DEP Update. Our golf outing is this Wednesday. We have a few open slots, so let us know if you want to play. On Friday we’ll be in Dallas and then returning again next week before heading up to OKC for meetings/group dinner on 11/17. Let us know if you are around.
E&P Anecdote: Don’t want to make a mountain out of a mole hill, but we thought the following observation from an E&P contact was interesting. The company is a small player who had planned on completing a basket of wells in Q4. Company was subsequently notified by its frac provider that only a portion of the wells would be completed as the frac company was taking its fleet to work for a larger E&P who could offer more dedicated work. Our E&P contact gets shafted and is forced to call around to secure a crew. During its inquiries, the E&P company uncovers that four frac companies are purportedly confirmed to work for the same (albeit another) E&P player in Q1. In other words, this other E&P has allegedly booked four frac fleets for one fleet’s worth of work (i.e., quadruple booking). Perhaps it is doing so to ensure access to a frac fleet, but in doing so, it gives multiple frac companies an impression they will be busier than some might actually be. Yes, this is a one-off, but as access to equipment tightens and as service companies flex atrophied pricing muscles, we wonder if other E&P players may embark on a similar strategy and if so, how many?
Well Service Consolidation Continues: Axis Energy Services announced it has acquired the well service assets from Superior Energy Services. No transaction price was disclosed, but we believe Superior owned ~200 well service rigs, of which ~40 rigs are working and another ~40 rigs are marketable. Our understanding is Axis will likely cut up over 100 rigs associated with this purchase. The divestiture by Superior is not a surprise. We addressed this multiple times in prior notes. News of the actual buyer is, however. Thankfully, the assets fall into the hands of an existing rig provider thereby allowing further industry consolidation. Now, the next deal on the horizon is the Pioneer Well Service rig assets. PTEN presently owns this equipment but has stated a desire to sell the assets. One would hope/assume the assets will find a home with a strategic buyer as well.
NINE/USWS: More evidence of reduced emission completion work as USWS and NINE announced jointly the completion of a two-pad, nine-well project which utilized an electric fleet from USWS and a NINE electric wireline unit. According to USWS, a total of 589 stages were fracked with an estimated reduction in CO2 equivalent by 25% (vs. traditional diesel), an 86% reduction in NO2, a 94% reduction in particulate matter while displacing an estimated 1.5M gallons of diesel. NINE noted the successful use of turbine power and no diesel usage for 46 days as it completed 356 stages. The E&P customer was Northeast Natural Energy.
GR Energy Services: In keeping with the spirit of electric wireline units, we noticed a GR Energy Services LinkedIn post which announced the deployment of its first fully electric wireline truck. This new unit is called e3 (electric, environment, efficient) and was deployed to the Permian Basin.
New OFS Product/Solution: We took a break from earnings season to do an equipment tour as one emerging company, Velox Oilfield Services, has developed a new trailer design to transport and store concentrated chemicals on location. The unit, which is electric, pumps concentrated chemicals, thereby reducing the number of trucks which are normally required to deliver diluted chemicals to location. One of the other advertised benefits is the ability to reduce the number of vacuum trucks required to haul excessive flow back water as the amount of water is reduced due to the concentrated nature of the chemicals. This is a relatively new design as Velox has only operated one unit thus far as it refines the design process, but early results, according to the company, are positive. The unit is being designed to operate unmanned, but the company intends to have service techs cover multiple units within a defined geographic scope. Velox believes its trailer design assists E&P customers with reduced emissions due to potentially less truck traffic; reduced transportation costs due to less truck traffic and potentially less labor given the system is automated and capable of being operated remotely.
Frac Attrition. Lots of frac companies called out equipment attrition again this quarter, citing it as an industry challenge and a key reason why pricing needs to go higher. Sadly, few actually give any details about their own attrition challenges with most arguing they don’t want to disclose due to competitive reasons. Unfortunately, for outside observers the consequence is we see lots of theoretical horsepower on the sidelines, thus giving customers/investors reason to believe the market isn’t as tight as it really is. Of course, the DEP team goes to the field frequently enough to know the sad state of frac affairs, but for someone in an office tower in Houston or NYC, that on-the-ground reality is often less clear. Thankfully, FTSI stepped up this quarter and noted another 100,000hp was removed from its roster. The company previously reported 28 company-owned fleets or 1.4M horsepower. Now it reports 25 fleets and 1.3M horsepower. This is a step in the right direction and hats off to FTSI for the disclosure, but some may argue more horsepower should have been removed as it’s hard to see industry demand ever rebounding to the glory days of yesteryear. This begs the question whether the majority of idle fleets will ever see enough demand to all come out of retirement. Hard for us to make that case today. We submit companies would be better served following the FTSI lead.
U.S. Land Rig Count: +6 rigs to 535 rigs.
Q3 Earnings Review: There were a ton of earnings this week and sadly, we couldn’t get through all of the releases/transcripts, but we did hit a bunch. Here are some of our brief observations. For those we didn’t touch on this week, we will summarize high level observations next Sunday.
Oil States International:
- Revenue = $140.5M, -4% q/q.
- Adjusted EBITDA = $8.5M vs. $10.0M in Q2
- Hurricane Ida negatively impacted revenue and EBITDA by $6M and $3M, respectively, thus OIS should have witnessed a q/q improvement.
- Good bookings for Offshore/Manufactured products which were up 64% q/q with a 1.5x book/bill. Backlog stands at $249M.
- Approximately 5% of Q3 bookings were tied to non-oil and gas projects, bringing YTD non-oil and gas bookings to 9%.
- Cash = $68M with total debt = $178M.
- Q3 capex = $3.7M with a 2021 budget = $15M.
- Offshore/Manufactured Products: Revs = $69.0M, -10% q/q; Adjusted EBITDA = $8.6M
- Downhole Technologies: Revs = $25.5M, Adjusted EBITDA = $1.4M.
- Well Site Services: Revs = $46M, +9% q/q. Adjusted EBITDA = $5.9M.
- Q4 Guidance: Consolidated revenue expected to grow 15% q/q.
- Revenue = $32.4M, +51% q/q.
- Adjusted EBITDA = $4.2M vs. negative $1.6M in Q2
- Revenue improvement driven by a tremendous q/q rebound in Canada which witnessed a 140% q/q improvement which was offset by declines in the U.S. and International.
- Gross margins improved to 46%, this highest since 2019 and up from 35% in Q2.
- Balance sheet is fine. Cash = $18M with Debt = $8M.
- Q4 Guidance: Revenue = $33M-$36M. Gross margins expected to range between 43% and 46%. U.S. revenue guided to $8.5-$9.5M, Canadian revenue guided to $20.5-$21.5M and International revenue guided to $4-$5M.
- 2021 Guidance: Full-year revenue = $115-$118M with EBITDA = $8-$10M.
Solaris Oilfield Infrastructure
- Revs = $49M, +40% q/q (best clean top line growth within OFS)
- Adjusted EBITDA = $8M, +18% q/q.
- Total systems active were 88 with a fully deployed system equivalent to 59 systems (that’s +11% q/q).
- Q3 capex = $6M with 2021 capex expected to total $20M.
- Cash = $43M with no debt.
- Dividends continue to be paid, uninterrupted. 12th consecutive quarter.
- SOI new product development and innovation continues.
- Two new AutoBlend systems will enter service in Q1.
- AutoBlend is SOI’s new blender technology.
- SOI is also testing / developing the next-gen belly dump systems, with two systems in trials now.
- Q4 activity likely down slightly given holiday effects, but October’s fully utilized system count was flat with the Q3
- Expect 2 new blenders to go out in 2022.
- Noteworthy – signed 3 year agreement in 2Q with a customer.
Ranger Energy Services
- Revenue = $82M, +63% q/q (driven by acquisitions).
- Adjusted EBITDA = $3.3M, up from $2.0M in Q2.
- RNGR completed the BAS asset purchase on 10/1.
- Running 180 rigs today (67 RNGR/113 BAS).
- Company has identified ~100 rigs which will be scrapped but expect more than this.
- RNGR is delivering the right message which is to drive prices higher.
- Well service rig hours totaled 51,200 in Q3, down from 51,900 in Q2.
- Rev/hour was $584, up from $566 in Q2.
- Completion and Other Services revenue jumped to $51M from $31M due to the acquisitions of PerfX and Patriot.
- Cash = $3M. Net debt = $70M.
- RNGR will have the ability to sell non-core BAS equipment/properties which should free up cash to reduce debt.
- FCF = $2.3B.
- Will add two rigs in Q4.
- Q3 capex = $561M with YTD oil and gas capex = $1.67B.
- Permian Q3 capex = $257M with $757M spent YTD.
- The 2021 budget calls for $1.2B to the Permian, implying Q4 will be ~$440M.
- Company will average 13 gross rigs in the Permian and 2 rigs in the Rockies.
- Will bring 35-45 wells on line in the Permian in Q4 vs. 187 wells YTD or ~60 wells/qtr avg YTD.
- OXY cited record drilling times in the Rockies and Permian.
- Drilled first 15,000 foot lateral with one drilled in less than 10 days.
- Record 9,702 feet drilled in 24 hours in the DJ Basin.
- Completed 18 stage in one day in the Texas Delaware, a record for Oxy.
- Saved 6M gallons of diesel YTD using dual fuel frac and rigs.
- Revenue = $945M, +5% q/q.
- Adjusted EBITDA = $179M
- Adjusted EBITDA margin = 19%.
- Q3 FCF = $111M.
- Balance sheet enhancement continues with debt restructuring during Q3.
- Extended debt maturities at a lower coupon.
- Cash = $1.3B with Debt = $2.6B.
- Q3 capex = $20M; YTD capex = $44M.
- Western Hemisphere: Revenue +4% q/q to $441M driven by Canada and LAM, offset by declines in U.S. Segment EBITDA margin up 300bp q/q to 17%.
- Eastern Hemisphere: Revenue +5% q/q to $504M driven by 8% improvement in ME, NA and Asia. EBITDA margins also up 300bp to 23%.
- FCF $2.8B,
- Capex = $1.3B ($770M L48),
- Dividends = $600M with Stock Repo = $1.2B
- L48 Production 790k bbls/d (445k Permian, 217k Eagle Ford, 95k Bakken).
- 15 Operated rigs and 7 frac crews working in L48.
- FY Guide Capex $5.3B, YTD Capex $3.8B, implies $1.5B in Q4.
- L48 Capex has been 60% of total YTD, implies $900M for 4Q21 vs $770M in 3Q21 in L48.
- Inflation for 22’ – low single digits on international portfolio.
- Permian inflation probably low double digits mostly OCTG, Labor, sand and pressure pumping.
- $4-5B of asset sales post Concho/Shell will allow upgrading of portfolio.
- Committed to give investors 30% of cash flow in dividends/buybacks.
Independence Contract Drilling
- Revenue = $24.0M vs. $19.8M in Q2, +21% q/q.
- Adjusted EBITDA = $0.7M vs. negative $0.4M in Q2.
- Exited Q3 at 15 rigs
- Running 16 rigs today with plans to increase to 17 rigs this quarter.
- Q3 operating days improved 18% q/q.
- Q4 operating days expected to improve 9% q/q.
- Cash margins = $3,456/day in Q3.
- Q4 cash margins guided to improve 30-40% q/q.
- ICD sees cash margins doubling by Q1’22.
- Q3 capex = $4.3M.
- Q3 capex = $365M.
- Q3 FCF = $480M with YTD FCF = $1.4B.
- Reduced net debt in Q3 by $409M.
- Company will repurchase $111M of stock in Q4
- Increased dividend by 50% in Q3
- 2021 capex budget remains at $1.5B.
- 2022 capex spend targeted at $1.5B.
- With flat budget, OVV believes it can keep maintain 2H’21 production levels in 2022.
- Ran 3 rigs in the Permian and drilled 17 net wells in Q3
- Roughly 13 wells had an average lateral of 13,500 feet.
- Drilled at an average rate of 2,000 feet per day and completed at 3,300 feet per day using simulfrac.
- OVV is using wet sand which reduced well costs by $100,000
- Ran 2 rigs in the Anadarko and drilled 12 net wells in Q3
- Ran 4 rigs in the Montney and drilled 23 net wells.
- Longest lateral was 15,300 feet, +13% more than the prior company record.
- Press release noted a new casing design which save roughly $120,000 per well.
- Q3 EBITDA = $519M.
- Q3 FCF = $265M.
- Increased base dividend by 27%
- Will implement variable dividend beginning in 2022.
- Sees $6B of FCF from 2021 through 2025.
- Cash today = $849M with long term debt at $1.26B.
- Increased its 2022 EBITDAX guidance to $3.2B to $3.4B from $2.55B-$2.75B, but no change to 2022 capex plan.
- The preliminary 2022 capex budget is $1.45B at the mid-point and is inclusive of the VINE deal.
- 85% of the capex allocated to Appalachia, Haynesville and South Texas
- The inclusion of VINE for November/December 2021 results in an upwards revision to EBITDAX by $150M, but CHK will maintain 2021 capex.
- Running 11 rigs today with plans to average 10-12 rigs in 2022.
- CHK will invest $30M on ESG initiatives by YE’22.
- Q3 capex = $137M with Q4 capex expected to be $120M.
- Completed 18 wells in Q3 with plans to complete 18 wells again in Q4.
- Running 2 rigs and one frac crew. Expects to add a temporary 3rd rig which will operate through Q1’22.
- Borrowing base on credit facility increased to $1.0B from $725M.
- Company owned sand mine saving $250,000 per well.
- Expect to generate FCF in Q4.
- At $75 oil, FCF generation could be $300M per year.
- Sees service cost inflation of ~15%.
- Completed two acquisitions but focus now turns to debt reduction.
- Noted wider spacing wells are performing as much as 24% to 36% better than tighter spacing well packages.
- Revenue = $250M, +15% q/q.
- Adjusted EBITDA = $42M vs. $36M in Q2, +18% q/q.
- Effective utilization = 13.8 fleets vs. 13.1 fleets in Q2.
- Q4 guidance calls for effective fleets of 12.5 to 13.5
- Q3 Loss on Disposal of Assets was $12M. Assume half is tied to fluid ends which would suggest the pressure pumping unit achieved $48M of EBITDA. This would imply annualized EBITDA/fleet in the $14M vicinity.
- FCF = $16M.
- 2021 capex budget = $155M-$165M, of which spend YTD = $88M.
- PUMP continues to invest in Tier 4 dual fuel with plans to have 86 Tier 4 dual fuel units once existing orders are received = essentially enough for 4-5 fleets.
- PUMP sees U.S. frac fleet growing by 20-30 fleets in 2022, consistent the LBRT commentary.
Magnolia Oil & Gas
- Record EBITDAX, FCF, Net Income and EPS
- Q3 D&C capex = $67M
- Q4 D&C capex = $80M.
- The Q4 guidance is a tad lower than previous guidance due to efficiencies.
- FCF = $143M in Q3 and $375M YTD
- MGY repurchased $79M of stock in Q3 (nearly $280M of repurchases YTD).
- MGY expects to repurchase 1% of its outstanding shares each quarter.
- Paid its first dividend in Q3
- MGY is running two rigs today but may add a third rig in 2022. One rig is focused in Giddings area while the other one is in Karnes.
- Running two rigs will allow MGY to grow its production in the mid-to-high single digits.
- Pad size increasing from ~3 wells/pad to ~4 wells/pad.
- Lateral lengths increase by ~1,000 feet to ~7,000 feet.
- Company noted M&A market not attractive now.
Calfrac Well Services (Canadian $$)
- Revenue = $296M vs. $128M in Q3’20 and $207M in Q2’21.
- Adjusted EBITDA = $35.6M, up from $8.5M in Q3’20 and $4.4M in Q2’21.
- U.S. Market: 9 active fleets today with effective utilization of 8 fleets in Q3. Revenue = $138M with EBITDA = $14M. This compares to $87M and negative $3M, respectively in Q2. The company reports active U.S. horsepower = 576,000 with 297,000 deemed idle.
- Canada Market: Active fleet is four fleets which is expected to stay the same into Q1.
- CFW increased its 2021 capex budget by $5.5M to $61M.
- Cash = $6M. Long-term debt = $378M.
- Full year 2021 capex unchanged at $115-$130M.
- Roughly 90% of the 2021 budget has been spent with Q3 capex at $51M.
- 2021 FCF guidance raised to $80-$90M, up from $45-$55M.
- Three tuck-in deals since August 2021 added 60,000 acres
- Expects double-digit production growth in 2022.
- Will operate a continuous one rig program in 2022.
- Not drilling today but will add a rig in December.
- Drilled 6 wells during Q3 and completed 11 wells.
- Repaid nearly $30M YTD.
- Cash = $1M with total long-term debt = $394M.
Nine Energy Service
- Revenue = $93M, +9% q/q.
- Adjusted EBITDA = $4.5M which included a few one-time benefits which totaled $2.4M.
- Q3 negatively impacted by labor issues as company missed wireline jobs due to lack of people.
- Q4 revenue guided to $92-$100M.
- Q3 capex = $2.1M with YTD spend at $4.9M.
- Cash = $30M with total debt = $318M.
- Cementing: Q3 jobs = 758, +18% q/q. Revs = $29.5M, +8% q/q.
- Wireline: Rev = $19.2M, +3% q/q. Stages = 4,793, +3% q/q.
- CT: Revs = $17.1M, +18% q/q. Days worked = +12% q/q.
- Completion tools: Revs = $26.9M, +10% q/q. Stages completed = 21,815, flat q/q.
- Adjusted EBITDA = $1.2B.
- FCF = $421M with $600M+ expected in Q4’21.
- Will return 60% of FCF through dividends/share repurchases
- Q3 capex = $228M with Q4 capex = $340M.
- U.S. capex = $92M in Q3 vs. $118M in Q2.
- Repurchase 14.7M shares through October 31st with plans to keep buying more.
- Averaged 2 rigs in Q3, added a 3rd rig recently and will add a 4th rig in 2022.
- Company has two rigs in Permian and one in Austin Chalk.
- The 4th rig will go to the Permian.
- Company stated it will not add a 5th rig in the U.S.
- 2022 capex budget likely in the $1.5B range. Compares to ~$1.1B vicinity for 2021. The breakdown is $1.3B for development and $200M for exploratory.
- Running 11 rigs in Egypt, up from 8 rigs. APA sees more additions but won’t return to the mid-20’s at prior peak.
- Expects FCF in 2022 to be around $2B.
- Will acquire GEP Haynesville for $1.85B. $25M of synergies expected in 2022.
- This follows recent Indigo deal.
- Q3 D&C capex = $228M with YTD D&C capex = $643M.
- Q3 FCF = $105M
- Expects to generate $475M of FCF in 2021.
- Expects to generate $2.3B of FCF over the next two years.
- Appalachia: Expects to average 2 rigs and 2 crews in Q4. Drilled 15 wells in Q3 and completed 19 wells. During Q3, SWN averaged 4 drilling rigs.
- Haynesville: Expects current rig and frac crews in Q4 which in Q3 totaled 6 rigs and 2 frac crews. SWN drilled 2 wells and completed 4 wells in Q3.
- SWN noted GEP is running 4 rigs and one frac crew but will drop to three rigs by YE.
- FCF = $84M in Q3 and $137M YTD.
- FCF in Q4 should be over $70M.
- EBITDAX = $309M, +109%
- Capex = $167M with Q4 capex anticipated to be $115M to $135M.
- FCF to be used to pay down credit facility and retire bonds in May 2022.
- Running 5 rigs and 3 frac crews. Activity expected to be steady.
- DUCs should go lower into YE.
- Company acknowledges service cost creep and notes an expectation of +10%.
- Objective is to offset the creep via longer laterals and efficiencies.
- In process of drilling two 15,000 foot laterals in the Bossier formation.
- Production might be up 4-6% y/y in 2022, but that was not official guidance.
- Noted steel prices up 15-17% vs. start of the year.
STEP Energy Services
- Revenue = $133M vs. $108M in Q2, +23% q/q.
- Adjusted EBITDA = $18M vs. $12M in Q2.
- STEP owns 184,750HP of dual fuel equipment and 80,000HP of Tier 4 equipment.
- Canada: Q4’21 expected to exceed Q4’20 and Q4’19 with Q1’22 looking strong.
- U.S.: Q4 expected to improve as STEP’s 3 fleets should have high utilization. Q3 U.S. frac revenue totaled $29.5M, up from $19.0M in Q2. U.S. CT revenue improved from $15.3M to $20.2M. U.S. frac horsepower totals 207,500hp, of which 52,250hp is dual-fuel. 8 of the company’s 13 U.S. CT units are staffed.
- 2021 capex budget remains $39.1M.
- Cash = $2.3M with net debt = $212M.
- STEP comment from release: “STEP will continue to advocate that the industry should remain disciplined and only add crews once pricing reflects the improved economics from higher commodity prices that producers are realizing”.
- Hats off to STEP for calling out new entrants to the U.S. frac market. While the numbers aren’t large, our reporting of these players has largely been dismissed – the reality as the number of new companies bidding on work does not help the industry recovery, thus more reasons industry consolidation is necessary.
Ensign Energy Services (Canadian $)
- Revenue = $269M.
- Adjusted EBITDA = $60M.
- 2021 capex budget = $60-65M with $38M spent YTD.
- Canada: Own 125 drilling rigs with 43 running. Visibility to 50 rigs by YE. Ensign owns 50 well service rigs, running ~30% utilization which should rise to 45-50% in Q1. Pushing rates up 10-15% and getting it.
- U.S.: Own 93 drilling rigs, of which 46 drilling today. Visibility to get to ~50 by YE with further gains expected in 2022. Everyone seems to be raising rates about $500-$1,000/day per month. Running about 36 of the 48 well service rigs.
- Reactivated 7 U.S. rigs for $500,000 each and looking to reactivate another 5 rigs.
- Canada rig count could hit 60 rigs in Q1.
- FCF = $120M.
- Capex = $115M.
- During Q3, drilled 15 wells in Q3 and placed 26 wells on production.
- Presently running 6 rigs and 1.5 completion crews. 5 rigs in the Permian and 1 in EF.
- Release notes active conversion of gas lift systems to electric submersible pumps.
- Company also continuing electrification process, removing 25 generators in the EF.
- Closed Primexx on 10/1.
- Entered into agreements to divest non-core assets for $170M.
- Will convert nearly $200M of debt into equity.
Centennial Resource Development
- Q3 FCF = $77M, a record
- Raising 2021 FCF guidance to $200M-$220M. vs. ~$155M previously.
- Q3 D&C capex = $75M vs. $82M in Q2.
- 2021 D&C capex to range between $290M-$305M, implies ~$70M in Q4.
- Notes plans to extend laterals and expand pad sizes to help offset future service cost inflation.
- Repaid $50M of borrowings in Q3 with $125M repaid YTD.
- Will continue the 2-rig program and one completion crew into 2022.
- Drilled 13 wells and completed 10 wells in Q3.
- Cited two new completion designs which yielded a 30% improvement in stages/day.
- Believes it can further reduce drilling cycle times by another 10%.
- Will divest ~6,200 net leasehold acres for $101M in cash.
- FCF = $268M with $300M of FCF expected in Q4.
- Repurchased $60M of stock and paid $12M in dividends
- Reduced debt by $200M.
- Total debt reduction expected in 2021 = $650M with total cash returned to shareholders = $210M
- Q3 capex = $149M.
- Total production = 18.8 MMBoe, +7% q/q (roughly 204,000 BOE per day)
- Q4 production to decline to 197,000 to 200,000 BOE per day
- Wattenberg: Spent $115M running one rig and one frac crew. Drilled 20 wells and brought 57 wells on line. Exited Q3 with 160 DUCs and 225 permits.
- Permian: Spent $35M running one rig and drilling 5 wells. Company completed several Permian workover projects in Q3. Also spent money on clean-outs.
Forum Energy Technologies
- Revenue = $141M, +3% sequentially
- Revenue negatively impacted by $10M-$15M due to supply chain issues.
- Adjusted EBITDA = $7M, +9% q/q
- Orders = $176M with book-to-bill = 1.25x.
- A nice chunk of orders came in the Completions segment which saw a $12M increase or +26% associated with new product offerings within the stim/intervention business.
- FET called out success of the Serpent Series solution which now has 8 fleets out. Also, FET booked four ROVs in Q3.
- FET Board authorized a $10M share repurchase program (= 8% of FET market cap).
- Cash = $50M with total debt = $232M.
- Bank facilities amended/extended, a positive.
- Q4 Guidance: Revenue = $145M-$155M with EBITDA = $9M-$11M.
Mammoth Energy Services
- Revenue = $58M vs. $71M in Q2.
- Adjusted EBITDA = $3M.
- Average 1.2 effective frac fleets in Q3, up from 0.8 in Q2.
- Company is running two spreads today and is in discussions to add a third fleet.
- Subject to commodity prices/demand, TUSK sees a chance to be at four spreads by mid-2022.
- Sand sold totaled 315,000 tons.
- Call commentary largely on PREPA’s unwillingness to honor its obligations and pay money due to TUSK for work performed.
- Revenue = $439M, +10% q/q.
- Adjusted EBITDA = $15M vs. $6M in Q2
- Better-than-expected sequential revenue growth, a third consecutive quarter of record-breaking gross margins and EBITDA excluding other costs of $15M.
- Generated $22M in free cash flow vs. $7M in Q2. DNOW historically consumes cash in Q3.
- U.S. revenue increased 5% sequentially (U.S. Energy 80% and U.S. Process Solutions 20% ).
- Activity increased during the quarter (completions activity) leading to increased construction and maintenance spend, centralized tank batteries builds, tie-ins and gathering systems
- Improvement in gross margins driven by line pipe price inflation
- Exited low margin product lines while shifting resources to higher margin product lines
- Canada revenue $68M +33% sequentially and International revenue $59M, +11% sequentially
- Gross margins improved to 21.9% (higher product margins)
- 4Q21 guidance, sequential revenue flat to down mid-single-digits, driven by headwinds related to seasonality, customer budget exhaustion and product availability constraints
- Expect a seasonal sequential revenue rebound in 1Q22
- 2021 full-year revenues largely unchanged from full-year 2020
- Full-year 2021 EBITDA improvement over 2020 to be near $90M – stronger gross margins and leaner cost structure
- Improving fundamentals to core market signaling the beginning of a 2022 upcycle
- View that customers spend more money 2022 but the public companies are disciplined
- M&A: targeting accretive margin businesses, non-commoditized solutions
- Working capital, excluding cash, as a percentage of annualized 3Q21 revenue was 10.6%
- Cash conversion cycle was 62 days, an improvement of 9 days sequentially
- Cash=$312M with $0 in debt (total liquidity=$560M)
- Revenue = $218M, (7%) q/q.
- Adjusted EBITDA = $49M vs. $54M in Q2
- Free cash flow = $17M. Year-to-date cash generation to $64M.
- Sequential decline in revenue was primarily driven by lower unconventional frac activity, partially offset by higher activity in Kuwait.
- Adjusted EBITDA in the third quarter was $49M (22% of revenue). Sequential decline was primarily driven by the leverage impact of lower production revenue.
- Production segment revenue for the third quarter was $138M ((7%) over the same period last year and (10%) over the prior quarter. The sequential decrease was primarily driven by lower frac activity.
- Maintaining current manpower structure in anticipation of improved markets in upcoming quarters.
- Drilling and Evaluation segment revenue of $80M +13% compared to the same quarter last year, but down (3%) sequentially. Adjusted EBITDA margins were flat sequentially.
- Outlook much more robust vs last quarter’s results.
- The Company believes there will be significant activity increases and that the MENA region will carry most of that load, (major customers have taken the long view and invested in spare capacity), regional operators understand that nobody but them will be able to fulfill this demand especially in the short term, and they can sustain it longer than anybody else.
- MENA will be the main engine for global commodity growth and that the super cycle is materializing is more and more evident.
- The Company sees double-digit capex spending growth from its customer base across the MENA region next year (and into 2023) as this will lead to a sharp improvement in activity levels over the course of 2022 and ultimately, a more favorable pricing backdrop as equipment capacity continues to get soaked up.
- Notable joint ventures/collaborations: NESR and Cactus Wellhead (frac rental equipment). NESR and Ulterra (Ulterra’s PDF drill bits Asia/MENA).
- Post Q3 NESR completed a refinancing with a goal of creating additional financial flexibility, lowering the Company’s costs, and improving the tax efficiency of the Company’s borrowing structure.
- Prior facilities now refinanced into a single facility with additional term, revolving, and working capital capacity available. The refinancing expands borrowing capacity to $860M.
- Cash= $101M ($75M at 12/31/20). Debt=$427M
- Q3 capex = $18M, down from $21M in Q2 (Capex front end loaded in 2021)
- Q3 FCF = $128M with YTD FCF = $347M.
- Production = 92.1 MBOE/day vs. 92.6 MBOE/day in Q2
- Q3 capex = $67M vs. $58M in Q2
- WLL drilled 10 gross wells and turned in line 17 gross wells.
- Lease operating expense declined to $57M from $64M due to less workovers.
- Company is running two rigs.
- WLL dropped its frac crew recently but will pick it back up in mid-December.
- Company seeing service cost inflation in the high-single digits to low double-digits.
- Company expects its non-operated activity to rise next year.
- FCF $1.1B, Capex $481M vs $509M Q2
- Fixed Quarterly Dividend $74MM, Variable Dividend $494MM
- Total Production- 608k bbls/d (409k Permian, 75k Anadarko, 58k Bakken, 42k EF, 20k PRB) 50% oil, 24% NGLs, 26% Gas
- Q3 Wells Drilled 78 (50 Permian, 9 Anadarko, 10 EF, 9 PRB)
- Q3 Wells Completed 81 (52 Permian, 4 Anadarko, 4 Bakken, 19 EF, 2 PRB)
- Q3 dividend payout +71% to $0.84/share.
- Announced $1B share repurchase program through YE22’ (4% of market cap)
- Reinvestment rate 30%, down from beginning of year at 60%.
- 22’ Guide- Production- 570-600k (50% oil), Capex $1.9-2.2B vs $1.6-$1.8B in 21’
- Permian Running 13 rigs and 4 frac crews
- Anadarko Basin- 2 rigs running, expect to spud up to 30 wells in 21’.
- Partnership with Dow in Anadarko Basin evaluating additional activity in 2022. (higher NGL price helps)
- EF- running 2 rigs through remainder of the year.
- Efficiencies-Permian D&C cost/ft Q3 $554/ft down from $614/ft in 2020 and $940/ft in 2018.
- Drilled 3-mile Wolfcamp development in Lea County 30 day rate as high as 6,300 BOE/D.
- Inflation- DVN is modeling 10-15% cost inflation for 2022.
- Inbound calls from generalist investors to DVN have picked up recently.
- 22’Highlights – Per DVN
- Annualized Dividend Yield of 9% at $80 oil,
- Positioned to generate CF growth of more than 40% in 22’ at $80 oil.
- $80/oil implies 18% FCF Yield
- FCF $480M, Capex $308M, Retirement of Debt $900M ($1.4B YTD), Dividend $39M.
- Expect share repurchases of $500M in 4Q21 ($200M already done).
- Increased the share repurchase authorization to $2.5B.
- Total Production 345k bbls/d, L48 Production 284k bbls/d
- Reinvestment rate tracking below 35%.
- FY Guide Capex unchanged $1B, YTD Capex $781MM, implies $219MM in Q4.
- 3Q Capex at $308 was peak for year, partially due to bringing on 3 well pad in Texas Delaware oil play.
- Total of 9 wells (6 Woodford, 3 Meramec) in the Texas Delaware oil play.
- Inflation for 22’ –modest inflation in the 10% range.
- Permian/Oklahoma 10% of Capex in 21’ likely goes 20-30% in 22’ with good mix of Oil, NGLs and Gas.
- FCF $740M, Capex $391M, Retirement of Debt $432M during quarter
- Reduced debt by $1.3B since end of 1Q21.
- Increased annual dividend by 11% to $2.00/sh, third time this year to raise dividend.
- Commitment to return 50% of FCF to shareholders beginning in Q421.
- Board authorized $2B share repurchase program as part of the return capital to shareholder commitment.
- If FANG were paying 50% of FCF to shareholders in 3Q21
- 50% of $740M = $370M
- Base Dividend $0.50/Qtr = $91M
- Additional Return of Capital (share repo and/or variable dividend) = $279M
- Permian Production 223k bbls/d, 4Q guide 218-222.
- FY Production Guide- raising 21’ range from 219-222 to 222-223.
- 3Q drilled 47 wells and completed 63 wells in the Midland Basin. Well cost: D,C&E $500/ft down from $533/ft 1Q21.
- 3Q drilled 11 wells and completed 10 wells in the Delaware Basin. Well cost: D, C&E $700/ft down from $717/ft 1Q21.
- YTD drilled 135 wells and completed 152 wells in the Midland Basin.
- YTD drilled 28 wells and completed 49 wells in the Delaware Basin.
- Reinvestment rate 35% in 3Q21 down from 39% in 2Q21.
- Drilling Efficiencies- decreases number of days to drill spud to total depth by ~30% this year, drilling 2mile laterals in 10 days.
- Completion Efficiencies- increase avg ft/day from 1,650 on single zipper to 2,800 on 4 well simulfrac in Midland Basin.
- Capex Guide- Q4 $435M – $475M, FY21’ range of $1.525B- $1.625B reduced to $1.49B- $1.53B.
- Inflation for 22’ – approximately 10%, which can be offset with efficiency gains.
- Running 3 simul-frac crews and 1 spot crew this year and expect same next year.
- 90 % of wells next year will be simul-frac.