A gaggle of OFS and E&P conference call takeaways are summarized below. Admittedly, much of this is simple elevator analysis and a rehash of data points from the various press releases, IR slides and conference calls. For those who don’t have time to read every release, this may be of some value to you. We also include a few brief big picture thoughts as we digested these calls. We also bloviate on recent discussions with industry contacts regarding the labor market as well as parts of the OFS supply chain.
Labor Market and Supply Chain Pressures. We caught up with multiple OFS companies this week to discuss current business challenges. No surprise weak pricing/margins are the biggest frustrations, but complicating matters is a tight labor market. Four well service contacts report job turn-down’s due to the lack of people. As a result, all are moving prices higher, but three still claim rig rates are below pre-COVID levels. Meanwhile, inflationary pressures are mounting, including the need to raise hourly wages. For workover companies, the average starting wage varies by basin. We had some contacts in East Texas share the starting wage is close to $18/hour while in the Permian, the starting wage is closer to $15/hour. An equipment fab shop claims a new hire with no experience will come on at $12/hour. To put these wages in perspective, WalMart recently upped its starting hourly rate to range between $13-$19/hour while one our favorite venues, Buccee’s (we stopped there three times on our way to/from Gainesville this week), advertises starting hourly wages at $13-$15/hour (includes 40+ hours, healthcare, 401k and 3 weeks paid vacation). On the surface, the relative similarity in wages would suggest folks should opt for these airconditioned jobs which potentially offer better benefits and most assuredly offer a safer work environment.
Our OFS friends claim our assessment is incorrect as the typical OFS worker wants the overtime, thus the effective hourly wage for an OFS is much higher (folks often work ~60 hour weeks). Ok, that may be right, but how do you square this view with the notion that new hires are hard to find because people don’t want to come off the unemployment benefits? We often hear this explanation as a key reason for the current labor challenge. Seems to us the individual who is willing to work 60 hours/week is not the same as the one who opts to take government benefits. Obviously, we are generalizing, a lot.
The other challenge which OFS contacts report is today’s younger generation of oilfield workers values more personal time than hours/week. Moreover, many report experienced OFS workers laid off this past year have now transitioned away from energy given the volatility of oilfield. Companies needing CDL drivers say competition from other sectors is problematic. Package all these reasons up and you have an industry which is struggling to find help. Now to be fair, we don’t think the labor market woes are limited to just the oilfield. Just this weekend our favorite pizza joint in Kingwood shutdown temporarily due to a lack of staff. Our preferred barber shop is down from five to two barbers as people don’t want to work. Help wanted signs abound. A funny thing seems to be happening.
Going back to the oilfield, several companies shared labor challenge anecdotes. One that jumped out comes from a service company manager who is now getting summer vacation requests from employees. In normal times, the company would keep a few extra staff to handle things such as vacations and illness. Given the debacle of recent years, this company runs lean with no reserve employees. Consequently, this company is concerned it may have to lay down rigs this summer due to employee shortages. Just imagine the labor challenges which could develop if a major government infrastructure plan is approved. One would think parts of the OFS sector, at current wage practices, could face even greater issues should the construction market further improve. Making matters worse, employee poaching is on the rise.
Another problem conveyed by industry friends is the cut back in formal safety/training programs. Prior to COVID, most large companies had internal training programs for new hires. We suspect many still do, but some contacts report forced reductions to these departments during 2020. In one case a company cites a transition to video-based training as it’s cheaper. We get the need to lower costs, but here’s a question for readers with kids. Do you see a greater value in classroom-based learning vs. on-line classes? We think most probably do. Therefore, shouldn’t similar logic of in-class training vs. on-line training also apply to field workers? Again, we would think so. Yet, the consequence of the 2020 industry debacle may be a structurally lower level of reinvestment in employees or perhaps less effective training methods. Again, for some, but not all companies. Nevertheless, if our theory is right, what are the consequences of less-than-stellar training should a more assertive industry recovery unfold. We don’t know, but we do know some OFS businesses today are not quite what they used to be. Further, to return to best practices, companies need higher profits in order to properly reinvest in both people and equipment. The question is how does the OFS sector get there.
As for supply chain, multiple contacts report an emerging challenge with cement. Specifically, cementing contacts claim they are now on allocation from the cement suppliers. One emerging private cement player is purportedly unable to establish accounts with cement producers as the producers are not taking new clients. Not clear yet how this will impact the market, but simplistically, if cement supplies are limited, one would think this could impact both the D&C process and potentially P&A work as well. We’ll seek more clarity this week. Sand procurement issues, meanwhile, appear to be easing as the shortages which surfaced shortly after the epic winter storm have now faded. Consequently, one sand contact tells us that leading edge 100 mesh prices for in-basin sand have reverted back to the $12-15/ton level. We had heard of several spot sales in the high-$20’s in the February/March timeframe.
Q1 Earnings Observations. It’s the best of times and it’s the worst of times. Take a quick look at Q1 earnings to date and one can see the robust performance of the E&P sector. FCF metrics are top notch, resulting in solid debt reduction progress and in some cases, the reinstatement of dividend programs. CLR generated FCF of $606M and reduced debt by $560M. Its advertised rates of return on wells exceeds 50% with D&C costs still expected to bleed lower. CNX generated FCF of $101M which allowed it to repurchase $18M in stock and reduce net debt by $70M. The company raised its FCF expectation this year by $25M to $450M and sees ~$500M/year in FCF over the next five years with limited capex spend. Not too shabby. Meanwhile OVV generated FCF of $540M and reduced debt by $467M. Strong results led OVV to accelerate its debt reduction targets by nearly two quarters. COG increased its dividend while MTDR initiated a dividend. Overall, E&P conference call commentary is generally upbeat as cash flow is strong/stable; D&C efficiencies remain stout; and most see little in the way of service cost pressure.
Contrast the healthy improvements within E&P to Oil Service. First, with the exception of ChampionX, every single service company which reported last week incurred a net loss (NOV, HP, PTEN, RES, MRC, OIS, SLCA, NBR, OII, DRQ). CHX almost joined that group, but its net margin came in at 0.6%. Not surprising, the service industry remains barely EBITDA positive; a few more companies witnessed asset impairments and/or restructuring charges while asset sales and/or equity ATM programs continue to be used to supplement cash flow. The collective woes distill into limited capex reinvestment levels, a point hammered home by NOV’s CEO on its Q1 call.
Now, should these observations offend some our E&P readership, please know that’s not our intent. In fact, we want you to make oodles of money. That said, we need to see the forest through the trees, remembering actions have consequences, a theme we wrote about nearly one year ago. With the E&P capital discipline narrative persisting, prospects for material OFS price increases feel limited given (1) significant overcapacity and (2) the continued desires for market share vs. profits at many OFS institutions. Therefore, challenges with the broader OFS community will linger. Yes, there will be a few exceptions, but for the most part, companies will continue to use band-aids and duct tape to keep equipment running vs. real investment to upgrade/rebuild (i.e. listen to the KEX call). Trifling investment in people will also continue while much needed investment in R&D and ESG will be subdued. Therefore, the only real solution which would allow the OFS space to quickly drive margins higher, a necessary outcome, is to pursue much needed consolidation. In other words, take a play out of the E&P playbook. Consolidate, slash duplicate costs and eventually raise prices. That process, we believe, is coming as even our optimistic activity outlook forecast isn’t enough to bail out the OFS complex.
E&P vs. OFS Interest. Notable differences in sell-side interest in E&P vs. OFS. We say this based on the number of analysts asking questions on the respective conference calls. For instance, here’s the E&P breakdown: CVX (12), CLR (12), HES (11), CNX (7), AR (7), COG (6), RRC (6), MTDR (5), SM (5), and OVV (4). As for OFS: LBRT (10), FTI (8), HP (6), OII (6), NBR (4), PTEN (3), AROC (3), OIS (2), SLCA (2), RES (1). The difference largely reflects the wide gap in market capitalizations as most of the reporting OFS names suffer from sub-$1B market caps. Another reason is OFS analysts keep getting fired, downsized or transitioned to other jobs (i.e. banking, IR, etc.). Case in point, the OFS sector lost another senior sell-side analyst at a bulge bracket firm last week. The bank showed just how committed they are to the energy space by purportedly making cuts to its energy research practice. One would assume this institution will eventually reduce its OFS coverage just as many others have already done. Nothing like making rash decisions right as the sector is beginning to improve.
Rig Count Commentary. Four land drillers have now reported Q1 earnings. HP is presently running 118 rigs, but expects to exit Q2 at 120-125 rigs, a +2 to +7 change. NBR’s Q1 L48 rig count averaged 56 rigs and is expected to improve by 6-7 rigs. The company, however, is running 64 rigs today, thus we suspect the incremental gains between now and the end of the quarter is likely 1-2 rigs. PTEN is running 73 rigs per its website this weekend. The company’s Q1 rig count averaged 69 rigs but is expected to improve to an average of 73 rigs in Q2. That said, PTEN expects its rig count will reach ~80 rigs by July, so a net gain of ~7 rigs. PDS reported last week. At the time of its call, the company was running 40 rigs in the U.S., but noted an expectation that the rig count would migrate into the high 40’s later this year. So, quick ballpark math, but if we assume these four companies are running roughly 295 rigs and we take the high end of rig deployment estimates, the conclusion is a possible addition of ~24 rigs in the coming months or an ~8% gain. Applying the ~8% gain to Friday’s reported BKR rig count would suggest we see the BKR rig count climb to the ~460 vicinity sometime during late Q2/early Q3. Our working rig count forecast assumes a Q3 average rig count of 447 rigs and a Q4 average rig count of 478 rigs. We’ll true up our rig count forecast after Q1 earnings season.
BKR U.S. Land Rig Count. Flat again this past week at 426 rigs.
Frac Crew Commentary. Three frac providers reported this week: LBRT, PTEN and RES. LBRT did not disclose its specific active fleet tally, but did state that Q1 averaged in the low 30’s while Q2 would also average in the low 30’s. PTEN had an average of seven active fleets during Q1 with an effective utilization of 5.5 fleets. For Q2, PTEN expects to average seven active fleets, but intends to activate an additional fleet during Q2. Finally, RES had an average of five fleets in Q1, the same as it had in Q4. The company noted it recently activated a sixth fleet. Assessing the direction of PTEN and RES is relatively easy. Each company will have activated one additional fleet during Q2. For LBRT, it’s not clear. We believe LBRT operates three fleets in Canada. One could argue the company’s guidance of low 30’s fleets in both Q1 and Q2 is flattish, but if one were to assume the company’s Canadian fleets witness normal Q2 softness due to breakup, then the implication is the U.S. active count grows. Frankly, we don’t know, but that’s our supposition. As for revenue guidance, only PTEN offered up specific commentary. During Q1, PTEN’s frac business generated revenue of $76M but this is expected to improve to $120M in Q2. The company’s gross margin is expected to improve to $9M which implies a gross margin/fleet of ~$5M.
Q1 Company Earnings Takeaways – no investment advice, just our quick recap of data points/observations we thought were noteworthy
- Consolidated revs = $296M vs. $246M in calendar Q4. Adjusted EBITDA = $20M vs. $1M in calendar Q4. HP exited Q1 with 109 active rigs, +15% q/q and has 118 contracted today. Balance sheet remains strong as cash/investments total $562M with long-term debt = $482M. The company’s North American Solutions segment achieved quarterly gross margins of $64M, a $19M sequential improvement. Included in the gross margin are $9.7M of rig reactivation expenses associated with the reactivation of 21 rigs (roughly $460,000 per rig). This quarter HP also began a plan to sell 68 non-super-spec rigs, all of which are located in North America. This decision resulted in a non-cash charge of $54M. Facility rationalization also continues as HP is downsizing its Houston rig building facility. HP called out several technology gains including the value of its AutoSlide technology which is allowing HP to land the curve earlier – in some cases 150-200 feet – thereby allowing one extra stage on the well. Increased automation is providing smoother wellbores and reduced tortuosity, an outcome which HP claims extends downhole tool life and lowers downtime events during the completion process. International rig count stands at 5 rigs (3 Bahrain/2 Argentina). No near-term incremental rigs expected internationally, but HP is bidding on work in South America and the Middle East. Calendar Q2 guidance: North American Solutions is expected to generate gross margins of $65-$75M while the U.S. rig count is expected to exit the quarter at 120-125 rigs. At that mid-point, that’s a 12% improvement relative to the calendar Q1 exit rate. International gross margins expected to be negative $1-$3M while the company’s GOM business are expected to range between $6-$9M. FY’21 capex is expected to range between $85-$105M vs. $141M in FY’20. Other Observations. HP’s transition to performance-based contracts continues to gain steam as ~30% of the company’s rig count today is under those contracts. The company ballparks the incremental cash margin impact in the $1,000 – $2,000/day range. Also, HP called out its belief the U.S. market is quickly approaching an inflection point where rising reactivation costs will necessitate higher pricing. We agree and believe a step change increase in dayrates is likely to unfold in Q4/Q1 if our rig count forecast proves prophetic.
PTEN: Consolidated revs = $241M vs. $221M in Q4. Adjusted EBITDA = $35M vs. $30M in Q4. Adjusted EBITDA margins were up ~130bp q/q. Drilling Segment: Q1 rig count averaged 69 rigs vs. 62 rigs in Q4. Current rig count stands at 73 rigs (per website). Management noted the rig count should reach ~80 rigs by June/July. Average cash margins in Q1 were $8,750/day, but included $960/day of one-off benefits. Guidance calls for Q2 cash margins to bleed lower to $6,200/day. Pressure Pumping: Averaged 7.0 spreads in Q1 with an effective utilization of 5.5 spreads. Q1 revenue totaled $76M with a negative gross margin of $700,000. Margins/revenue were negatively impacted by weather. The company will activate its 8th spread later in Q2. Guidance calls for pressure pumping revenue to jump to $120M with gross margins rising to $9M. Directional Drilling: revenue improved to $20M from $17M with gross margin rising to $3M from $2M. Q1 capex = $19M while the 2021 capex budget stands at $135M.
LBRT: Revs = $552M vs. $258M in Q4. Adjusted EBITDA = $32M vs. $7M in Q4. Big top-line improvement largely driven by the OneStim integration. LBRT refrained from providing fleet details other than stating Q1 activity was in the low 30’s. Guidance for Q2 also in the low 30’s. Presumably, this means U.S. picks up a tad and offset by a decline in Canada. We assume LBRT has 3 fleets in Canada. Good news is LBRT will host an analyst day on June 17th, so hopefully more fleet granularity will be forthcoming then. Since we do not know the company’s average fleet, it’s difficult to derive EBITDA/fleet metrics. For simplicity, we’ll assume an average of 32 fleets. On that assumption, the implied annualized adjusted EBITDA per fleet is ~$4M. This, of course, assumes a full G&A burden. Perhaps a more useful measurement is annualized Gross Profit/Fleet. On this metric, LBRT’s gross profit/fleet is closer to $6.6M, but we note this is somewhat overstated as gross profit includes some contribution from LBRT’s wireline and sand assets. Therefore, we suspect the right gross margin/fleet is somewhere in the $5-$6M vicinity. When one considers a maintenance capex burden, perhaps ~$2-$3M/year, the attendant cash flow per fleet remains low. Hence, a reason why OFS pricing must go higher. As for conference call anecdotes, LBRT continues to invest in new technology as it called out the digiFrac technology which now has ~250 hours of time on the test stand. Also discussed is LBRT’s new FracSense service, the company’s downhole measurement technology. We expect to learn more about this at the analyst day in June. LBRT’s ability to pursue R&D and enhanced technology is partially a function of its strong balance sheet. Cash = $70M with total debt = $106M. Capex in Q1 totaled $42M with the 2021 budget still expected to range between $145M and $175M. LBRT noted an expectation that fleet profitability would return to “normalized” levels next year, albeit this “normalized” level wasn’t precisely defined, but was characterized as “mid-teen’s”. We think that’s a reasonable view, but will require frac industry leaders to raise prices and withhold capacity.
RES: Revs = $183M vs. $149M in Q4. Adjusted EBITDA flat = $8M vs. $8M in Q4’20. Balance sheet remains pristine. Cash = $85M with no debt. Q1 capex = $12M with the 2021 budget set at $55M (vs. $65M in 2020). The company operated five frac fleets during Q1, the same as Q4. The company recently deployed a 6th fleet. The company stated that 2/3 of its active frac fleets are ESG friendly. Roughly 41% of the company’s Q1 revenue was tied to frac (~$75M). No real discussion on the other service lines. Limited conference call takeaways as the prepared remarks were brief and there was only one person in the Q&A.
SLCA: Revs = $234M vs. $227M in Q4. Consolidated adjusted EBITDA totaled $38M vs. $64M in Q4. Q4 results included one-time benefits of $27M associated with customer shortfall penalties, thus adjusted for this, Q1 EBITDA was up about 5% q/q. Within the Oil & Gas segment, revenue totaled $122M or flat with Q4 at $120M; however, Q4 included the aforementioned one-time benefit of $27M, thus q/q revenues actually improved 31% on an adjusted basis. Tons sold were 2.57M, +36% q/q while contribution margin came in at $8.36/ton. SandBox loads were up 19% q/q. Capex = $3.5M with 2021 capex guidance expected to range between $30M to $40M. Looking ahead, SLCA sees its Oil and Gas proppant volumes up 20-25% while SandBox volumes should be up 5-10%. Segment profitability should be up 30-35%, implying a contribution margin of ~$28M. Other observations. Mgmt stated normalized margins should be roughly $10/ton within Oil & Gas. SLCA is ramping production. The company restarted the Spart facility in Q1 while the Crane mine and the Ottawa mine are now back to running 24/7. SLCA continues to focus its efforts on the Industrial business which continues to generate greater profits than the Oil & Gas segment. On the Q1 call, SLCA highlighted various ESG friendly products which are heavy users of sand while it also called out a normal price increase for the ISP segment.
NBR: Revs = $462M vs. $447M in Q4. Adjusted EBITDA flat at $108M vs. $108M in Q4. NBR averaged 56.2 rigs in Q1, up from 53.6 rigs in Q4. As of the call, NBR has 64 rigs working while Q2 guidance calls for the average to increase by 6-7 rigs. Implies current rig count likely stable near-term, although the company did note an expectation its rig count would rise throughout 2021. NBR’s shared a customer survey anecdote whereby the company surveyed its largest L48 clients who collectively make up ~40% of the U.S. rig count. This group foresees flattish activity the rest of the year. Cash margins for L48 rigs totaled $8,466/day vs. $9,541/day in Q4. For Q2, drilling margins are expected to soften to $7,000+. ESG investments persist. NBR now has two rigs running advanced battery-based hybrid energy management solutions. A third L48 rig with this system will soon be deployed. International averaged 65 rigs, a +4% q/q improvement. NBR’s +8 rig count gain in Saudi was offset by declines in the company’s Eastern Hemisphere operation. Balance sheet remains levered. Cash = $418M while total debt stands at $2.9B. 2021 capex budgeted at $200M, of which $40M was spent in Q1.
OIS: Revs = $126M vs. $137M in Q4. Adjusted EBITDA = $6M vs. $2M in Q4. Balance sheet stable. Cash = $55M with total debt = $170M. Debt/cap = ~20% while OIS 2021 EBITDA guidance of $38-$43M implies a Debt/EBITDA ratio in the ~3x vicinity, but much lower on a net debt basis. The Offshore Products segment garnered $70M in bookings, distilling into a book/bill ratio of 1.2x. Roughly 17% of the bookings are related to non-oil and gas projects. Backlog in this segment stands at $226M, a 3% q/q improvement. Within Wellsite Services, cost controls and restructuring are showing benefits. Q1 revenue totaled $40M with EBITDA of $4M. This compares to Q4 revs of $39M and EBITDA of $1M, thus strong incrementals q/q. Q2 Guidance calls for consolidated revenues to grow 15+% q/q. 2021 capex is budgeted at $15-$20M, of which $4M was spent in Q1.
CLR. Q1 capex = $293M or ~21% of the 2021 budget at $1.4B. No change to the capex budget as CLR focused on FCF for debt reduction. During Q1, CLR generated FCF of $606M and reduced debt by $560M. The company projects FCF of $1.7B in 2021. Given the huge FCF generation, CLR reinstituted its dividend at a level which is nearly double the level prior to its suspension last year. Rates of return advertised at ~70% for Bakken wells and ~50% for Oklahoma wells. Bakken well costs expected to decline 7% y/y in 2021 while Oklahoma well costs expected to decline ~17% y/y. The company recently added a rig to the PRB with a second rig expected to be deployed soon. CLR will also add rigs to the Bakken. The company expects to average 11 rigs this year (7 Bakken/PRB, 4 Oklahoma). References were made in the company’s opening remarks regarding new equipment technologies but we didn’t see any query what these technologies are.
SM: Capex = $185M in Q1 with $230-$240M expected to be spent in Q2. 2021 budget of $650-$675M reiterated, thus implies a moderation in 2H’21 spending. The company is presently running 3 rigs and 3 frac crews in the Midland Basin. In this area, SM drilled 13 net wells and completed 14 net wells during Q1. The average lateral length is ~11,300 feet. DC&E costs estimated at $520 per lateral foot. In the company’s South Texas business, the unit is running 2 rigs and one frac crew. Average lateral lengths are ~12,000 feet. 5 net wells were drilled in Q1 with 3 net wells completed. For Q2, total net completions are expected to be 50 across the company, up from 17 in Q1. On the call, SM referenced positive initial results from its Austin Chalk exposure. This appears to be an area of growth/opportunity for the company. The company’s slide deck references SM’s use of an electric frac fleet in October 2020, although it’s not clear how SM will use this technology on a go-forward basis. The company’s ESG metrics appear commendable. One thing which jumped out to us is the company’s hedging profile which indicates 75-80% of ’21 oil production is hedged at an average price of $40.66. This would seem to argue for much more robust cash flow in 2021, all else being equal. We also wonder how this would impact the company’s spend next year.
COG: Capex = $124M. 2021 budget unchanged at $530-$540M. Q2/Q3 spend will move up but declines in Q4 such that Q4 spend/activity will be lower than Q1. The company is running 3 rigs and 1.5/2 frac crews. Q1 activity included drilling 25 net wells and completing 13 net wells. Management alluded to dropping one rig later this year. FCF totaled $138M. COG reduced debt by $88M and increased its dividend by 10%.
SWN: Capex = $266M. 2021 budget unchanged at $850-$925M. FCF was $88M in Q1. During Q1, SWN averaged 5 drilling rigs and three frac crews which allowed for 23 drilled wells and 29 completed wells. Q2 and Q3 capex will trend lower before falling in Q4. Southwest Appalachia. SWN drilled 12 wells and completed 17 wells. Average lateral length = 12,629 feet. Northeast Appalachia. SWN drilled 11 wells and completed 12 wells. Average lateral length = 13,470 feet. D&C efficiencies persist. Footage drilled/day expected to increase to 1,600 in 2021, up from 1,563 in 2020. Completed stages/day expected to average 8.0 in 2021, up from 7.1 in 2020. The company’s records for footage drilled/day and completed stages/day are 2,544 and 15.0, respectively. For 2021, the company expects to drill 70-85 wells and complete 75-90 wells.
MTDR: D&C capex = $126M. 2021 D&C budget = $525M-$575M. Sequence of capex is Q2 at $116M, Q3 at $153M and Q4 at $139M. MTDR had a record Q1 in both revenue and EBITDA. The company initiated its first quarterly dividend and repaid $100M in debt. The company’s D&C costs continue to bleed lower, largely efficiency driven. The company’s capex/foot is expected to be $730 in 2021, down from $850 in 2020 and $1,165 in 2019. MTRD averaged 3 rigs for much of Q1 but added its 4th rig in late March.
CVX: Q1 adjusted earnings = $1.7 billion. Cash flow from operations excluding working capital was $5.1B. Maintaining and growing dividend is CVX’s top financial priority. CVX board approved 4% increase to the dividend. For the first time since the pandemic, cash flow from operations excluding working capital exceeded cash capex and dividend. Capex for 1Q21 was $1.7B and down over 40% y/y. Capex guide is still $14B, but running less than budget through the 1Q, which is partially due to timing with some major capital projects that are back-end loaded. Production guidance for the year is 0-3% growth. Total Production for the quarter was 3.121MM bbls/d, which included 348k bbls/d from the Noble acquisition. In the Permian CVX is running 5 rigs and two completion crews and could add another completion crew later this year to reduce some of their DUCS. 2Q21 expect turnaround at Australia Gorgon Train 3 to reduce production by 90k bbls/d and OPEC curtailments to reduce production by 40k bbls/d. Upstream earnings increased with higher oil prices and downstream earnings declined on a swing in timing effects and lower margins and volumes due to the pandemic. Earnings impact from Winter Storm Uri was $300MM, but all upstream production has been restored and all refining/chemical units have been restarted. They have not seen any requests for oil service price increases yet. Steel costs are higher and seeing some of that in come through in the price of oil tubulars. On the labor side, the biggest impact has been on the trucking side in the downstream business as many of the drivers have gone to Amazon or UPS. CVX will close an all-stock deal for NBLX in mid-May. Energy Transition: In early stages of developing a bioenergy project with carbon capture and sequestration in Mendota, California. CVX is working with Toyota to develop commercially viable and large-scale business in hydrogen. CVX also launched a future energy Fund that has made 5 investments YTD.
MRC: 1Q21 Revenue $609MM vs $794MM 1Q20. Sales by product for the quarter were as follows: Valves, Automation and Instrumentation $241MM, Total Carbon Pipe Fittings and Flanges $150MM, Gas Products $134MM, Carbon fittings and Flanges $85MM, Line Pipe $65MM, Stainless Steel and Alloy Pipe and Fittings $29MM and General Products $55MM. 1Q21 EBITDA $24MM vs 1Q20 EBITDA of $34MM and $22MM in Q420. Net Debt is currently $250MM. The gas utilities business is a bright spot for MRC and they expect this business to exceed $1 billion in revenue by 2023. Line Pipe sales in Q1 witnessed some inflation as prices moved higher with higher (HRC) hot-rolled coil prices. Line pipe spot prices in 1Q21 were 10% higher y/y and 20% higher q/q. Line pipe pricing is expected to continue to move higher throughout the year due to rising HRC pricing. 1Q21 results, higher backlog and encouraging customer conversations all contributed to MRC’s improved outlook for the year. Total company revenue expected to grow low single digits in 2021 vs 2020. MRC expects low double-digit growth for gas utilities, modest increase for downstream and industrials and mid-single-digit percentage declines in both upstream production and midstream pipe sector. MRC took massive costs out in 2020, where they reduced headcount by 600 and closed 27 branch locations.
CHX: Revenue of $684MM, 3% below 4Q20. EBITDA = $94.2MM. FCF = $65MM (Production Chemicals EBITDA = $56MM, Production & Automation Technologies EBITDA = $35.5MM, Drilling Technologies EBITDA $7.3MM, Reservoir Chemical Technologies EBITDA -$ 600k). Still expect $125MM of cost synergies within 24 months from the merger. Guidance. 2Q expect continued positive momentum in short cycle NAM and seasonal uptick in international operations; 2Q expect revenue $700MM to $740MM driven by production-oriented businesses; 2Q expect EBITDA $97MM to $105MM. Seeing increased tender activity in the Middle East on lift and production chemicals.
XOM: Total Revenue $59B vs 1Q20 $56B and 4Q20 of $47B. Q1 Earnings = $2.76B vs loss of $610MM 1Q20. Total Capex in Q1 = $3.1B vs $4.7B in Q420 (approximately 75% upstream with balance mixed between downstream/chemicals). Total Capex in line with FY21 plan to spend between $16-19B. Capex in 2022-2025 range is $20-25B. Capital budget for 2021 was discussed at the October 2020 board meeting and finalized in November when crude was lower and there was still plenty of uncertainty around the demand recovery. Capex is likely back-end loaded, so spending could increase in the 2H21. Upstream: reported income $2.55B 1Q21 vs $536MM in 1Q20. 1Q21 Production was 3.8MM bbls/d vs 4.1MM bbls/d 1Q20. During the quarter Permian production averaged 395k bbls/d which was 12% y/y. XOM agreed to sell $1B of non-operated upstream assets in UK and North Sea with expected close by mid-year 2021. Guyana, Brazil and Permian will generate 10% returns at $35/bbl or less. 2021 outlook increased to between 410-430k bbls/d. Downstream – 1Q21 Reported loss of $390MM vs loss of $611MM in 1Q20. Petroleum Product Sales 4.8MM bbls/d in Q121 vs 5.2MM bbls/d. Chemical – reported income of $1.41B in 1Q21 vs $1.27B in 1Q20. Demand for chemicals has been in excess of GDP growth around the world and XOM believes that will continue. Dividend: unchanged at $0.87/share or ~$3.7B for the quarter. Balance Sheet: XOM targeting 20-25% Debt to Capital.
HES: 1Q21 net income $252MM vs 4Q20 net loss $176MM and 1Q20 net loss of $182MM. Total Production was 315k bbls/d, which was inline with guidance . Bakken production was 158k bbls/d which was below guidance of 170k bbls/d. Capex $309MM for 1Q21 and FY21 guidance $1.9B. In February when oil prices moved above $50/bbl, HES added a second rig in the Bakken and is currently running 2 rigs in the Bakken. HES drilled 11 wells in Q1 and brought 4 new wells online. Spud to Spud drilling days in the Bakken was 14 days in 1Q21 vs avg of 12 days in 2020. In the 2Q, HES plans to drill 15 wells and bring 10 new wells online. For full year 2021, HES expects to drill 55 wells and bring on 45 new wells. D&C costs are expected to avg $5.8MM/well in 2021 which is 6.5% reduction from $6.2MM in 2020 and 15% reduction from $6.8MM in 2019. Drilling cost $2.5MM/well and Completion Cost $3.4MM/well. Guidance for 2Q Bakken production is 155k bbls/d and full year 2021 Bakken production is 155-160k bbls/d. GOM 1Q production avg 56k bbls/d and 2Q guidance for GOM is 50k bbls/d. Full year 2021 GOM is 45k bbls/day which reflects planned maintenance and downtime. Gulf of Thailand 1Q production was 64k bbls/d. 2Q and FY21 Gulf of Thailand production is 60k bbls/d. Guyana Liza Phase 1 1Q production was 31k bbls/d net to HES. 2Q guidance at Liza Phase 1 is 20-25k blls/d net to HES. FY 21 guidance at Liza Phase 1 is 30k bbls/d net to HES. First oil from Liza Phase 2 remains on track for early 2022. HES recently announced new five-year emission reduction targets for 2025 which are to reduce operated Scope 1 and Scope 2 greenhouse gas emissions intensity by approximately 44% and methane emissions intensity by approximately 50% from 2017 levels. FCF priorities are debt reduction and then return of capital to shareholders through dividend increases and opportunistic share repos. Total Production Guidance for 2Q and FY21 is 290-295k bbls/d. The previous forecast for FY21 was 310k bbls/d.
Other Earnings: It is getting late; dinner is almost ready and we are tired of reading transcripts, particularly when the weather is so nice; therefore, we will touch on RRC, OVV, AR, and TS in next Sunday’s note. We will also highlight Q1 drilling and completion efficiency anecdotes. For all those companies who read our comments on their respective companies, we apologize in advance if we transcribed any numbers incorrectly or misread the transcript. Call our cell anytime to bark.