Frac Market Thoughts:  Mixed industry views on spot market activity and pricing.  Here’s the backdrop.  An industry market observer recently opined on the U.S. active frac market, stating a belief the U.S. frac crew count totaled as many as 220 fleets.  Subsequent to this report, DEP received inbound comments from frac market participants questioning the accuracy of this estimate.  First, we do not fully understand the tallying methodologies of all market observers, so we won’t question others due diligence and forecasting practices.  That said, this tally, which we hope for the sake of our frac friends is correct, differs from our working tally which remains in the ~200 vicinity.  Our tallying process is hardly flaw-proof.  We employ a bottoms-up approach where we individually update with frac companies and other market participants. Sometimes we can’t chat with everyone, thus an element of risk with our methodology.  That said, we believe our tallying process is reasonable and is directionally in the ballpark.  Now, the significance of our tally vs. someone else’s is not the primary driver of this diatribe.  Rather, comments made by frac companies during our query process shed light on a potential emerging theme.  Notably, companies questioned the elevated frac count estimate because the dramatic improvement would seemingly indicate robust demand.  On the contrary, we had several frac companies report a softening in the spot market while others cited expectations for more white space.  To be fair, we had multiple frac companies who disagreed with this view, but most of those players are known to have a greater proportion of dedicated fleets.  We would also submit HAL’s commentary on its Q1 call is contrary to our industry contacts observation as HAL stated a view that NAM completion activity should improve.  In a couple instances, frac contacts also report softening spot prices (or at least more competitive).

Here’s some additional color.  First, while multiple companies acknowledge growing competitive tensions in the spot market, the concerns are limited to the Permian Basin.  Reasons for the softness:  (1) incremental capacity via fleet reactivations and (2) completion of DUC projects / perceived front end loading of some E&P capex spend.  In select instances, frac companies report expectations of more E&P’s set to drop spot crews later this quarter.  Again, these comments are not universal, a very important consideration.  Frac companies who operate dedicated fleets have not experienced any price pressure while companies with more fuel efficient engine solutions similarly haven’t seen weakness on those fleets.  To this point, we know E&P companies are increasingly asking about fleet type during the RFP process (i.e. type of engine, dual-fuel capability, etc.).  As we have previously written, E&P’s don’t yet mandate the newer engines as that would likely lead to frac price increases.  Frac companies share with us that these RFP’s might inadvertently lead to lower Tier 2 quotes as frac players may believe the lower price will be needed to win the RFP and get that equipment working.  Perception vs. reality – not quite sure.  Now, just as we hear of some spot pricing pressures, we also hear of efforts to raise rates too.  One company recently implemented a $1,000+ per hour increase (~20%), although that increase was not in the Permian.  With inflationary cost pressures becoming more broad-based, the effort to raise rates should become a tad easier.  Based on a myriad of calls, it’s clear to us the pricing dynamic is both company and region specific.  At this point, we sense more companies are trying to raise rates, but the admission by some companies about spot pricing weakness is a data point worth paying attention too (we just don’t think this is a broad-based trend).

Last point.  Conventional wisdom holds the attrition thesis will become more evident as 2021 unfolds.  The rapid efforts by some to reactivate fleets with diminished fleet profitability will simply accelerate equipment wear-and-tear.  Further, there are those who believe the efforts to reactivate fleets is driven by a belief that in an M&A process, higher valuations could be ascribed to those with more active fleets.  We don’t necessarily support this notion as smart buyers should focus on profitability as well as the potential capex burden to keep existing equipment running.  Remember, skinny margins and highly-utilized equipment is a bad combo.  Moreover, industry players continue to highlight a need to operate newer generation engine equipment, thus one would think the acquisition of legacy fleets may be less tempting or at least should come at a discount, regardless of whether or not the fleets are working.

New Frac Companies:  We are tracking two new frac start-up’s.  One of these companies, Express Pressure Pumping Services, recently announced its formation on social media.  Express, we believe, is targeting the Eagle Ford with potentially two spreads operating out of the company’s San Antonio facility.  Company management has significant industry experience.  The second company purportedly now operating is Straitline Pumps.  We believe this company operates in the Eagle Ford and may have as many as three fleets.  In the coming months, we hope to learn more about each of these companies.

BKR U.S. Land Rig Count:  Flat w/w at 426 rigs.

Q1 Earnings Takeaways:  A few early themes.  Balance sheet enhancement continues within the OFS realm as PDS, CLB, HAL and BOOM all continue to allocate FCF towards reducing debt.  In the case of CLB and BOOM, both companies employed at-the-market equity programs to raise cash.  BOOM raised $25M while CLB raised $59M.  Proceeds were used to reduce debt/enhance liquidity.  PDS, meanwhile, continued to its debt reduction effort by repaying $51M YTD and a total of ~$600M since 2018.  This was accomplished largely via FCF.  But while balance sheet enhancement is a necessary process, particularly given two recent and harsh industry downturns, the need to run a business continues.  Consequently, with the cycle now in recovery mode, companies are rightly guiding to increased costs as reinstating benefits, reversing wage reductions and implementing variable compensation are necessary moves.  Finally, discussion of one’s ESG efforts and/or emissions-friendly operating practices is another key discussion topic found throughout Q1 earnings transcripts.

Q1 Earnings Observations – a few high level & abbreviated takeaways and not stock opinions

Core Laboratories:  Rev = $108M, -5% q/q.  Adjusted EBITDA = $15.8M vs. $29.5M in Q4’20.  Adjusted EBITDA margins = 14.5% vs. 25.9% in Q4’20.  Balance sheet enhancement continues as CLB’s net debt decreased by $65M, largely driven by proceeds of $59M from the company’s at-the-market equity program.  Total debt stands at $210M, of which $75M comes due in September 2021.  CLB will use cash on hand as well as its revolver to address this maturity.  Leverage ratios are improving as the company’s leverage ratio at 3/31 was 2.3x vs. 2.8x at 12/31.  Presumably this ratio will grind lower as financial performance is expected to improve while FCF will be used to reduce debt.  This would, in theory, keep CLB in compliance with its financial covenants.  Conference call discussion highlighted a number of new projects/product success.  CLB called out its work with the Turkish Petroleum Corporation on a deepwater Black Sea well.  This example was indicative of international projects beginning to spool up.  Within the Production Enhancement segment, CLB noted success with its Zero180 Oriented Perforating System.  CLB cited examples of this system working well with “smart” wells whereby fracs/perfs were completed without damaging the fiber optic cables attached to the casing.  In fact, CLB noted that to date the system has perforated hundreds of stages without incident and zero NPT.  Q2 Guidance:  CLB sees Reservoir Description revenue up mid-to-high single digits sequentially while Production Enhancement revenue is expected to be up mid-to-high teens.  ~70% of CLB revenues are International exposed, thus a more robust growth is expected to unfold in 2H’21.  Near-term incrementals will be soft near-term as CLB is reinstating previous cost reduction measures.  2021 capex is likely to be up slightly y/y.

Halliburton: Rev = $3.5B, +7% q/q.  Operating income = $370M, +6% q/q.  HAL generated FCF of $160M during the quarter and repaid $188M in debt.  Within HAL’s C&P segment, revenue improved 3% q/q to $1.9B with operating income declining by 11% q/q.  The company’s Drilling & Evaluation segment saw Q1 revenue improve 11% q/q with operating income up 46% q/q.  Looking forward, HAL anticipates the C&P segment will see Q2 revs up low-double digits with margins improving 125-150bp while in the D&E segment revenue should see mid-single digit improvement with margins up 100-125bp.  Commentary we found noteworthy. (1) noted an inflection in international activity in Q1 with the recovery set to gain momentum – completion tool orders, for instance, grew in Q1, a leading indicator of activity; (2) International work tenders has increased significantly; (3) HAL’s believes OFS underinvestment internationally will lead to a shortage of equipment as markets improve; (4) new tools/technology announced including the company’s Ovidius isolation packer; its iCruise intelligent drilling system; electric frac solutions, etc. and (5) expectation for public E&P companies to increase activity in 2H whereas privates drove the increases in 1H.   HAL is also providing more granularity with respect to its investments in energy transition, calling out geothermal opportunities in Europe and the investments being made by its Halliburton Labs business. Moreover, HAL laid out its emission reduction targets for both Scope 1 and Scope 2 emissions.  Final point, while HAL sees NAM activity improving, “we’re not there yet” with respect to service pricing.  That said, total fracturing capacity, in HAL’s view, has limited room to grow in the current pricing environment.  To be fair, the U.S. active frac crew count has improved from ~50 fleets to nearly ~200 fleets with little-to-no improvement.

Precision Drilling:  Consolidated revenue totaled $236M vs. $379M in Q1’20 with adjusted EBITDA = $55M vs. $102M in Q1’20.  Relative to Q4’20, PDS witnessed increased sequential activity with the U.S. rig count averaging 33 rigs in Q1, an improvement of 7 rigs from Q4.  Today, the U.S. rig count stands at 40 rigs.  In Canada, PDS averaged 42 rigs in Q1’21, down 21 rigs from Q1’20, but up from 28 rigs in Q4.  The company’s well service operation is up sharply.  Today, PDS is running 26 rigs, but at this time last year, no well service rigs were running.  The company continues to do a commendable job with respect to its debt reduction efforts.  Year-to-date, PDS has repaid nearly $51M in debt, bringing total debt reduction since 2018 to just over $600M.  The company’s 2021 debt reduction goal is to repay $100M to $125M.  Q1 capex totaled $8M while the 2021 budget remains unchanged at $54M.  Outlook.  PDS sees its U.S. rig count rising to the upper 40’s later this year.  Near-term, U.S. cash margins likely bleed lower by $500-$750/day, but should move up later this year a rigs should reprice with $2,000-$3,000/day improvements.  Additionally, start-up costs, which are averaging $150,000 to $200,000 per rig should moderate as well.  In Canada, the company expects to exit Q2 at ~40 rigs with that rig count moving higher into Q3/Q4.  Technology investments will continue.  PDS highlighted continued success with its AlpahAp programs.  This initiative creates tangible profitability enhancements while the technology delivers value to the E&P customer via better drilling efficiencies, among other benefits.  Observation, not a stock comment, but PDS continues to deliver on its core strategies: Debt Reduction, Revenue Growth via Technology Advancement and ESG Improvements.  On the final strategy, PDS called out the upcoming pilot of its rig-based GHG monitoring system as well as the adoption of energy storage systems.

DMC Global:  Rev = $56M, -3% q/q.  Adjusted EBITDA = $4.0M vs. $3.6M in Q4’20.  Adjusted EBITDA margin = 7%.   Gross margins improved ~200bp q/q to 23%.   Balance sheet remains strong with cash = $46M and no debt.  Q1 results were burdened by $1.0M of legal expense as BOOM is pursuing legal action against purported patent infringement.  An additional $1.5M of expense is expected in Q2.  Within the DynaEnergetics business, Q1 revenue grew 8% q/q to $38M with gross margins down ~200bp to 22%.  Q2 Guidance:  Consolidated revenue guided to $67M-$72M, or +24% at the mid-point.  The DynaEnergetics business is forecasted to have Q2 revenue of $45.5M (at mid-point) or +20% q/q.  Consolidated gross margins are expected to improve to 25% to 26% with G&A expense up $1-2M q/q due to resumption of benefits, business travel, etc.  Adjusted EBITDA is expected to range between $6M to $8M in Q2.  Of note, DynaEnergetics implemented a 5% price increase on all products effective March 30 (they believe they are out in front of this)

Baker Hughes:  Adjusted EBITDA in the quarter was $562 million, which excludes $106 million of restructuring, separation and other charges. Adjusted EBITDA was down 27% sequentially and down 5% year-over-year.  In North America, stronger-than-expected activity in the first quarter helped mitigate some of the impacts from the Texas winter storms.  BKR remains focused on three pillars: 1) transform the core; 2) invest for growth and 3) position for new frontiers.  On transform the core in Q1, the company formed a JV with Akastor on subsea drilling and sold some pressure pumping assets in Argentina.   On investing for growth in Q1, the company acquired ARMS Reliability with a presence in multiple industrial sectors that will help accelerate the digital transformation of industrial assets.   On the position for new frontiers in Q1, BKR announced an exclusive license for SRI International’s Mixed Salt Process for carbon capture.  They also announced their intention to invest in FiveT Hydrogen Fund alongside Plug Power and Chart industries.  During Q&A, a good question from our friend Chase Mulvehill at BOA around energy transition and the addressable market across the CCUS value chain.  BKR said the addressable market for CCUS for them was between $35-$40B by 2030 and the addressable market for Hydrogen for them was between $25-$30B by 2030. BKR believes oil and gas demand continue to move higher with continued discipline from OPEC+ and more vaccinations around the globe.  BKR sees upside to their 2030 long-term forecast for global LNG demand, which was previously 550 to 600 MTPA of demand by the end of the decade.  Due to recent customer discussions and some third-party analysis BKR now sees the potential for 600 to 650 MTPA of global LNG demand by 2030.  Despite the higher rig count, they continue to believe the public E&P’s are committed to capital discipline and maintenance mode spending.

Guidance – OFS – Stronger than expected activity in NAM during Q1 may provide for modestly improved outlook for full year relative to prior guide, but International is still expected to really recover in 2H21.   BKR is sticking to plan to reduce 100 facilities in 2021.  TPS – The long-term outlook for LNG is improving as countries continue to phase out coal in favor of natural gas.   Confident that 3-4 projects reach FID in 2021. Expect TPS revenue to be flat q/q.   Also mentioned 2Q margins would be flat with 2Q20, which implies 100bps q/q decline. OFE – Continue to see outlook for subsea tree awards improving modestly in 2021, but still below 2019 levels and difficult to sustain 2019 levels for foreseeable future.   Expect revenue to decrease q/q due to lower SPS and Flexible backlog conversion.  Digital – Aviation remains challenging, expect strong q/q revenue growth and op margins back to high single digits.  Other Observations: Cost rationalization a focus as BKR continues to execute on plan to reduce rooftops by approximately 100 facilities in 2021 and size product lines appropriately.  OFS business remains on track to achieve double-digit operating income margins given the significant structural cost reductions, improved operating process and the increasing use of remote operations.  From a normalized EBITDA margin standpoint, BKR sees no reason this business should not be a 20% EBITDA margin business. BKR noted relationship with remains very important; feel very good about the progression.  Also, releases of different products externally as well as the usage of internally to drive process efficiencies.


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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