Happy Mother’s Day to all our mom readers….you are the best!


DEP Travels.  We drive to Midland tomorrow morning for two days of meetings.  Likely will assemble a small group dinner Tuesday night in Midland, so if you’re up for Mexican or Italian, let me know.  We will then proceed to Fort Worth for meetings and dinner on Wednesday, returning to Houston on Thursday morning.  However, we immediately fly to North Carolina on Thursday afternoon to move kiddo #1 out from college and then drive her car back to Texas.  Therefore, be forewarned that the DEP note next Sunday will likely be brief as we will blast it out from the highway somewhere between Raleigh and Houston.

Hydrogen For Frac.  This week we participated in an equipment preview which highlighted the use of hydrogen as a fuel source for frac engines.  The tour, hosted by Caterpillar and Certarus, was held at the CS&P Technologies Houston facility.  By way of background, Caterpillar and Certarus announced an MOU in late April. Specific details of the MOU were limited although the companies noted an intent to work together to leverage each other’s strengths to deliver lower carbon solutions to their customers.  One solution is to advance the use of lower carbon fuels such as natural gas and hydrogen.  We had the chance to see first-hand this partnership at work as the companies demonstrated how hydrogen could be used in concert with dual fuel engine technology.  This display included Certarus CNG trailers/equipment providing CNG and hydrogen to a CAT Tier 4 DGB engine.  The testing process started with ~15% of the fuel coming from traditional diesel and ~85% coming from CNG.  Midway through the process, hydrogen was mixed with the CNG (80% CNG/20% Hydrogen).  The benefit of the hydrogen is a further reduction in methane slip and an overall reduction in GHG.  During the fuel transition when hydrogen substitution began, no audible change in engine performance arose.  For purposes of this test, the hydrogen was sourced from a gas supplier along the Texas Gulf Coast.  Cost details were not shared so we can’t yet opine on the economics of hydrogen.  That said, our impression is lots of infrastructure will be needed to make this fuel source possible.  Nevertheless, from a finance-person’s perspective, the performance on the test stand seemed to work.  Other random thoughts: The hydrogen could be mixed with the CNG and transported together in the same trailer vs. the two trailers on site.  Hydrogen is only being tested on Tier 4 dual fuel engines and not Tier 2.  Again, we have no idea what the economics of hydrogen are, nor do we have an estimate when infrastructure to make hydrogen will be field ready.  That wasn’t the purpose of the tour.  Rather, the tour simply illustrated how hydrogen can be used as a fuel source in order to further reduce emissions.  Definitely something worth paying attention too.  Lastly, we would presume other engine players are testing or will endeavor to test hydrogen as well, so more DEP diligence to be required.

DEP Team Update:  We are pleased to announce Bob Stanton has joined our team.  For many of you, Bob is no stranger.  He’s played in the upstream energy complex with stints at Simmons & Company and then U.S. Capital Advisors.  We were blessed to work with Bob for many years during our time at Simmons.  In his role at both Simmons and U.S. Capital Advisors, Bob served on the institutional sales desk.  Most recently, however, Bob spent the past several years with JP Morgan’s Private Wealth Management group.  He’s a smart guy and a better golfer.  We’ll use his skills to help us on the institutional sales and research front.  We are also excited to announce a new member of our Advisory Committee. Loren Singletary has graciously agreed to step in and assist DEP in a corporate advisory and business development capacity.  Loren spent many years with NOV before retiring and is well respected in both the energy and institutional investor community.  His expertise and relationships are expected to be a great value-add to the DEP team. Finally, we would like to thank Larry Kerr and Chris Menefee for their assistance as Advisors to DEP.  Both Larry and Chris have returned to take leadership roles within the industry, so they will be stepping off as Advisors.  Larry is returning to Gardner Denver while Chris is now with Unit Drilling.  Both Chris and Larry were hugely helpful to DEP and we hope they crush it in their new roles.

M&A Activity Developing.   Small, but helpful deals announced.  First, within the well service sector, Axis Energy Services has acquired the well service assets of Forbes Energy Services.  This is the second deal of consequence within the domestic workover business as it follows the Basic/C&J combination early last year.  Prior to buying the Forbes assets, Axis owned 36 well service rigs along with snubbing and pump down capabilities.  Forbes, meanwhile, brings 117 rigs, 15 CT units and scores of pumps.  To be fair, these are not all “working” rigs/units, but the combination nonetheless solidifies Axis as a top 5 player within the U.S. well service sector.  Purchase price details were not provided, but we suspect Axis had an attractive valuation.  Also, we do not believe Axis acquired the legacy fluid service assets of Forbes.  Ranger Energy Services meanwhile announced on its earnings call that it is within days of making multiple acquisitions in the wireline business.  Best guess is potentially ~2 deals in the works, but no financial details were provided, nor were the targets identified.  That’s ok as our big beef with the OFS sector has been the inability for it to consolidate and rationalize the business.  Now, two deals do not make a trend, but it’s a step in the right direction and we applaud Axis and Ranger for leading the way to fix this business.  Presumably, more deals will follow as the OFS sector remains way too fragmented, particularly in a 400-500 rig count environment.

Finally, while not in the category of M&A, the signs/struggles of the OFS sector remain alive and well.  According to multiple contacts, a privately held frac company suspended operations this past week.  Field feedback suggests customers were caught off guard and are now looking for frac dates.  We don’t have all the particulars and we certainly wish the team well as they are good folks.  That said, if the suspension of operations is due to financial pressures, which would seem reasonable, it is simply an indication of the persistent problems facing the OFS space.  Without higher pricing and consistent utilization, the industry will continue to shrink – either in the form of companies shutting down and/or via consolidation.

Shout Out to Double Eagle:  We had the good fortune of receiving an invite from an industry friend to attend a charity auction hosted by Double Eagle Charities this past Friday night.  The Cook-Off for Kids event was well-attended, featuring top notch music and great social interaction.  More importantly, however, the evening raised a ton of money Rivertree Academy in Fort Worth and Holy Cross Catholic High School in Midland.  Both of these schools are doing REAL work to support local kids in need.  The testimonials from school administrators helped bring us back to the reality of what’s really important in life.  So, if you don’t have a preferred charity – consider this one.  BTW – the charity auction had lots of nice gifts.  We were keen on the Vegas trip, but couldn’t quite match the bid.  Next year, the DEP team will gladly offer to BBQ for a private BBQ social for ~60 should the Double Eagle team need more items in the 2022 auction.

Permian BBQ Cook-Off:   We are knee-deep with event planning, including the Permian Basin BBQ Cook-Off which will be held on September 30th at the Rolling 7’s ranch.  We presently have 44 cooking teams entered and 22 BBQ judges.  We are targeting 54 smokers and 54 beer-drinking carnivores to assist us with judging.  For those who have inquired about cooking spots, don’t worry – we haven’t forgotten you.  Our team heads to Midland on Wednesday to do final measurements of the property.  Once the measurement process is complete, we then hope to have our sponsorship brochure information ready within ~14 days of this final diligence trip.

In the meantime, below is our current save the date which lists confirmed cooking companies.  In addition, we are blessed (and expect) to have BBQ judging executives from the following companies:  Admiral Permian Resources, Apache Corporation, Callon Petroleum, Centennial Resource Development, Chevron, ConocoPhillips, CrownQuest Operating, Diamondback Energy, Elevation Resources, Fasken Oil & Gas, Henry Resources, Hibernia Resources, Kaiser-Francis, Laredo Petroleum, Northern Oil & Gas, Ovintiv, Patriot Resources, Pioneer Natural Resources, SM Energy, and XTO.  We are still looking for more E&P company judges – let us know if you or someone you know might have an interest.  Lastly, please mark your calendar to attend.

permian basin bbq cook off

BKR U.S. Land Rig Count:  Up 8 rigs to 434 after having been flat the past two weeks.  Increases were largely in the Haynesville (+4 rigs) and Permian (+5 rigs).  We intend to true up our rig count forecast within the next week or so, but at this point, we don’t feel as if major changes are forthcoming.

Q1 Earnings Observations.  FYI – There were a ton of calls last week.  We did the best we could to highlight things of interest…there is no way we did a totally thorough job, so we encourage industry readers to peruse the company’s press releases/slide decks as there is no shortage of information out there.

SOI:  Revs = $29M, +13% q/q.  Q1 EBITDA = $6M, +26% q/q.  SOI ended the quarter with $55M of cash and no debt on balance sheet.  SOI also had 10th consecutive quarterly dividend payment in 1Q21.   SOI system count for 1Q21 was 52, +24% during the quarter and expects 2Q activity to be flat with 1Q.  SOI’s new all electric blender system eliminates traditional blender points of failure and reduces headcount by as much as 80% on location which continues to drive costs lower and provides safety improvements.  The first trial of the new system will take place in 2Q21. Capex = $2.6MM during Q1.  FCF of $100k.  Expect FY21 capex to be in the $10-$15MM range due to new growth capital initiatives including water silo conversions and system enhancements.  Simu-Frac jobs helping drive the conversion of sand silos to water silos.

PUMP: Revs = $161M in 1Q21, a 5% increase vs Q420.  1Q21 EBITDA $20M vs $24M 4Q20, $5M of lost EBITDA with 8 days of extreme winter weather in Texas during February.   1Q21 fleet utilization average was 10.3 fleets compared to 9.6 in 4Q20.  Winter storm impacted fleet utilization by ~ 1 fleet.  PUMP will only pursue profitable work as this discipline is critical to PUMP and the industry.    Today, PUMP has 13 fleets working of which 2 fleets are working simul-frac jobs.  PUMP guidance for 2Q21 is 12-13 fleets. PUMP believes the industry has 10-15 fleets total working simul-frac jobs.   CAPE   Seems like the way to go, but two operators not getting the savings they were expecting to get out of it.  If economics improve, PUMP will convert more of their equipment from Tier 2 to Tier 4 DGB.  Company will have 90,000hp of Tier 4 DGB equipment by YE’21.  50,000hp is new purchases (previously disclosed) while 40,000hp is engine upgrades.  Balance sheet is strong.  Cash = $56M with no debt.  Q1 capex = $32M of which $18MM was maintenance.  Capex for Tier 4 DGB purchase/conversions was ~$12MM during the quarter.  2021 budget set at $115M-$130M ($37MM for Tier 4 DGB).

NCSM:  Revs = $28.5M, +4% q/q.  Adjusted EBITDA = $0.1M vs. $3.0M in Q4.  Revenue growth was driven by better results in Canada (+45% q/q improvement), offset by lower U.S. revenue.  Balance sheet is sound as cash = $12M while total debt = $6M.  Company expects full-year revenue to be between $110M and $125M and Adjusted EBITDA to be between $5M and $10M. Fracturing Systems activity in the US is levered to smaller operators that have been increasing activity thus far in 2021.

NOG:  Interesting story.  Largest non-op player.  Q1 capex = $38M.  2021 guidance = $200M to $250M.  Q1 production up ~8% q/q with capex down ~22% q/q.  Company growing via acquisition having recently just acquired assets in the Marcellus via the purchase of the Reliance Marcellus assets a few weeks ago.  NOG announced its first quarterly dividend and stated on the Q1 call a desire to methodically grow this over time.  Dividend growth is expected as debt reduction unfolds.  NOG believes it will repay its revolver ($366M outstanding) before YE’24.  FCF reached $42M in Q1.  Operational anecdotes.  NOG sees the Williston rig count growing in the coming months.  Noted Q1 included heavier-than-normal workover activity which could potentially ease as the year unfolds.  Will be interesting to see if the recent strength in U.S. well service activity will prove fleeting.  Finally, NOG is committed to tactical, smart acquisitions.  Company is presently evaluating ~15 asset packages and believes the non-op M&A market could be as much as ~$10B.  Deals range in size from small (i.e. ~$20M to $200+M).

FANG:  Q1 D&C capex = $273M.  2021 D&C Guidance = $1.3B – $1.4B, thus 22% spent at the mid-point.  Q2 total capex guided to $350-$400M vs. total Q1 capex = $296M.  FCF totaled $331M in Q1.  Of note, FANG announced the divestiture of the QEP Williston Basin assets for $745M while the company also will ~8,000 acres of non-core property in the Permian for $87M.  Proceeds for debt reduction. For 2021, FANG expected to drill 200-215 gross wells and complete 275-285 gross horizontal wells with an average lateral of ~10,300 feet (75% Midland Basin / 25% Delaware Basin).  During Q1, FANG drilled 49 wells and completed 67 wells.  Good discipline by FANG as cash capex as a percent of cash flow was 47% during Q1.  Comprehensive ESG update in the company’s slide deck.  Q2 production guided to 232,000 to 236,000 barrels of oil a day. 2021 themes: generate free cash flow, keep capital and operating costs down, extend debt maturities, add Tier 1 inventory and divest noncore assets. Running 11 rigs and 3 to 4 frac spreads. A&D market “still seems to be pretty frothy”.

PDCE:  Q1 capex = $125M.  2021 budget unchanged = $500-$600M.  Q2 capex will rise to ~$200M with Q2 FCF expected to total ~$75M.  PDCE generated $175M of FCF and reduced net debt by $230M.  The company also repurchased 600,000 shares of stock for $22M and will commence a quarterly dividend this year.  Operational Anecdotes:  The company is running one rig and one frac crew in the Wattenberg.  During Q1, PDCE spent $95M here, drilling 20 wells and bringing 34 wells online.  In the Permian, PDCE spent $30M, running one rig and 0.5 frac crews.  PDCE will run the crew fulltime in Q2. The company reports Delaware Basin wells are average 17 days spud to rig-release, beating guidance by ~20%.  Outlook.  PDCE’s multi-year outlook (2021-2023) assumes $500-$600M of capex in a $55 WTI world.  This model would yield cumulative FCF of $1.8-$2.0B, allowing PDCE to reduce debt by $850M and return $650M to shareholders.  What’s not clear is what capex could be should WTI prices stay $60+.

OAS:  Q1 capex = $29M.  2021 capex = $230-$245M, thus OAS only spent ~12% of its 2021 budget.  Q2 capex expected to be $75-$90M.  OAS announced the purchase of the QEP Williston Basin assets from Diamondback.  Purchase price is $745M.  OAS is tweaking the 2021 capex budget higher by $5-$10M to reflect incremental workover activity.  OAS does not expect to spend any D&C capex on the FANG assets until 2022.  Operational anecdotes:  Bakken well costs in the mid-$6M range, down ~17% from early 2020.  Currently running 1 rig in the Bakken with plans to complete 20-25 wells.  The company noted it is presently focused on areas in the Wild Basin and Indian Hills.  Later this year, it will begin drilling its South Nesson project, but it’s not clear if this means a rig addition or a rig move.  In the Permian, OAS will bring on 6-7 wells in June and will add a rig later this year.  Other: OAS declared its first dividend of $0.375/share.  The company anticipates raising the dividend to $0.50.  It also has a $100M share repurchase program.

BCEI: Q1 capex = $33M.  2021 capex = $150-$170M, thus BCEI only spent ~21% of its 2021 budget.  The 2021 plan incorporates the completion of 45 wells, of which we believe 8 were completed in Q1.  The Q1 completions were for the legacy BCEI DUC’s.  Beginning in 2H’21, BCEI will complete the HighPoint Resources DUCs.  As a reminder, BCEI and HighPoint merged on April 1, 2021.  Of note, BCEI will pick up a rig in Q4.  The company initiated a dividend which will be paid in Q2 while estimated FCF in 2021 is expected to be ~$150M.

SND:  Revs = $28M vs. $25M in Q4, +8% q/q.  Adjusted EBITDA improved to negative $3.5M from negative $7.7M.  Volumes up 25% q/q to 762,000 tons.  Q2 guidance calls for volumes to be up 5-10% q/q with contribution margin rising in Q2/Q3.  Q1 contribution margin came in at $1.0M or $1.36/ton.  Balance sheet is fine.  Cash = $10M with total debt at $28M.  SND forecasts being cash flow positive this year, somewhere in the $10M vicinity.  This quarter SND rolled out its SmartPath technology.  The first system operated in the Bakken.  10 systems are expected to be deployed by YE’21.  Unclear what the per unit contribution is, but the rate of growth, if achieved, would be commendable.

NINE:  Revs = $67M vs. $62M in Q4, +8% q/q.  Adjusted EBITDA improved to negative $3.4M from negative $13.9M q/q.  Good debt reduction q/q as NINE lowered its debt by $26M to $318M.  Cash is $53M.  The company repurchased $26M of debt for $8M.  Operationally, NINE noted an 80% q/q increase in sales of its Stinger Dissolvable plugs while NINE also noted trials began in Q1 for its new Scorpion Pincer Composite plug.  Operational anecdotes:  Cementing jobs totaled 620 in Q1, +22% q/q.  Rev/job in cementing up +3% q/q.  11 of 40 cement spreads are stacked.  Wireline completed 3,448 stages, -2% q/q.  Rev/stage -7% q/q.  Coiled tubing utilization = 29% with 7 of 14 units stacked.  CT days were down 8% q/q.  Completion tools revenue totaled $20M, +11% q/q.  Weather impacted NINE’s operations as it did others. Q1 capex totaled $1.9M with 2021 capex = $15M-$20M. Q2 guidance.  NINE sees revenue up double-digit q/q to $78M-$86M with additional revenue improvement expected in Q3.

RNGR:  Revs = $38.5M vs. $41.5M in Q4, -7% q/q.  Adjusted EBITDA was a negative $0.2M vs. positive $3.2M in Q4.  Winter weather and lower wireline pricing burdened Q1 results.  Company did a good job walking through the activity transition since February as April composite pricing is up 10% vs. the Q1 monthly average while rig hours are up 17% vs. the Q1 monthly average.  For Q1, total rig hours were 43,200 vs. 43,100 in Q4.  Composite rates were $493/hour, down from $503/hour.  We suspect the decline was rig mix related.  Total debt at the end of Q1 was $24M, but subsequent to quarter-end, RNGR entered into a sale leaseback transaction which allowed RNGR to reduce total debt to $18M.  The most important takeaway from the earnings call was RNGR’s acknowledgement that it has multiple pending acquisitions, all of which appear to be in the wireline segment.

NEX:  Revs = $228M vs. $215M, +6% q/q.  Adjusted EBITDA = $0.7M vs. $7.7M in Q4’20.  NEX estimates the impact of winter weather cost the company ~$10M in profitability.  The company averaged 18 deployed fleets and 15 fully-utilized fleets in Q1, up 1 fleet q/q.  Annualized adjusted gross profit per fully-utilized fleet totaled $4.1M in Q1 vs. $6.2M in Q2.  Presumably this is higher if adjusted for the ~$10M in lost profits, perhaps as much as $2.5M/fleet.  Near-term guidance points to higher activity as Q2 is expected to average 20 active fleets and 18 fully-utilized fleets.  This should distill into 25+% q/q revenue growth with adjusted EBITDA coming in between $18-$22M.  For the full-year, NEX sees adjusted EBITDA of at least $80M.  Balance sheet is fine.  Cash = $272M with total debt = $335M.  1H’21 capex is budgeted at ~$60M with NEX noting plans to continue its upgrade of Tier 4 DGB engines.

FTSI:  Revs = $96M vs. $50M, +92% q/q.  Big improvement when one considers fully-utilized fleets increased to 11.8 from 8.3, +42% while total pumping hours increased 51% q/q to 14,776.  Adjusted EBITDA improved to $7.8M vs. negative EBITDA of $5.2M in Q4.  Management estimates lost EBITDA of $2-3M in February due to the winter storms.    Capex = $5.3M while the 2021 budget is set at $30-$40M.  Balance sheet is strong.  Cash = $86M with no debt.   Outlook:  April enjoyed a full work calendar while management notes May is off to a good start.   Q2 adjusted EBITDA guided to $11-15M on fully-utilized fleets of 10-12.  The slight q/q reduction in fleets is due to gaps in the calendar.  Q3 fully-utilized fleets guided to 12-14.  Company sees 2021 adjusted EBITDA of ~$50M in 2021 and believes annualized EBITDA/fleet could reach ~$10M in 2022 vs. ~$3M today.  FTSI will continue to upgrade to Tier 4 DGB engines.  Had 2 fleets doing simulfracs in Q1…Likely 1.5 to 2 in Q2.

EQT:  Real story not Q1 earnings, but rather another transformative deal as EQT announced the acquisition of Alta Resources for $2.9B.  In Q1, EQT generated FCF of $75M with plans to generate FCF of $575M-$675M in 2021.  The 2021 capex budget was trimmed by $75M to $1.025B to $1.125B.  Q1 capex of $238M, below the company’s guidance of $280-$305M.  Company will run 1-2 HZ rigs and 2-3 frac crews in 2021.  For the Alta assets, EQT will maintain a one rig maintenance program.  The pro forma FCF for 2022 could be as much as $1B.  Integration is not expected to be a challenge given EQT’s recent integration of the CVX Marcellus assets.  One benefit of the Alta assets are its low operating costs which will help reduce EQT’s costs.  A ton of detail in EQT’s slide deck on ESG, deal synergies, etc.

CPE:  Q1 capex = $96M.  2021 operational capex budget = $430M.  FCF in Q1 = $25M, but rising this year as CPE forecasts FCF of $200M.  Debt reduction remains a priority.  With FCF and proceeds from asset sales, CPE’s debt is down almost $400M from the middle of last year.  Believe FCF through 2023 could total $500M to $800M in a $50-$60 WTI world.  Operational anecdotes.  Drilled 18 wells in Q1.   Called out the success of its first E-Frac project.  This included a three-well pad with ~160 total stages.  The pad also used 56M pounds of proppant with average laterals approaching ~12,000 feet.  Recently set a new company record for Delaware lateral efficiency drilling 11,359’ in ~75 hours.  Eagle Ford completed lateral feet per day up +15% in Q1’21 vs. Q1’19 (up slightly over Q1’20).

MGY:  Q1 capex = $39M.  2021 budget expected to be less than $300M.  Company will add a second rig this summer.  FCF totaled $100M, allowing MGY to repurchase $88M of its shares.  The company also announced during Q1 that it would commence a semi-annual dividend.  Moreover, MGY hopes to repurchase 1% of its shares quarterly.  Raised production guidance, now sees 6-9% y/y production growth.  The company stated it averages two wells drilled/month in the Giddings area with well costs averaging $6M/well.  Results in Q1 were records as margins reached 48%.

CDEV:  Q1 capex = $73M.  The 2021 budget is $260M-$310M.  FCF totaled $11M.  During Q1, CDEV upgraded its drilling rigs, replacing the legacy rigs with walking rigs.  This is expected to reduce cycle times going forward.  The company operated two drilling rigs and one frac crew in Q1 – drilled 9 wells and completed 11.  Company noted continued efficiency gains, highlight spud to rig release improvements of 11% y/y.  In Q1’20, the company averaged 19.4 days, but this has improved to 17.3 days.  A key driver is the company’s use of three-string casing.  The drilling efficiencies are made more impressive given CDEV’s average lateral length increased to an average of 8,100’ in Q1’21 vs. ~6,900’ in Q1’20.  Completion stages per day are averaging around 7/day with average jobs using 2,000 pounds of proppant per foot.  CDEV’s rigs are both dual fuel and by the end of May, its frac fleet will be dual fuel as well.  The company is using CNG to fuel these dual fuel engines.  FCF guidance upped.  The company had previously called for FCF of $55-$75M, but now sees it being closer to $100M.

PVAC:  Q1 D&C capex = $54M.  2021 D&C capex budget unchanged at $205M-$235M.  PVAC expects to spend ~$56-$64M in Q2.  Will maintain a 2 rig program.  FCF totaled $6M.  Company noted prepaid capex of $12M which locked in lower service costs.  Looking ahead, FCF expected to improve and will be used to reduce debt.  Production guidance increased.

ICD:  Revs = $16M vs. $13M in Q4.  Adjusted EBITDA = negative $2M vs. negative $1.5M in Q4.  Q1 operating days up 31% q/q with the ICD fleet at 43% utilization.  Rev/day = $15,465 vs. $16,720 in Q4.  Cash margins = $2,802/day vs. $3,001/day in Q4.  Cash margins expected to increase ~11% in Q2.  ICD operated 12 rigs during Q1.  It expects to exit Q2 with 15 operated rigs.  These incremental rigs will displace competitors rigs as ICD notes customers are upgrading. Management noted rigs renewing at higher pricing with some going up in excess of $1,000/day.  Two rigs renewed in the high-teen’s before adders. Contract terms also improving as incidental charges going back on the ticket.  Rig fleet likely to be 7 Permian, 5 Haynesville/ETX and 3 Eagle Ford/STX.  All rigs are dual-fuel capable.  Balance sheet still a work-in-process.  Total debt = $145M with cash = $5M.  Company has successfully used its ATM to raise equity/cash.  Q1 capex = $1.7M.

SBOW: Q1 capex = $36M.  2021 Capex reiterated at $100-$110M, thus 30-35% spent in Q1.  Company added a rig in April.  It will drill through August and then be released.  A rig will subsequently be picked up in Q4.  Appears completion activity will be up in 2H’21.  The budget assumes 16 wells are drilled and 18 are completed.   SBOW anticipated FCF of $30M-$50M this year.  Used FCF to reduce debt by $30M.  Efficiency Gains.  Noted its completed stages/day improved 17% vs. the 2020 average.

PXD: Capex =$605M in Q1 with $3.1-3.4B expected to be spent in 2021 (inclusive of DoublePoint acquisition). The company plans to continue running 22-24 rigs, while dropping DoublePoint rig count from 7 to 5 by the end of the year.  The highlight of the call was the forecast for FCF generation as the company expects to generate $2.7B in 2021 and more than 20B in the years 2022-2026 accumulating a total of 23B by 2026 (calculated using future strip).   The company noted that they now believe that they have 15k Tier 1 locations, and that their large contiguous acreage position has allowed them to drill several successful 15k’ laterals (up from the average of 8-10k’).  Longer laterals definitely seem to be part of the plan for the future.  PXD also highlighted a less than $30 best in class breakeven price.  Regarding the DoublePoint acquisition the company plans to get the former company’s production from 92K BOEPD up to 100k BOEPD by the end of the 2nd quarter, keep it flat at that 100k until the end of the year,  and then focus on growing it 5% per year from that point (DoublePont had been growing at ~30% per year).  The company also noted the benefits that they have received from testing Simulfrac on 4 of their pads in Q1: cost savings of $200-300k/well (similar to competitors), and 3,000 feet of completed lateral per day (50% improvement) and they are expecting to expand trials in Q2.  Company noted that their main source of inflation at the moment was in raw materials (sand, chemicals, and cement), but that they have been able to offset those increases through cost efficiencies.


MRO : Q1 Capex = $184 M, Q2 should increase to $300 with no change to estimated 2021 Capex of $1.0 B.  Like its competitors MRO was particularly focused on cost reduction, capital efficiencies, paying down debt, generating free cash flow, and returning capital to shareholders (goal = 30% of CFO, while 2021 appears closer to 40%). MRO highlighted: FCF post base dividend breakeven below $35 per barrel of WTI, company successfully paying down $500m in debt and targeting another $500 in debt paydown, while growing its quarterly base dividend 33% from 3 to 4c.   “and as we continue to advance further base dividend growth in line with our framework, we’ll look to transition toward simply retiring debt as it matures and focusing more on alternative shareholder return mechanisms, including share buybacks or variable dividends all funded through sustainable free cash flow generation.”   The company reiterated its commitment to keeping capex steady at $1b regardless of commodity price.  Operationally, The Bakken and Eagle Ford continue to commandeer a lion’s share of the capex at around 90%, while Oklahoma and Permian assets are becoming increasingly competitive and in 2022 should see an increase in the budget 20-30%.


EOG: Q1 Capex = $945M with (< $1.0 = Midpoint of previous guide) with Q2 exp to be = $1-1.2B, & 2021 Guide of $3.7-4.1B.  In context 2019 Capex = $6.234B & 2020 = $3.49B.  FCF in Q1 was $1.1B.  EOG’s theme for the call was “Shifting to Double Premium” which calls for the company to develop wells that earn 60% Direct ATROR at $40 WTI (previously this number had been 30% at $40).   EOG believes it has 5700 double premium locations and continue to target a base decline rate of less than 25%.  The company continues to drive down costs, and efficiencies as they target a 10% ROCE at $50 WTI.   As you would expect, EOG highlighted the FCF machine that they have become especially in lieu of the $600M spent on the $1.00 special dividend.  The company expects maintenance capex to be at $3.4B (keeps production at ~440Mbopd and plans to spend another $500mln in capital investment, which would allow EOG to breakeven with FCF at $32 WTI.  The company has paid off $1.35B in debt in the preceding 3 years and plans to pay down another 2Bln by year end 2023.  The company will continue to evaluate opportunities to return to cash to shareholders via increasing the base dividend, issuing more special dividends, and / or buying back stock.

CRK: Q1 D&C capex = $163M.  2021 D&C capex reiterated at $510M to $550M.  Roughly ~30% of the 2021 budget spent.  FCF was $33M after preferred dividends while FCF could reach $200M in 2021.  Company drilled 21 gross wells in Q1 using six operated rigs.  One rig will be released this month with the total wells drilled budgeted at 67 this year.  Takes about 20 days to drill the wells and ~30 days to complete them.  CRK is also running 3 frac crews today, but sees this being an average of 2.3 for the year, thus we would suspect a crew gets dropped later this year.  Noted plans to pursue 15,000 foot laterals.  This will likely require workover rigs vs. coil to do the clean-outs.  Leverage ratio is improving.  Company sees it moving to 2.5x by YE’21 vs. 3.8x at YE’20.  Company announced a 3-year contract with BJ Energy Solutions to use their new TITAN fleet.  We believe this will be BJ’s second TITAN fleet, thus a newbuild.  The fleet will feature 8 pumps vs. the traditional 18 pump conventional set up.  Carbon emissions are estimated to be reduced by 25% while methane emissions are expected to be reduced by 60%.  Noise abatement is also highlighted as a safety benefit.  This fleet will go to work in early 2022.  GHG intensity reduced 38% since 2018 and likely moves lower with company’s adoption of the BJ Titan fleet.

ESTE: Q1 capex = $10M.  2021 budget = $90M-$100M.  Company completed 5 wells in Q1 and resumed drilling with one rig in March.  Company will likely add a second rig later this summer.  FCF in Q1 totaled $32M.  Company has made two acquisitions in recent quarters with the second deal expected to close in the coming months.  For the second deal (Tracker Resources for $127M), no incremental capex is expected to be spent in 2021.  Company noted service cost increases as costs were up in Q1 vs. Q4.  Company’s cost/stage reached $43,000 vs. $38,000 in Q4. Part of the increase is inefficiencies due to shorter laterals, but higher steel costs and higher diesel costs were called out.  ESTE also noted plans to change artificial lift methods from electric submersible pumps to gas lift or gas-assisted plunger lifts.

APA: Prioritizing returns over production growth, budgeting conservatively and focusing on free cash flow generation and debt reduction. Aggressively managing cost structure and will continue to do so regardless of the oil price environment. FCF > $500M. Upstream capital investment and LOE were considerably below guidance for the Q, with strong price realizations, all of which is being designated for debt reduction. Full year guidance is unchanged (CAPEX $1.1 Billion, Adjusted Production 340-350 Mboe/d).  Company averaged 1 rig in the U.S. in Q1.  Company plans to complete 25 DUCs in Q2.

WTTR:  Revs = $144M, +8% q/q.  Adjusted EBITDA = $1.0M vs. $10M in Q4. Strategic objective: improving and growing the base business in a recovering activity environment by creating value for our customer base with our integrated full lifecycle FluidMatch solutions which should drive market share gains and gross margin improvements. Deploying expertise in water and chemicals both across the energy value chain and into other industrial applications as a value-add solutions company. Continue to pursue smaller strategic investments and acquisition opportunities in areas such as technology, energy transition, and ESG solutions. M&A is clearly on the table. Water Services, expect to grow revenues 15% to 20% in the second quarter, while restoring margins into the double-digits. Water infrastructure, recently more than doubled its revenue from Q3 to Q4, advanced revenue modestly in the first quarter while holding margins at 30%. Oilfield Chemicals, anticipate very strong Q2 revenue growth of 20% to 30% along with those 14% to 16% gross margins. Expect second quarter consolidated revenue growing to $160 M to $170 M with adjusted EBITDA margins of 5% to 7%. FCF of -$8 M due to lower capex in the quarter ($2.2 M in Q). Net Capex forecast for full year of no more than $30 M to $40 M for all purposes. Net cash position of $160 M (~30% of market cap).

DVN: 1Q21 adjusted operating cash flow $759M, 1Q21 Capex $487M ($447M upstream, $40M Midstream/Other).  Reinvestment of cash flow of 64% in 1Q21.  Reduced debt by $743M YTD on total debt reduction program of $1.5B.  DVN plans to redeem another $500MM in bonds in June.  Net Debt/EBITDAX on tract to reach 1.0x by year end.  Cost synergies to exceed original target, now $600M, +$25M in D&C efficiencies relative to original plan.  FY21 upstream spend target at $1.6-1.8B (80% in Delaware).  FCF yield at $60 WTI is approximately 12% for 2021 and if you exclude hedges and give full benefit of synergies, the FCF yield at $60 WTI is approximately 20%. Fixed plus variable dividend –  65% of capital allocation to dividends and debt reduction.  Fixed Dividend 11c and Variable 23c = Total payout 34c.  1Q21 Production 499k bbls/d (Permian 310 k, Anadarko 68k, Williston 61k, EF 30k, PRB 23k and Other 7k).  Gross Operated Wells Tied in 1Q21- 74 (52 Permian, 12 EF and 10 PRB).  Average lateral Length 1Q21 – Delaware 10,000 ft, EF 4,400 ft and PRB 9,800 ft.  DVN realized prices during 1Q21 was $47.23/bbl.  D&C cost/ft in the Delaware Basin was $614 in 2020 and was down to $534 in 1Q21.  2 Frac crews running in Delaware.  Running 2 rigs in Anadarko basin and expect to spud 25-30 wells in 2021.  Commenced Dow JV drilling program in 1Q21 and $100MM drilling carry on 133 undrilled locations.

COP:  1Q21 earnings $1B vs 1Q20 loss of $1.7B  Cash flow from operations $2.1B exceeded capex of $1.2B.  COP paid $600M in dividends and repurchased $400M of shares during Q121.   Resumed stock repurchases at $1.5B annualized level.  1Q21 total production of 1.488M bbls/d excluding Libya and approximately 50k bbls/d of unplanned production downtime throughout L48 from winter storm Uri.  L48 exited Q1 with 15 drilling rigs (11 Permian, 4 EF)  and 7 frac crews (5 Permian, 2 EF). L48 production 715k bbls/d (405 Permian, 187 Eagle Ford, 86 from Bakken).  COP in process of restarting 4 rigs across their operated assets in Alaska.  In Canada, COP has reduced drilling costs in the Montney by 25% over the first four paths.  In Asia Pac region, APLNG is running well and has cash breakeven of $25/bbl. APLNG distributed $100MM to the company in 1Q21 and expects to distribute $200MM in 2Q21.   Guidance: 2Q Production expected to be 1.50-1.54 MM bbls/d.  FY21 Capex $5.5B. Q1 at $1.2B, would imply ~$1.4B/quarter for the rest of the year. Debt Reduction plan is reduce by $5B over next five years, with $3B of bonds retiring over next 5 years, some will be early retirement. Plan to sell Cenovus shares in the open market beginning in 2Q21 (valued at$1.6B) and should be done by the end of 2022.  Proceeds will be used to buy back COP shares, which would be above and beyond the $1.5B regular buyback. Mid-year market update in June COP will provide an update to synergies.    Recognized by Dow Jones Sustainability Index as top US ESG performer in the Oil and Gas Upstream and Integrated Sector.

FI: Q1 Revs=$95M -2% q/q and Adjusted EBITDA = $7M, adjusted EBITDA margins improved to 7% from 5% in Q4. FCF loss was $18M for the quarter, ended the quarter with $193M in cash and no debt. Additional rig deployments and project start-ups will generate strong year over year revenue growth. Company’s full-year 2021 guidance of high-single-digit revenue growth and double-digit margins. Expro deal is ‘on track to close by the end of the third quarter. Experiencing the benefits from its cost reduction actions, process improvements, consolidation of its operations, that were started in 2020.

DNOW: Q1 Revs=$361M +13% q/q; Adjusted EBITDA = $1 M vs. ($29)M in Q4. Driven by improved activity and growth from all three reporting segments. Q1 revenue per Rig @ $1.2M. Q1 gross margins 20.8%. $374M cash balance at March 31, 2021, with $0 debt; Free Cash Flow of $(5)M. Inventory turns 4.6x. Completed two transactions, Master Corporation (February) and Flex Flow (April) acquisitions.

Weatherford: Q1 Revs=$832M -1% q/q; Adjusted EBITDA = $102M +4% q/q. Q1 free cash flow of $70M improved $93M sequentially. Total cash of $1.3 billion as of Mar. 31, 2021. Adjusted EBITDA margin expected to expand by 100 bps to 200 bps from H2’20 levels. North America revenue growth driven by increased Drilling, Evaluation, and Intervention sales in the United States and Canada, as well as seasonal activity increases in Canada partially offset by lower Completion and Production activity. Consolidated revenues expected to be in line with annualized 2H’20 results. Continued focus on improving cost structure and driving efficiencies. 2021 full year CAPEX expected in the range of $100-130M. Relisting on NASDAQ as “WFRD.”

FET: Q1 Revs=$115M +10% q/q; Adjusted EBITDA = $2M +$7M q/q. Q1 free cash flow of $70M improved $93M sequentially. FCF ~ breakeven. Ended Q1 with $101M cash and total liquidity of $243M. Demand is improving short-cycle products. Customers not yet be willing to spend capital dollars on new equipment, but spending is increasing to keep equipment working and to reactivate stacked equipment. During Q1, FET saw a 21% increase in inbound orders compared to Q4, (excluding businesses sold in Q4). Have the capacity to increase revenues without considerable addition to fixed cost structure. Expect revenues for the second quarter, $125 – $135M and EBITDA of $6-$8M.

EXTN: Q1 EBITDA $33.1MM. Revenue by Geography: 42% Africa/ME; 44% LAM; 9% Asia Pac and 5% NAM.   ECO backlog of $1.23B at the end of Q1. Total Capex of $80-90M in 2021. Debt to EBITDA = 3.8x.  Q2 Guidance: EBITDA = mid-$30M range.  2021 EBITDA = $150-160M; SG&A  $125-135M; Interest Expense = $40-45M; Cash Taxes = $20-25M.

WLL:  Q1 capex = $56M, up from $21M in Q4.  Company drilled 6 wells and completed 15 wells in Q1.  Presently running one rig and one frac crew in the Sanish Field.  Net debt at the end of Q1 was $220M, but WLL has reduced debt to $170M as of 4/30/21.  This year WLL expects FCF of $300M, of which $100M was generated in Q1.

XEC:  Q1 capex = $165M.  2021 capex budget unchanged at $650-$750M, thus ~24% spent in Q1.  XEC generated FCF of $231M in Q1.  Oil volumes totaled 68.6 MBopd.   Debt reduction will be prioritized.  Small asset sales pending as XEC announced agreements to sell $115M in non-core assets.   XEC is running one rig in the Mid-Con which will be released this month.  XEC is running 5 rigs in the Permian and 2 frac crews.  Q4’21 oil production is expected to be up ~30% from Q4’20.   Company noted a 26% improvement in footage drilled per day in Q1’21 vs. Q1’20.  In 2021, company expects to complete 65 wells vs. 46 in 2020 and 76 in 2019.  Average lateral lengths in 2021 will be ~9,600 feet vs. ~9,200 feet in 2020.  Management highlighted one well which reached total depth in 9.1 days for a 2-mile lateral (Permian) – more than 2,000 feet/day.  Two rigs are running directly from XEC grids.  Advertised emission reductions are noteworthy.


Daniel Energy Partners is pleased to announce the publication of its first market research note. In this note, we reached out to executives across the oil service and E&P sectors to gauge leading edge sentiment.

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