigs each)
• APA likely reduces Alpine High activity
• CPE reducing from 7 rigs to 5 rigs.

Callon Petroleum announced two transactions this week:  A divestment of its EF assets for $655M to Ridgmar Energy Operating.  CPE produced ~21 MBOE/d (72% oil) in the EF last quarter.  Separately, CPE acquired the interests of Percussion Petroleum for $265M in cash and 6.46 million shares of stock (~$475M total consideration).  Percussion assets include 18K acres in the Delaware, 14 MBOE/d (70% oil) of production, and 70 drilling locations.  CPE estimates it purchased these interests at 2.5x NTM EBITDA. Given FCF accretion and deleveraging associated with these deals, CPE is launching a $300M buyback on closing.

EIA Monthly Report Takeaways (Authored by Bill Herbert): The EIA released its 914 monthly production data on Monday, May 1st. 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 February. While Feb oil production of 12.48 MBD was flat-to-down m/m (-53 KBD m/m, +1.2 MBD y/y), Jan production was revised higher by 74 KBD to 12.54 MBD (+421 KBD m/m, +1.2 MBD y/y). GOM witnessed the largest sequential decline in February (-79 KBD) while ND witnessed the strongest gain (+77 KBD). TX was flat-to-down m/m and NM flattish.

EIA oil production projections for 2023 (12.54 MBD, +660 KBD y/y) look doable (YTD 2023 ~12.51 MBD) but, as we expressed last month, Jan’s m/m gains will be the largest for some time given the increasing difficulty of sequential comparisons and the current stasis in drilling and completions activity. Y/y production comps will remain reasonably generous over the first 6-7 months of this year and become more challenging in the latter half.

E&P reinvestment, activity and production will be governed by commodity prices and cash flow generation which has been meaningfully squeezed due to the collision of lower commodity prices and relatively unyielding well costs (moderating but less cathartically than the recalibration of commodity prices from 2022 peak levels). Notwithstanding E&P cash flow duress, reinvestment and D&C activity resilience is ongoing.

Oil

• Feb US Oil Production:  12.48 vs. 12.54 MBD for Jan (-53 KBD m/m, +1.2 MBD y/y or 10.3%).
• Feb L-48 Onshore Production: 10.20 MBD, +29 KBD m/m, +956 KBD y/y.
• TX, NM, GOM Jan Oil Production: TX (largest US oil producer, by far, with over 50% of L-48 production) Feb production of ~5.26 MBD, -25 KBD m/m and up 443 KBD y/y. NM (3^rd largest producer behind TX and GOM) production of ~1.81 MBD was flattish m/m and up 406 KBD y/y.  GOM production of 1.83 MBD was down 79 KBD m/m and up 217 KBD y/y.

Nat Gas

• Feb US Gross Nat Gas Production: 123.10 BCFD, + 0.3 BCFD m/m, +7.9 BCFD y/y (+6.8%).

• Feb L-48/GOM Gross Production: ~112.5 BCFD, flattish m/m, +7.9 BCFD y/y.

Refining Observations:  Five refiners reported this week, and most benefitted from strong margins in the quarter.  All guided to higher throughput in the current quarter, as the heaviest part of their turnarounds appears to be over.  The key question is whether this increase in volume is meeting a recession-driven lull in demand.  This week’s EIA numbers were less than dazzling on the demand front for gasoline, diesel, and jet, and their YTD demand is running flat y/y for gasoline and down 4% for both distillate and jet.  The commentary from refiners this week is that distillate has been impacted by a warm winter, with YTD demand down between 1% and 3.5% from last year.  The group is nearly universally encouraged with trends in gasoline (running above last year for everyone) and jet fuel (with the companies seeing demand up 6-8% so far this year).

Q1 Earnings Takeaways:  Abbreviated….lots of earnings so did our best….

BOOM

• Revs = $184.3M, +5% q/q
• Adjusted EBITDA = $20.1M vs. $19.6M last Q
• DynaEnergetics revs +6% q/q to $82M with flattish EBITDA margins at 18%
• The y/y improvement at Dyna more impressive with revs +68% and adjusted EBITDA +183%
• Margins negatively impacted by a $3M litigation expense.
• Cited increased unit sales for the 11^th straight quarter.
• Roughly 13% of Dyna’s revs come from International.
• Two next-gen DynaStage systems are in field trials.  These systems are designed for oriented perforating.
• Q2 guidance calls for consolidated revs = $177M to $187M with adjusted EBITDA of $23M to $26M (before NCI allocation).
• Dyna Q2 revs guided to $78-$82M.
• Full-year capex guided to $20M

DNOW

• Revs = $584M, +7% q/q
• Higher revs in all three geo-segments, but large percentage growth in international which was up 28% q/q.
• EBITDA = $47M, flat q/q.
• Q2 revs guided to grow low-single digits with EBITDA to be flat.
• Gross margins likely bleed lower in Q2 due to Canada seasonality and more competitive premium pipe market.  Canada tends to be DNOW’s highest gross margin segment.
• Full year revenue guided to improve 8-12% y/y with EBITDA margins guided to ~8%.
• Completed 4 acquisitions in the past four months – largely within Process Solutions.
• Of note, all deals carry higher margins.
• Focus on transactions is revenue synergies, not cost synergies.
• DNOW sees opportunities in RNG, particularly with its EcoVapor business.
• Noted Process Solutions is about 26% of revs today but would be good to see it grow the 1/3 of revs.
• Cash = $168M with no debt
• Repurchased $36M in stock (3M shares or roughly 3% of stock)
• 2023 capex guided to $20M.

SOI

• Revs = $82.7M, -2% q/q.
• Adjusted EBITDA = $25.1M, +9% q/q.
• Q2 EBITDA guided to flat q/q.
• Improved profitability driven by better pricing and additional top fill systems.
• Averaged 92 mobile proppant systems in Q1.
• Q2 mobile systems guided down 10-15%, some impact from gassy markets.
• Top fill system growing rapidly with over 40 working today vs. 2 in Q1’22.
• Would expect ~50 top fill systems by end of 2023.
• Roughly 25% of SOI’s sand systems use the top fill system.
• Running 5-6 blenders systems today vs. 2-3 in Q1.
• Announced new shareholder return program which provides at least 50% of FCF to shareholders.
• Repurchased 3.5% of shares in Q1 for $14M.
• Increased dividend for second time in 18 quarters.
• 2023 capex maintained at $65-$75M, of which $19M was spent in Q1.
• 2H’23 capex will moderate to $10-$15M/quarter with Q2 capex in the $20-$25M vicinity.
• Cash = $2M with borrowings on credit agreement = $26M.

RNGR

• Revs = $158M vs. $154M in Q4
• Adjusted EBITDA = $20.1M vs. $21.6M in Q4
• Adjusted EBITDA margin = 12.7%
• Announced shareholder return program which provides at least 25% of FCF to shareholders.
• Well service rig revs = $77.5M with adjusted EBITDA of $17.4M.  This compares to $72.6M and $15.2M, respectively, in Q4’22.
• Rig hours totaled 112,500 vs. 113,600 in Q4
• Rev/hour = $689 vs. $640 in Q4
• Wireline revs = $49.9M vs. $48.3M in Q4
• Wireline adjusted EBITDA = $4.2M vs. $4.7M last Q.
• Company noted pricing pressures in wireline.
• Maintained 2023 guidance which calls for revs in the range of $685M to $715M and adjusted EBTIDA in the range of $95M to $105M.
• 2023 capex budgeted at $25 – $35M.

FET

• Revs = $189M, +22% y/y
• Adjusted EBITDA = $12.5M
• New orders = $179M with book-to-bill = 0.95x.
• Q2 EBITDA guided to $16-$20M with 2023 EBITDA guided to $80M-$100M (no change).
• Drilling & Downhole Segment
  • Revs = $77M, -5% q/q.
  • Orders = $81M, -7% q/q.
  • EBITDA flat q/q
• Completions Segment
  • Revs = $74M, flat q/q.
  • Orders = $66M, -19% q/q due to large Q4 pressure control and radiator orders.
• Production Segment
  • Revs = $39M, +9% q/q
  • Adjusted EBITDA = $2M
• Cash = $47M and total debt = $153M

XPRO

• Revs = $339M, -3% q/q, but up 21% y/y
• Adjusted EBITDA = $42M, -40% q/q, but up 14% y/y
• 2023 guidance reaffirmed with revs expected to range from $1.45B to $1.55B with adjusted EBITDA of $275M to $325M.
• Captured awards of $350M this Q
• Repurchased $10M in stock in Q1; $27M remaining under authorization.
• 2023 capex = $90-$100M, of which $29M spent in Q1
• Cash = $186M with no debt
• Completed acquisition of DeltaTek Global, a cementing specialist
• Completed commissioning of its vessel-deployed light well intervention system with unit now deployed to an IOC offshore Australia.
• Also announced a contract with this system for an upcoming well decommissioning project in the APAC region
• Noted momentum with early-stage carbon capture and storage segment

PUMP:

• Revs = $424M, +21% q/q
• Adjusted EBITDA = $119M, +42% q/q
• Q1 results demonstrated nearly 50% incremental margins
• Effective utilization = 15.5 fleets vs. 14.5 fleets last Q
• Q2 effective fleet count guided to 15 to 16 fleets.
• Acknowledges spot market pricing pressure, but PUMP fleets dedicated.
• Retiring 140,000HP
• Operating six Tier 4 DGB fleets with a 7^th fleet coming in Q2
• 4 Electric fleets on order
• Cash = $45M
• LT Debt = $30M
• 2023 capex = $250M to $300M.

FANG

• Production of 425 MBOE/d (59% oil), up 8.6% sequentially (full quarter of Firebird acquisition and partial Lario contribution).
• Q2 production guided to 430-436 MBOE/d (~60% oil with full-quarter of Lario), and full-year production expectation unchanged at 430-440 MBOE/d (~60% oil).
• Capex of $657mm is 25% of unchanged full-year guidance of $2.5-$2.7B.
• 2Q capex will increase to $675-725mm, due to peak activity and well costs for the period.
• Management confident in 2H spend–$50mm run-rate reduction expected due to rig reductions, lower service costs, and efficiencies due to high-grading to two Zeus fleets with HAL and two Simul-frac fleets.
• Operated rig count peaked at 16-17 and will move to 14-15 in 2H. 
• “We believe well costs peaked over the last two quarters and have line of sight to meaningful decreases in the upcoming quarters.  Both raw materials (including steel, diesel, sand) and service costs are now decreasing.
• FANG also expects savings with the start-up of its 2^nd Simul-Frac e-fleet, replacing two zipper-frac fleets.  Simul-frac fleets save $20-30/ft, regardless of price per HHP.

CHK

• Production of 4.1 Bcfe/d (~90% natural gas), flattish with Q4.
• No change to full-year production guidance.
• Capex of ~$500mm in Q1, 32% of (as-yet) unchanged full-year guidance, but CHK is reducing activity.  It dropped 1 HV rig and 1 Marcellus frac crew in Q1.   Both of its EF rigs are being dropped this quarter, as well as 1 frac crew in the HV.  In Q3, CHK will release 1 rig HV and 1 Marcellus.
• CHK expects a 10% D&C decrease in Q2, as well as a 5% decrease in natural-gas production.
• Co expects to maintain “discipline” and “flexibility’ in capital program going forward.
• Non-op well proposals are slowing in the HV—and CHK believes that will translate into another 10 rigs come out of the HV due to lower prices in 2023.  Current activity will add to production in 2024, so further reductions would require the 2024 strip to fall.
• Returned $250mm to shareholders YTD in dividends and buybacks.
• Declared divided of $1.18/share to be paid in June.
• Thanks to EF sales, cash on hand now ~$1.2B.

MUR

• Production of 172.5 MBOE/d (55% oil, 61% liquids), flat with Q4.
• Full-year production guide of 175.5-183.5 MBOE/d.
• Production mix:  52% offshore, 32% onshore Canada, 16% EF.
• Capex of $327mm is 34% of unchanged full-year guidance of ~$950mm ($875-$1,025mm).
• MUR expects Q2 spend of $320mm.
• 2 EF refracs in Q1:  10x production increase and higher IPs than original rates.
• MUR has ID’d 220 EF wells that are good candidates for refract (initially frac’ed with <1,200 lbs/ft of proppant).
• MUR board authorized initial $300mm share repurchase program.  Co plans to direct 75% of FCF to debt reduction and 25% to repos and dividends.

CRK

• Production of 1.4 Bcfe/d (99% natural gas), down 2% sequentially.
• Full-year production guide of 1.42-1.55 Bcfe/d.
• Q1 D&C of $325mm, or 31% of unchanged full-year D&C guide.
• Completed 15 operated wells in Q1:  Avg lateral length of 11,042’ and average IP of 23 mmcfe/d.
• D&C/ft of $1,579 in Q1, vs $1,425 in Q4.
• CRK released 2 rigs in its legacy HV as previously announced.
• Q2 D&C guide of $260-310mm.
• Retaining quarterly dividend of $0.125 (~5% annualized yield).

MRO

• Production of 396 MBOE/d (47% oil), up 1.8% sequentially.
• Completed Ensign Eagle Ford asset integration ahead of schedule.
• No change to full-year production guidance.
• Capex of $601mm or 31% of unchanged full-year guide.  60% of capex is 1H weighted.
• Current budget anticipates 10-15% inflation for the entire year.
• Seeing a “general flattening or plateauing of service costs.”  Access has improved.
• MRO using better access to high-grade equipment and crews.
• Rig rates “could soften” later this year, but too “early to make the call’ on where rates go in 2H.
• Adjusted FCF of $309mm for Q1.
• Paid $63mm base dividend and bought in $334mm of stock.

CPE

• Production of 100 MBOE/d (60% oil), -6% sequentially.
• CPE acquired the membership interests of Permian-based Percussion Petroleum Operating for $475mm (contingencies of $62.5mm), made up of $265mm cash and 6.46mm CPE stock, or 2.5x NTM EV/EBITDA.
• Percussion has 18k net acres, 14 MBOE/d (70% oil), and 70 locations in the Delaware.
• Separately, CPE is selling its assets in the Eagle Ford to Ridgemar Energy Operating for $655mm in cash ($45mm of contingent payments).
• Proforma production guide of 103-106 MBOE/d (60% oil) vs 104-107 prior.
• Capex of $270mm is 27% of old guidance.
• Proforma capex guide of $960-980mm vs $1B previously.
• Current 7-rig program will be maintained through mid-year, going to 5 rigs into year end.
• As a result, CPE’s board authorized a $300mm share buyback program for next two years, subject to the deals closing.

SBOW

• Production of 304 Mmcfe/d (~20% oil), down 3.6% sequentially.
• Full-year guide of 325-345 Mmcfe/d (40% liquids).
• Capex of $108mm, or 23% of unchanged full-year guidance of $450-475mm.
• 2Q capex expected at $110-115mm.
• 2 oil-focused rig development program continues.
• 50% of 2023 capital focused in Central Oil and Western Condensate areas (81% and 64% liquids, respectively).
• D&C costs down 10% YTD.  Expect further cost relief on dayrates and steel through 2023.
• Frac costs (HHP, sand, and chemicals) down 18% YTD.  Stages per day up 25% from 2022 average.

CIVI

• Production of 159 MBOE/d (45% oil), down 6% sequentially.
• Full-year guide of 160-170 MBOE/d (45% oil, ~70% liquids).
• Capex of $236mm, or 30% of full-year D&C guide of $725-825mm.
• Total capex guide of $800-$910mm.
• Program anticipates 2 rigs/2 crews drilling 100-110 gross Hz wells an completing 120-130, with 140-150 brought online.  Average WI of 83% and lateral length of 2.5 miles.
• Drilling program is fully permitted; plan to run about 18 months ahead of rigs for permits.
• Could flex activity up depending on service costs.
• FCF of $186mm.
• $300mm of stock repurchased in Q1 ($1B authorization).

APA

• Adjusted production of 318 MBOE/d (48% oil), down 5% sequentially.
• Full-year adjusted production guided to 330-334 (~48% oil).
• Capex of $495mm, or 25% of lowered full-year guidance of $1.9-$2B.  $2.05B at midpoint previously.  Reduction reflects lower gas-directed activity in Permian.
• Maintaining 5-rig program.
• Any renegotiation of service costs unlikely to move needle much in 2023.  Would show up in 2024 due to contract mix.
• 81% of FCF returned to shareholders–$142mm of stock repo and $74mm of bond buyback.
• Maintaining 5 rig L48 program—3 Delaware Basin (no new wells POP in Q1) and 2 S. Midland Basin.

MGY

• Production of 79.3 MBOE/d (46% oil), up 7.5% sequentially.
• Full-year production now expected to grow 5-7%, vs +10% guidance in Q4.
• D&C capital of $140mm, 31% of newly-lowered guidance of $440-460mm (from $490-520mm prior).  The reduction will be achieved through lower oil-services and materials costs and a modest reduction in activity.
• MGY is maintaining its 2-rig program, it intends to defer some completions.
• 2Q D&C now expected at $100mm, and MGY expects to spend about $100mm/quarter going forward.
• Management believes pricing needs to come down another 15+% or so to be aligned with current commodity prices.
• Q1 FCF of $61mm.
• Repurchased 2.4mm shares in Q1, leaving 6.5mm shares remaining on current repurchase authorization.
• Dividend of $0.115/share (~2.3% annualized yield).

PDCE

• Production of 244 MBOE/d (32% oil), down 1% from Q4.
• Reaffirm production guide of 255-265 MBOE/d (~32% oil).
• Capex of $415mm, or 30% of lowered full-year guide ($1.35-$1.45B, vs $1.35-$1.5B prior).  Spend will be lower due to cost savings from steel, sand, and fuel.
• Q2 capex of $325-400mm.
• Q1 activity ran 4 rigs/3 crews:  3 rigs/2 crews Wattenberg, 1 rig/1 crew Delaware.  Called out as most operationally-intense quarter of the year.
• In Wattenberg, began using an e-fleet this week and swapped out a conventional rig for an e-rig in March.
• Adjusted FCF of $100mm.
• Repurchased 2.1mm shares.  Authorization bumped to $2B.

CHRD

• Production of 165 MBOE/d (58% oil), down ~4% sequentially.
• Full-year guide of 164-168.5 MMBOE/d (58% oil).
• Capex of 202.3 is 24% of unchanged full-year guide.
• 2023 activity schedule unchanged, with completions concentrated in May, June and throughout Q3.
• Q2 spend of $235-265mm expected.
• On inflation: Could see steel come down in 2H.  Otherwise some areas up, some down, but in aggregate unchanged.
• 2023 TIL estimate of 90-94, 73% WI.  50% of those 3 mi laterals.
• FCF of $199mm.
• $1.25/share base quarterly dividend (3.7% annualized yield), $15mm share repo, and $1.97/share variable dividend.

DEN

• Production 48 MBOE/d, up 2.2% from Q4.
• 2023E sales volumes of 46-49 MBOE/d.
• Q1 Capex of $111mm, 22% of $510mm of 2023 anticipated capital.
• Oil and Gas Q1 capital of $100mm, Full-year of $350-370mm.
• FCF of $18mm.

COP

• Production of 1.79 MMBOE/d (56% oil), up nearly 2% sequentially.
• Full-year production guidance now at 1.78-1.8 MMBOE/d (low end raised from 1.76 in Q4).
• Lower 48 production of 1.03 MMBOE/d (54% oil), up 4% from Q4.
• Capex of $2.9B, or 26% of unchanged full-year guidance.
• Lower 48 capex of $1.7B up 13% from Q4.
• FCF of $2.8B in Q1.
• Repurchased $1.7B of stock, paid dividends (fixed and variable) of $1.5B.

ESTE

• Production of 104.5 MBOE/d (44% oil), flat sequentially.
• 2023 production guide unchanged at 96-104 MMBOE/d (44% oil).
• Capex of $202.3, 27% of unchanged full-year capex of $725-775mm.
• Cautiously optimistic that service-cost inflation starting to abate.  May see some Q2, but most likely 2H.
• ESTE is running 3 rigs in the Delaware, 2 in the Midland Basin.
• Expects to spud 45 gross op wells in the Delaware and 37 in the Midland Basin.
• FCF of $41.8mm in Q1.

EOG

• Production of 943 MBOE/d (49% oil), up 3.7% from Q4.
• Full-year guidance unchanged at 944-10278 MBOE/d (50% oil).
• Q2 Production guided to 939.5-974.7 MBOE/d.
• Capex of $1,489mm, 25% of unchanged full-year capex.
• Evaluating options to delay some activity at Dorado, due to near-term price weakness.
• Plan was to add eight wells this year.  May delay completions.
• On inflation: “The upward inflationary pressure we witnessed last year appears to have plateaued….Early indicators are showing signs of service-cost moderation, which is more prevalent in some basins and less in others.  We would expect that any softening of service and tubular cost will be slow to manifest into lower well costs and cash operating costs until much later in the year or more likely in 2024.”
• Q2 capex guided to $1.55-$1.75B.
• FCF of $1.1B.
• Returned $1.4B to shareholders:  $0.3B repo, $1.1B in dividends (regular dividend $0.825/shr, or ~3% yield).
• Retired $1.25B of debt.

CTRA

• Production of 635 MBOE/d (72% natural gas), flat sequentially.
• 2023 production guidance is unchanged at 610-650 MMBOE/d, with oil volumes up 1 MBOE/d from previous guide.
• Capex of $569mm, 27% of full-year guidance.
• Full-year capex, although unchanged in aggregate, will be $10mm lower in the Marcellus, offset by additions in the Anadarko and the Permian.
• Reducing activity in the Marcellus:  2 rigs/1 crews in 2H (down 1 rig and 1 crew).  Anadarko at 1-2 rigs and Permian remains at 6 rigs.
• FCF of $556mm.
• Share repo of $268mm, dividends of $152mm (regular dividend of $0.20/share, or 3.3% annualized yield).

NOG

• Production of 87.4 MBOE/d up 11% sequentially.
• Full-year guidance of 91-96 MBOE/d (63% oil).
• Capex of $212mm, 28% of unchanged full-year guidance of $737-778mm.
• Capex will be 1H weighted, with 60% of spend during Q1 and Q2.
• Adjusted EBITDA of $325.5mm.
• FCF of $84mm.
• Q2 dividend of $0.37/share, up 9% from Q1.  Annual yield of 4.8%.

MPC

• Throughput of 2.8 MMB/d (89% utilization).
• Q2 guidance of 2.9 MMB/d (91% utilization), with turnaround costs of ~$400mm (1/2 MidCon, $150 West Coast, $45mm Gulf Coast).
• R&M margin was $26.15/Bbl Q1.
• 98% margin capture in Q1, despite headwinds from planned maintenance in Gulf Coast.
• Margin/Bbl by region:  GC $25.94, MC $26.78, WC $25.16.
• Refining cash opex of $5.68/Bbl.
• Adjusted EBITDA of $5.2B.
• Capex of $690mm in Q1.
• Returned $3.5B to shareholders, $337 dividends and $3.2B repo.
• Initiated additional $5B share repurchase authorization.
• Martinez Renewables achieved Phase I production capacity of 260mm gallons/year, and has now entered Phase II, expected to achieve 730 mm gallons/year by the end of this year.
• On demand in Q1: “we really look comprehensively at our entire book of business…including our wholesale…our direct dealer, our branded jobber, our national account…So on the gasoline front, our book of business…was up 4.7% [vs. EIA at +1.7%].  On the distillate side, we were off about 1.2% [EIA -7%].”  MRO believes distillate demand heavily impacted by warm winter lowering heating-oil use.  “And then on the jet fuel side…we saw a 6% rise in demand in the quarter, which comps to about 5% from the EIA perspective.”

CVI

• Throughput of 196 MB/d (95% utilization), down 11% from Q4 due to Coffeyville coker turnaround.
• Refining margin/Bbl of $23.24, up 36% sequentially.
• RFS compliance costs were $95mm for the quarter, or $5.36/Bbl, excluding RINs revaluation benefit of $56mm or $3.17/Bbl.
• Refining EBITDA  $285mm (up ~40% from Q4); Nitrogen Fertilizer EBITDA largely flat at $124mm.
• Total adjusted EBITDA of $334mm.
• Q2 guidance of 95-100% utilization (195-210 MB/d) for Petroleum segment and similar utilization for Nitrogen Fertilizer business.
• Fertilizer revenue in Q1 up ~7% sequentially to $226mm, with utilization of 105%.
• Q1 capex of $59mm.  Q2 guide of $63-92mm.
• CVI declared a $0.50/share dividend for Q1 (an 8% yield).

PSX

• Refining throughput of 1,178 MB/d (90% utilization), down 3% sequentially.
• Refining margin of $20.72 (93% market capture), up 5% from Q4 and nearly double last year.
• By region:  Atlantic Basin $16.13 (82% capture), GC $21.28 (107%), Central Corridor $26.86 (116%), West Coast $16.53 (56%).
• Chems utilization 94%.
• Q2 outlook of refining utilization of mid-90%’s, with $100-120mm of turnarounds.  Olefins and Polyolefins utilization of mid 90%’s.
• Capex of $378mm in Q1.
• Shareholder distributions of ~$1.3B.
• On demand: “our volumes are somewhat off because of California flooding and because of some maintenance.  But generally for US gasoline, we’re seeing demand better than last year, and we’re seeing global demand about 3% better than last year….On the diesel side, the year did start off weaker early in the year with a warmer winter, that has begun to firm with a mid-continent planting season.  Currently we’re seeing US diesel demand about 3.5% under last year.  But that said, global distillate demand is a bit stronger than last year.”

PBF

• Throughput of 851 MB/d (87% utilization), down 9.4% from Q4.
• Q2 guided to 900-960 MB/d (95% utilization at midpoint).
• Guide by region (MB/d: East Coast 260-280, MidCon 150-160, Gulf Coast 180-190, and West Coast 310-330.
• PBF has planned “extensive” maintenance for 2023.  East Coast: Delaware coker and hydrocracker (Spring), West Coast: Torrance hydrocracker (Spring) and Torrance FCC/Alkylation Unit (Fall).
• Gross refining margin of $18.35/Bbl systemwide, down 7% from Q4. Gulf Coast and West Coast saw sequential improvements.
• Adjusted EBITDA of $665mm, down 36% from Q4, but more than double y/y.
• Increased share-repurchase authorization to $1B.
• On demand: Recovery in US gasoline and jet demand a “key theme” for 2023.  Expect gasoline and jet to pick up in California, and distillate likely to be helped by renewable-diesel conversions. In PADD I, rack demand remains very strong.  Wholesale business in East Coast up 10% YTD, and current run rate is up 15% from Q1.

DINO

• Throughput of 498.5 MB/d, down 25% from Q4 due to turnarounds at Puget Sound, El Dorado, and Woods Cross refineries during the quarter.
• MidCon throughput of 211 MB/d (81% utilization); West Region throughput 287 MB/d (69% utilization).
• 2Q guidance of 550-580 MB/d (~80% utilization), due to planned turnarounds.
• Consolidated refining gross margin of $23.70/Bbl, up from $12.69 y/y.
• Midcon refining margin of $20.34/Bbl; West Region $25.92/Bbl.
• Segment adjusted EBITDA  of Refining $544mm, Lubricants & Specialty Products $98.5mm, Market $6.4mm, and Renewables of $3mm.
• Acquiring 100% of HEP units outstanding to simplify corporate structure.
• On demand: “First quarter vs. last year our gasoline demand we believe is above 102% of what we saw last year.  Diesel was about 101% of demand in our areas.  The surprise was jet demand was 8% higher in the first quarter vs. last year.”

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

832-247-8215

jd@danielep.com

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