Baker Hughes U.S. onshore rig count was down 18 last week to 707 rigs.
FT- Oneok to buy Magellan Midstream in $19bn US pipeline deal – Link
WSJ-Turkey’s Election: What Does it Mean for Oil Prices? Link
WSJ- Rusty Old Oil Tankers Fetch Big Bucks Link
DEP Update & Future Trips: Happy Mother’s Day to all the mom’s out there. Relatively quiet at DEP this coming week. Geoff Jay will be in Houston, updating with E&P companies. Sean and Bob will be traveling with clients while Bill Austin will be knee-deep with Permian BBQ Cook-Off stuff. Your weekly weekend email spammer will be in North Carolina/Virginia, gathering the chitlin’s from college and then driving their car back home to Texas. With an expected 19 hours on the highway, I will be reaching out to all of DEP’s E&P friends as we are preparing our mid-year activity forecast update. We hope to update/publish our new rig count forecast next Sunday and it’s helpful when we can hear your perspectives. So, E&P friends, please take our call.
E&P Observations: E&P earnings are now in the rear-view mirror, and this week mostly reiterated last week’s themes: Unchanged (for now) budgets, a sense that rig and frac costs are plateauing, and rig counts moving lower (post deals for some, previously planned reductions for others). One company said it was notable that Q1 was the first quarter with no price increases for frac vs a string of six quarters of increases in a row. Spending and capex guides for the group are outlined in the table below.
Refracs were a topic of conversation again this week, with DVN highlighting its program in the Eagle Ford. So far, they have 30 online and have seen uplifts in production rates and EURs. Recall that MUR discussed its success with refracs last week, resulting in higher IPs than when the wells were originally brought online.
In A&D news, VTLE is acquiring the assets of Forge Energy II (an EnCap portfolio company) in the Permian Basin for $378mm, all cash. VTLE believes the deal value is 2.5x NTM EV/EBITDA and expects it to close in Q2. Forge adds ~24K net acres in Pecos, Reeves, and Ward counties and has current production of ~9.5 MBOE/d (65% oil). Management estimates that there are about 100 gross locations that are breakeven at $50 WTI. One of Forge’s two rigs will be dropped (a theme with recent E&P M&A).
BKR U.S. Land Rig Count. Another down week as BKR reported an 18-rig decline w/w to 707 rigs which means we are now down 57 rigs or 7.5% from the Q4’22 peak. About three weeks ago, we highlighted near-term rig activity guidance from the first week of Q1 earnings and included a quick survey from a basket of private drillers. Public company guidance coupled with our survey essentially showed a potential 25 rig count decline. Extrapolating that survey across the entire universe of land drillers implied a ~30-35 rig count decline. Since that note, the industry has shed 25 rigs, per BKR. Given cloudy near-term visibility, it would seem a bit more degradation will be forthcoming. Example, this week High Peak Energy (HPK) announced it would drop two rigs, moving from 4 rigs to 2 rigs while in the Vital Energy announcement of its purchase of Forge Energy, the company announced it would release one of the Forge rigs. Prospects for more E&P consolidation is not bullish for near-term D&C activity. However, one must see the forest through the trees. In this case, HPK also noted it would pick up two rigs in early 2024. This comment echoes our missive last week in which we prophesied some of the activity reductions are budget-related and will therefore reverse in 2024 under new budgets. Multiple E&P companies have shared with us that this is their plan. Moreover, we continue to believe there will be a handful of new E&P players who will access capital to buy acreage and that will yield incremental drilling. Big numbers? Probably not, but small additions, coupled with budget resets and looming demand to support LNG exports, give us hope that today’s lull will be next year’s ramp.
Refining Observations: EIA weekly inventory data was very encouraging this week: Commercial crude inventories built by ~3mm, but the SPR released ~3mm, so on a net basis, it was a push. Product inventories drew by more than 7mm Bbls, and implied demand was strong across gasoline, distillate, and jet fuel. The sole refiner reporting this week also highlighted seeing strong current demand. QTD, gasoline and jet demand are up more than 1% from QTD last year, while distillate demand is running more than 3% below the year-ago period.
There were news reports that Lyondell asked a private-equity firm to resubmit a bid for its 268,000 Houston refinery; however, the company later denied that it was seeking additional bids and reiterated its plans to close the facility at year end and potentially convert the plant to manufacture recycled plastics or potentially hydrogen.
Most Interesting Quote in Q1 Earnings: We were intrigued by the following comment made by ACDC’s management team. “…whenever we look at our float here, our inventory is higher than our float. Our capex is higher than our float. Our ABL is higher than our float. Our quarterly EBITDA is higher than our float. I honestly don’t understand why any energy company out there would want to be a public company.” We like management’s candor and would be willing to bet there are a bunch of SMID-cap OFS execs who share this view. Here’s why we suspect ACDC is frustrated and importantly, this is not investment advice. First, ACDC, like its peers, has consummated a number of strategic acquisitions recently. The company has made investments in equipment upgrades and is building out its E-Fleet presence. The company is addressing oversupply fears via its Acquire, Retire, Replace strategy as well as idling fleets vs. lower prices. Meanwhile, street estimates still point to continued y/y improvement with street ’23 EBITDA estimates at nearly $1.5B vs. ’22 EBITDA of $1.3B (not saying consensus is correct, but we’ll assume it’s in the ballpark and we pulled these from FactSet). Yet, with all of this, ACDC stock is down nearly 60% from its 52-week high. This, however, isn’t an isolated example. Numerous OFS companies are making fundamental improvements/changes to their business, and no one seems to care. Many OFS names are down anywhere from 30-50% from recent highs. We wish we had a magic wand which could make investors care and pay attention, but the reality is weak nat gas prices, a rig-count which is rolling and fears of recession make energy a bit less attractive to most investors. Uncertainty is never bullish. Therefore, DEP operational advice to companies is to fight-the-good-fight by watching capex spend, keep returning money to shareholders or reducing debt and in our humble view, run the business as if it’s your own money. That is, take advantage of market disconnects and be disciplined with cash. If the talking heads are correct and LNG saves nat gas prices next year and/or if the supply/demand picture for oil firms up, then today’s frustrations, hopefully, are alleviated this time next year. A cold winter would also be nice. And, if all of this plays out, then activity moves up, returns should quickly follow and momentum theoretically comes back to energy.
- Production of 153.8 MBOE/d (51% oil, 71% liquids), -2.8% sequentially. Expected to be lowest volume quarter for the year.
- Capex of $360mm, 27% of full-year guidance of $1.25-$1.45B.
- Plan still anticipates move from 7 rigs to 6 in 2H.
- No material cuts on rig pricing yet but feels like “market moving in our favor”. Frac revisited quarterly. No increases this quarter vs six quarters in a row of price increases.
- FCF of $101mm.
- Repurchased 2.75mm shares for $29.4mm.
- Base dividend of $28mm, or $0.05/share (~2% annualized yield) plus inaugural variable dividend of $0.05/share.
- Production of 641 MBOE/d (50% oil), up 0.8% sequentially.
- Q2 guidance of 643-664 MBOE/d (~49% oil).
- Full-year guidance 643-663 MBOE/d (50% oil).
- Upstream capex of $933mm, 27% of unchanged full-year guidance.
- Seeing some softening in pricing.
- Highlighted success of EF refracs (30 online, several hundred candidates ID’d). Refracs increased per-well reserves by 50%.
- Plan to complete 10 refracs in 2023.
- FCF of $665mm.
- Repurchased $692mm of shares YTD.
- Share buyback authorization expanded by 50% to $3B (~9% of current market cap).
- Base dividend of $0.20/share (1.6% annualized yield).
- Variable dividend of $0.52/share for Q1.
- Production of 49 MBOE/d (~73% oil), up 10% from Q4.
- D&C capex of $146.5mm, down from $157.1mm in Q4.
- Adjusted EBITDAX of ~$188mm.
- Declared cash dividend of $0.075/share, <1% annualized yield.
- No call or guide given pending BTE.CN merger.
- Production of 80 MBOE/d (49% oil), up 3.2% sequentially.
- Q2 production guide of 85.5-88.5 MBOE/d (47% oil).
- Full-year production guidance of 76-80 MBOE/d (~50% oil).
- Capex of $188mm, lower than expected due to deferral of facilities investments in Q2, moderating inflationary pressures, and weather impacts on completion activity.
- Spend to date is 27% of unchanged 2023 capex guide of $625-675mm.
- VTLE completed 21 wells with 18 TIL in Q1.
- Production of 511 MBOE/d (25% oil, ~50% liquids), down 2.3% from Q4.
- Full-year guide now affirmed at 520-545 MBOE/d (36% oil).
- Capex of $610mm is 22% of post-deal capex guide of $2.6-$2.9B.
- Rigs go from 10 in Permian to five by Q4 as announced with Permian acquisition of Black Swan, PetroLegacy, and Piedra Resources assets.
- Running 2 rigs in Uintah Basin.
- Increased base dividend by 20% to $0.30/quarter (~3.4% yield).
- Production of 1.2 MMBOE/d (54% oil), down <1% sequentially.
- Q2 Production expected at 1.16-1.2 MMBOE/d ( 52% oil).
- 2023 production guide of 1.17-1.22 MMBOE/d (~53% oil):
- 565-589 in Permian
- 243-253 Rockies
- 141-147 GoM
- Intl 221-231
- Capex of $1.5B, full-year budget of $5.4-$6.2B
- E&P capex $1.26B, 28% of unchanged 2023 spend of $4.3-$4.7B.
- L48 activity: 24 gross rigs in Permian Q1 going to 23, 3 gross rigs Rockies.
- Chems EBIT of $472mm, guided to $415mm Q2.
- Midstream EBIT of $36mm. guided to loss of $50mm Q2.
- $1.7B FCF.
- $750mm share repurchase.
- Production of 37.2 MBOE/d (85% oil), flat sequentially.
- Full-year production expected to average 45-51 MBOE/d (exit of 55-61 MBOE/d).
- 2024 expected at 60-66 MBOE/d (exit of 68-76 MBOE/d).
- D,C,E&F capex of $379.1mm in Q1, with 5-rig program drilling 25 gross and completing 32 gross Hz wells.
- Full-year D,C,E&F capital expected at $900-975 in 2023, $850-900mm in 2024.
- Revised development outlook for 2023: Reducing rig count from 4 to 2 from June through year end. Frac crews will also shrink from 4 to 2 for the period, completing DUCs from its previous 6-rig program.
- HPK expects to return to a 4-rig program (with 2 crews) in early 2024.
- Dividend of $0.025/share (~1% yield).
- Throughput of 269 MB/d (82% utilization), down 4% sequentially.
- Q2 guide of 290-300 MB/d of crude throughput (~90% utilization).
- No major turnarounds scheduled until Q4 of 2024.
- Systemwide refining gross margin of $16.44/Bbl.
- Tyler TX $21.65/Bbl, El Dorado AR $13.38, Big Spring TX $18.33, Krotz Springs LA $15.47
- Adjusted EBITDA $285mm, up 29% from Q4. Up more than 3x y/y.
- Refining EBITDA $230mm (+26% from Q4), Logistics $91mm (flat), Retail $6.4mm (-18%).
- Capex of $192mm. 2023E of $350 ($202 Refining, $81mm Logistics, $31mm Retail, $36mm Corp.)
- Retail locations saw fuel volumes fall 1.7% y/y on a same-store basis.
- We accidentally missed this one last week.
- Revs = $417M, +9% q/q
- Adjusted EBITDA = $67M, +29% q/q
- Repurchased $8M in stock in March and another $25M in April, roughly 4% of the stock.
- Nice business development wins as WTTR highlighted new agreements with total project costs of $32M. These projects are in the Haynesville, DJ, Mid-Con and South Texas. Our impression is these are accretive projects to WTTR all with volume contracts supporting them.
- Water Services
- Q1 revs = $229M with gross margins = 20.5%. Q2 guided to flat revs with margins up 100-200bp.
- Water Infrastructure
- Q1 revs = $102M with gross margins = 28.5%. Q2 revs guided steady with margins to improve 200-300bp.
- Q1 revs were up 32% q/q driven by contributions from the Breakwater and Cypress acquisitions.
- Oilfield Chemicals
- Q1 revs = $86M with gross margins = 19.4%. Q2 revs guided to improve mid-single digits with flat margins.
- WTTR working through ERP issues which resulted in a working capital build. Company contends this should be resolved and 2H’23 cash conversion should allow WTTR to pay off its $75M revolver draw.
- Revs = $852M, +7% q/q
- Adjusted EBITDA = $255M
- Adjusted EBITDA margin = 30%
- ACDC noted $20M of transitory expenses that are not included in Adjusted EBITDA
- Averaged 40.7 fleets in Q1.
- No commentary on fleet count today.
- Delivered 1st electric fleet under a dedicated agreement.
- A 2nd fleet is forthcoming with a total of four fleets expected to be built in 2023.
- Retired 150,000hp (not new news)
- ACDC is now the largest in-basin sand player with 23M tons of name plate capacity.
- Q2 revs guided to improve; no guidance on Q2 EBITDA, but should move higher as Q1 incorporated nearly $20M of non-recurring expenses.
- 2023 capex likely to be below $350M but will improve in Q2/Q3 vs. Q1’s spend of $83M.
- Alluded to returning cash to shareholders with a focus also on debt reduction.
- Revs = $82.4M vs. $73.8M, +12% q/q.
- Rev improvements a function of higher average selling price and contract shortfall revs.
- Adjusted EBITDA = $8.4M vs. $10.7M.
- Tons sold = 1.2M vs. 1.18M in Q4
- Q2 volumes guided to 1.0M to 1.2M.
- Contribution margin = $14.89/ton vs. $14.77/ton in Q4
- Q2 contribution margin guided to mid-teen’s.
- SND alluded to some April weather / customer issues in Bakken, but May rebounding
- Although Bakken demand remains strong, Marcellus showing a little bit of moderation.
- To date, SND has not seen frac sand pricing pressures.
- The Blair facility will come on line this quarter, allowing SND access to the Canadian market.
- All else being equal and assuming SND can develop relationships with Canadian end-users, the Blair facility could lead to a step-change increase in EBITDA during 2024.
- 2023 capex guided to $20-$25M.
- Revs = $63.8M vs. $60.3M, +6% q/q.
- Adjusted EBITDA = $21.4M vs. $18.5M, +16% q/q.
- Margin/day = $15,665 – guided essentially flat for Q2
- Averaged 19.4 rigs in Q1 – guided to 17.9 rigs in Q2.
- Q1 revenue days = 1,744 with Q2 revenue days guided to 1,632.
- Had 10 rigs in the Haynesville.
- Relocated 2 rigs to the Permian with 3 more to follow.
- Q2 results will be burdened with $2M of rig move costs vs. $600k in Q1.
- Noted an expectation to be back to 21 rigs working by YE’23.
- Inquiries exist for high-spec rigs.
- Not necessarily calling for U.S. rig count to rise as legacy rigs being displaced.
- Capex will move lower as rig upgrades on pause.
- Focus will be FCF towards debt reduction.
- Cash = $7M with total debt = $165M.
- Revs = $163M vs. $167M last Q
- Adjusted EBITDA = $25M vs. $30M last Q
- Q2 revs guided to $158M to $166M.
- Q2 adjusted EBITDA likely to be down slightly.
- Commentary on cement remains encouraging as does prospect for international tool sales.
- NINE noted market challenges in the Haynesville near-term.
- Commentary, as always, was direct and candid.
- Full year capex likely at the low end of the $25M-$35M guidance.
- FCF will be used for debt reduction.
- Cash = $21M with total debt at $332M.
- Business unit anecdotes
- Cementing: Revs = $63M, -4% q/q. Jobs = 1,029, -3% q/q. Rev/Job = -1% q/q.
- CT: Revs = $34M, -7% q/q. Utilization = 64%. Blended dayrate = -17% q/q.
- Wireline: Revs = $30M, -2% q/q. 5,455 stages completed, -7% q/q. Rev/stage = +5% q/q
- Completion Tools: Revs = $38M, +7% q/q. Stages -1% q/q to 32,219.
- Revs = $240M, +7% q/q
- Adjusted EBITDA = $38.2M, +2% q/q
- Adjusted EBITDA margins = 15.9%
- This represents a record quarter for KLXE
- Cash at 4/30 = $61M.
- Total Debt at 3/31 = $319M (includes finance leases)
- Noted March was a record month with annualized revs = $1B.
- Optimistic 2H results improve relative to 1H.
- Only 10% of revs come from the Haynesville.
- Noted some revenue synergies identified in the Greene’s deal. Not quantified but characterized as minimal. Still, good given no revenue synergies were part of the guidance.
- Q2 revs = $240-$250M
- Q2 adjusted EBITDA margin = 16% to 17%
- 2023 revs = $975M to $1.04 Billion
- 2023 Adjusted EBITDA margin = 17% to 19%
- 2023 Capex = $60M to $70M
- Revs = $43.6M, +8% q/q and +11% y/y
- Adjusted EBITDA = $4.9M.
- Adjusted EBITDA margin = 11.2%
- Cash = $13.6M with total debt = $8.4M
- Canada Revs = $30.7M, +24% q/q – Q2 guided to decline q/q
- U.S. Revs = $11.3M, -16% q/q – Q2 guided to increase q/q
- International Revs = $1.6M, -19% q/q – Q2 guided to increase q/q
- Q1 EBITDA $38M + 6% q/q
- Higher volumes and skim oil outperformance drove the q/q results
- Produced water volumes grew 3% q/q to 971k bbls/d
- Water recycling grew 11% q/q to 405k bbls/d
- ARIS see’s sustained levels of completion activity from their customers
- Continued progress on reuse pilot project with Chevron, ConocoPhillips and Exxon
- Aris selected as one of four finalists in the Water Reuse Project of the Year at the Global Water Intelligence 2023 Global Water Awards in Berlin
- Guide- 2Q23 EBITDA of $35-37M and Capex at $55-65M
- Full year capex $140-155M, which is first half weighted
- Expect 2Q produced water volumes to avg approximately 1mm bbls/d
- Water recycling volumes expected to be 365-375k bbls/d for 2Q
- Skim oil recoveries should normalize back to .10% of inlet produced water handling volumes
- Consolidated revs = $493M vs. $295M in Q1’22, +67% y/y.
- Consolidated EBITDA = $84M vs. $23M in Q1’22, +268% y/y
- CFW no longer breaks out Canada vs. U.S. results; all lumped together in NAM results.
- NAM Q1 revs improved 72% y/y to $413M with Adjusted EBITDA = $76M or 18.5% margins.
- NAM has 1.017M active frac horsepower or 15 fleets (we think 10 U.S., 5 Canada).
- Additionally, 6 CT units, all of which we believe are in Canada.
- Tier 4 DBG upgrade program underway.
- 9 units in the field soon with a total of 50 to be deployed by Q1’24.
- Cash = $23M with total debt = $339M.
- The company plans to reduce debt by $80M in 2023.
- Q1 capex = $35M with 2023 CapEx budgeted at $155M.
- Consolidated revs = $263M, +20% y/y
- Canada revs = $174M vs. $147M last year, +19% y/y
- U.S. revs = $89M vs. $73M last year, +22% y/y
- Consolidated EBITDA = $45M vs. $37M in Q1’22.
- Running 15 fleets today with 3 in the U.S. and 12 in Canada.
- 9 active CT units in Canada and 12 active CT units in the U.S.
- The U.S frac fleet has 50k hp which is dual-fuel while another 80k hp is Tier 4
- STEP now has 8 Tier dual-fuel units deployed with more to come.
- Noted some U.S. frac price choppiness in Q1 but characterizes prices as stable now. U.S. CT pricing characterized as stable.
- Cash = $1M with net debt = $133M.
- Net debt reduced by $9.4M since YE’22 and by nearly $180M since 2018.
- Revs = $484M, +46% y/y
- Adjusted EBITDA = $127M, +82% y/y
- Adjusted EBITDA margin = 26.2%
- Our comments focused on NAM operations.
- Running 55-60 drilling rigs in the U.S.
- Canada rig count did hit expectation in Q1 as ESI contends lower pricing by peers yield some market share erosion. Lost 8-10 bids on price. Had hoped to hit 65 rigs. Noted Q2 is looking much stronger and called out two high-spec rigs just signed contracts in the mid-$30s.
- Cited growing interest by customers for its EDGE emissions reduction offering.
- Revenue days
- Canada: 3,800 days, +2% y/y on 114 marketed rigs
- U.S.: 4,617 days, +25% y/y on 86 marketed rigs.
- Well Service Rig Hours
- Canada = 13,776, +22% y/y – should get to 18 rigs post break-up
- U.S. = 27,917, -6% y/y – mgmt noted business back to 85% utilization with no rate degradation. U.S. fleet remains at 47 rigs.
- Cash = $45M with total debt = $1.4B in debt
- Q1 capex = $50M with the 2023 budget set at $157M
- ESI.T intends to repay $200M in debt this year and a total of $600M over the next three years.
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
John M. Daniel
Managing Partner, Founder
Daniel Energy Partners, LLC
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