Back from vacation yesterday, so today we nerded out, spending all afternoon reading Q2 earnings call transcripts and IR slide decks. Below are a few takeaways.
- E&P Capital Discipline Persists – Focus on Debt Reduction, Liquidity Enhancement
- Efficiency Gains – Drilling & Completion Improvements Persist
- Well Cost Reductions – Is This Really A Celebration?
- OFS Q2 Results
- Another New Frac Start-Up?
- BKR U.S. Land Rig Count Flat last week at 239 rigs
E&P Capital Discipline. We reviewed transcripts/releases for eleven E&P companies. We will review last week’s OFS transcripts on Monday. The consistent theme thus far is a commitment to capital discipline. Yes, some companies are taking 2H’20 capex dollars higher vs. Q2 spending (OVV, QEP, CXO), but there are also those who will spend less, either a function of budget shortfalls or timing (SWN, CVX). For those willing to opine on a potential 2021 framework, most see flat-to-down spending (COG, AR, CXO, CNX, HES, OVV) while only a couple reference potentially higher y/y spending (SM) – in some cases, this is our interpretation of comments as opposed to firm guidance/comments. On the one hand, flat-to-down sounds bad, but flat-to-down, we believe, also means higher than the Q2’20 run-rate, which is good. The question is just how much higher. Based on the tone of Q2 calls, we walk away with a feeling of “not much” but we aren’t fully prepared to throw in the towel for 2021 as there is little upside for any E&P company to highlight increased activity next year when the forward curve for oil is ~$42/bbl while nat gas is only ~$2.75. Also, Wall Street is more concerned with returns (i.e. dividends, buybacks) vs. production growth. Therefore, the best strategy for E&P execs is to preach discipline and lean on the valid premise that it’s too early to make a definitive call for next year. In several cases, the very large E&P’s simply point to specific dates in late Q4 or early Q1 when they make formal announcements on spending.
The capital discipline theme this quarter yielded plenty of discussion on debt reduction as well as dividend discussion. Companies such as CXO, SM, EQT, CNX appear to us to be laser focused on debt reduction. Others, meanwhile, intend to live within cash flow. Some allude to using free cash flow from unexpected higher commodity prices to fund a variable dividend. At least that’s under consideration. One thing this cycle taught us is fixed dividends for oil service and E&P’s are generally not fixed as the unwind in commodity prices and fight for survival resulted in dividend reductions/suspensions for many upstream participants. Thankfully, analyst commentary in the select earnings Q&A sessions seem accommodating to the notion of a variable distribution. In our opinion, this is a smart strategy. Don’t over commit oneself and give flexibility in case another opportunity presents itself. We are not a fan of buybacks as it seems those tend to occur at the top, not bottom of a cycle. At the bottom when prices are low, the fear of spending cash precludes many from repurchasing shares even though that is, in our opinion, the best time to do it.
Continued Efficiency Gains: Our E&P conference call data points below identify a few E&P’s reporting further efficiency gains and/or higher service intensity. The pursuit of longer laterals is a consistent theme, but we don’t see much with respect to sand intensity or tweaks to completion designs. The primary efficiencies reported are faster drilling and completion times. EQT is a notable star this quarter as management provided specifics with regard to its ability to do more with less. In its case, it will use less rigs and crews yet have no impact to production.
Well Cost Savings: Q2 earnings season highlights numerous examples of E&P’s waxing poetic about the tremendous reduction in well costs. This bravado is a double-edge sword. On the one hand, the industry is getting smarter. Better equipment designs, enhanced logistics planning, improved water infrastructure and completion techniques such as simul-fracs all speed up the drilling and completion process and that reduces costs. This is good. But a big chunk of the savings comes from oil service price concessions. In many cases, these concessions were made on what some believe was already unsustainably low pricing. Most E&P’s were asked about the make-up of the savings as well as the durability (i.e. what comes from efficiencies vs. service company price concessions). On this point, there was little in the way of specifics, rather ranges were provided. Generally, service company price concessions represent about 25-50% of the total well cost reductions. Hard for us to debate the ranges. Interestingly, several E&P companies suggest current well costs could still bleed lower. This we do question as it’s simply not wise to make your service providers work for negative EBITDA. At some point, those service providers might not be around. With restructurings on the rise and consolidation just around the corner, it seems to us we will see OFS pricing bleed higher in 2021.
OFS Financial Results = Weak: Q2 results, as well as the growing list of OFS bankruptcies/restructurings, is a warning signal to the U.S. upstream industry. Something needs to give or else the wherewithal for the OFS sector to efficiently service you will fade. The table below offers a snapshot of Q2 results. In addition, we offer a few simple observations.
Take a look at the FCF results for those whose core focus is pressure pumping (we define as 1H’20 EBITDA annualized less capex). Note all of these companies reported negative EBITDA. For what it’s worth, we use each companies’ reported Adjusted EBITDA. We point this out as we do not always embrace every companies adjustments as some elevate the adjusted EBITDA value by including non-recurring charges, some of which are cash. For example, equity-based comp is often added back as it is a non-cash expense. Since it is a recurring expense to an investor, we personally believe it should serve as a penalty. That said, for the sake of speed, we grabbed each companies Adjusted figure. Now, we annualize this figure and reduce it by each companies stated 2020 capex plan. Point is the amount of “Free Cash Flow” for these companies calculated under this method is not impressive. In fact, it might actually be worse if one considers the 2H’20 results are more likely to mirror Q2’s results, not Q1.
Other companies, such as the land drillers, screen a bit better, but keep in mind, these companies have had the benefit of take-or-pay contracts. The trajectory of EBITDA may actually be lower into Q3/Q4 as rigs reprice. Meanwhile, a basket of these companies are burdened by too much debt, thus one would think the ability to deploy cash flow back into equipment upgrades, etc. is limited, or at least, it should be.
Finally, Adjusted EBITDA is not cash flow – we know this. Our exercise is simply meant to be for discussion purposes and to keep this an apples-to-apples comparison. Moreover, our point is to illustrate the unsustainability of today’s OFS market. Knowing this is a key reason we are often frustrated by E&P’s seeking accolades for their reduced well costs. Yes, we want them to do well, but we also want those who support them to do well. Remember, when a capital intensive business does not generate sufficient cash flow, it’s hard to reinvest in oneself. We are seeing this now with cannibalization on the rise. Further, with the industry still burdened by too much debt, free cash flow, when it’s generated, probably needs to go towards debt reduction first. Now, take this one step further – only those select few companies who enjoy pristine balance sheets have the wherewithal to truly and liberally reinvest back into their business. Smart E&P companies who seek partners as opposed to short-term low-bid contractors should take note.
Another New Frac Start-Up? Another inbound inquiry from an OEM contact who reports a potential new start-up. This management group, whom we have not personally identified, but are told came from a top 10 player, is purportedly seeking to build 40 pumps. The OEM would sell a portion of the OEM content on the trailer, thus we believe there is some credibility to this report. We believe the assets, if actually purchased, will go to the Permian. While there is still much digging to be done with this particular anecdote, one reason we believe there may be some merit is because of the small, but growing call by E&P’s to have best-in-class, emission-friendly equipment. As this equipment is in the inquiry stages, one would surmise it would not come to market until 2021, thus to apply today’s pricing/utilization framework may not be wise. Moreover, we have heard one anecdote of a leading Permian E&P shifting its completion service requirements to those players who offer either an electric and/or Tier 4 dual fuel solution. Perhaps this buyer sees this trend growing, thus a chance to quickly take share while its peers can’t reinvest. We also believe some of the OEMs are/will be trying to introduce new emission friendly engine technology. Could this potential start-up potentially be subsidized somewhat from an OEM seeking to gain traction? Not quite sure yet, but a reasonable query. So, while we don’t see this as an imminent threat and while we have not yet received a second confirmation on this potential start-up, our OEM contact is credible, thus we write about it. Obviously, as we learn more, we’ll provide more color, but our gut says that companies who have best-in-class equipment will win, particularly as pressures for ESG friendly services/equipment grow.
E&P Earnings Highlights: These are a few nuggets pulled from each company’s earnings release, conference call transcript and investor slides. There is much more information available for each of these companies, but these are activity/spending related data points which we find interesting. We also focus on just the L48 data points.
- D&C Capex Budget: No change. Remains at $750M, down 41% y/y. The original 2020 budget was $1.15B while 2019 capex was $1.27B.
- D&C Q2 capex was $180M.
- 1H’20 Capex = $489M or ~65% of the 2020 budget.
- 105 well completions expected in 2020, down from 131 in 2019 and 163 in 2018.
- YTD, the company has completed 69 of its 105 wells.
- Capex will move lower in Q3 and again in Q4.
- The company is running one rig and two frac crews. It previously released three rigs and two frac crews.
- During its Q1 call, AR noted plans to stick with one frac crew for 2020, but it picked up a second crew to complete some pads.
- The company will likely reduce to one crew later this year.
- At this point, the company sees no “temptation” to increase activity.
- Drilled 11,253 lateral feet in 24 hours, a U.S. record.
- Completion stages per day totaled 8.7 in Q2’20. This is up from an average of 5.8 in 2019. The company’s record is 13.0 in one day.
- In Q2, the company set a record with one pad averaging 9.6 stages/day.
- Average lateral length in Q2 was 12,897 feet, up from an average of 11,062 feet in 2019. The company’s record is 16,320 feet.
- Drilling days declined to 10.4 in Q2 from an average of 11.4 in 2019. The company’s record is 8.0. This is spud-to-spud.
- AR’s average Marcellus well cost was $11.6M in its 2019 budget, but recent AFE’s are closer to $8.5M. 2H’20 objective is $8.1M. A potential 30% reduction and assumes a 12,000 foot lateral.
- Balance sheet enhancement remains a central objective.
- Outlined a 7-year plan to generate $3B in free cash flow.
- 2020 D&C capex is reaffirmed at $330-$380M with non D&C capex of $140-$170M (thus total 2020 capex of $470M to $550M).
- For 2021, the early capex expectation is for total capex of $440M – not clear to us what’s D&C.
- Believes it can meet its production plans with just one frac crew.
- Operating one drilling rig and one frac crew. During Q2, CNX had as many as two drilling rigs operating.
- The company drilled 8 wells in Q2 and completed 11 wells.
- For 2021, CNX plans to use one drilling rig and one frac crew, thus flat activity from here.
- CNX uses an electric fleet from Evolution Well Services.
- CXO is maintaining its 2020 capex budget at $1.6B.
- Q2 capex = $312M with 1H’20 capex = $868M.
- Roughly 54% of 2020 capex has been spent.
- Averaged 11 rigs and four frac crews in Q2.
- Plan is to average 8 rigs and 4 completion crews in 2H’20.
- Averaged 18 rigs and seven frac crews in Q1.
- Drilled 63 gross wells in Q2 vs. 89 gross wells in Q1.
- Completed 45 gross wells in Q2 vs. 99 gross wells in Q1.
- The 2020 plan calls for drilling 180-200 gross wells and completing 210-230 gross wells.
- Implies ~40 more wells to be drilled and 76 well completions in 2H20
- Well costs reduced to less than $800/foot, a ~30% reduction from a year ago.
- Implemented a voluntary separation program.
- Not as granular as most E&P’s.
- With respect to L48, it will see a 75% reduction in development capital spending from Q1’20 to 2H’20.
- The company’s slide deck suggest development capex in Q1 was in the $1.2B range while 2H’20 quarterly spend looks closer to $300M.
- CVX highlights a 2x improvement in lateral feet drilled per rig from 2018 through today.
- The company is running 4 rigs and one frac crew in the Permian.
- Our sense is CVX stays at these levels for the balance of 2020.
- Q2 Capex = $303M. 1H’20 capex = $512M.
- 2020 Capex guided to $1.075B to $1.175B.
- Reduced debt by $417M. This was a focal point on the call/IR slides.
- Drilled 10,566 feet in 24 hours.
- EQT has witnessed a 63% increase in horizontal feet drilled/hour since Q2’19.
- Pumping hours per month up from just under 300 in Q3’19 to nearly 350 hours in Q2’20.
- Stages per month at roughly 190 in Q2 vs. ~165 in Q3’19.
- EQT will use less drilling rigs and frac crews due to efficiencies.
- It had planned to run 3-4 HZ rigs and 3-4 frac crews.
- Now it will run 2-3 HZ rigs and 2-3 frac crews.
- Reported $680 per foot well costs, vs. a goal of $730/ft.
- This compares to $745/ft in Q1 and over $900/ft in 1H’19.
- Significant internal reorganization post-new management.
- Employs an electric frac fleet.
- Company believes it will save 9M gallons of diesel using this fleet.
- 2020 capex budget remains at $1.9B.
- Had been $3.0B, but was cut to $1.9B las quarter.
- Bakken rig count reduced from 6 to 1.
- Likely stays at 1 rig.
- Believes it can hold Bakken production flat in 2021 with a two rig program.
- Noted the 2021 capex plan is likely to be flat-to-down with y/y reductions in the Bakken, offset by increases internationally.
- Management claims it wants $50 WTI before bringing back a rig to the Bakken.
- Bakken capex totaled $181M in Q2, down from $322M in Q1.
- Drilled 17 wells in Q2 vs. 41 wells in Q1.
- Completed 31 wells in Q2 vs. 50 wells in Q1.
- Spud-to-spud times reduced to 11 days in Q2, vs. 12 days in Q1 and an average of 14 days in 2019.
- Will likely spend at the low end of its 2020 budget.
- Guiding to $1.8B of ’20 capex vs. the range of $1.8B to $1.9B.
- Recall, the original budget was $2.7B, thus 33% below the original budget.
- Q2 capex was guided to $300M, but OVV came in at $252M.
- 1H’20 capex = $1.04B, leaving $760M remaining in 2H’20.
- Company committed on Q2 call to use all excess cash flow to debt reduction, not additional drilling.
- Company will resume completions in Q3.
- Highlighted Permian Simul-Frac completions which are yielding savings of $350,000 to $400,000 per well.
- OVV wants to apply Simul-Frac’s to other basins.
- In the Anadarko, OVV has achieved 20 hours of pumping time per day.
- Reminder: OVV dropped from 23 rigs to 7 rigs. It is running 3 in the Permian, 2 Anadarko and 2 Montney.
- D&C costs: Permian are at $550/1,000 lateral feet vs. $640 in Q1 and $680 in 2019.
- D&C Costs: Stack are at $520/1,000 lateral feet vs. $540 in Q1 and $640 in 2019
- Company sees D&C costs lower going forward.
- Discussed a potential $1.4B to $1.6B plan in 2021 which could require 7 to 10 drilling rigs.
- 2020 D&C capex budget tweaked lower to $325M-$360M vs. a prior $350M-$380M.
- The original 2020 D&C capex budget was $520M-$565M, thus at the mid-point, the revised 2020 plan is a 37% reduction.
- Q2 capex totaled $37M. Q3 will be essentially flat q/q, but Q4 capex should increase to ~$95M. Q1 was $180M.
- The company suspend completion activity in the Permian in March and released one rig there as well.
- It will pick up a second Permian rig in September and will resume completion activity in November.
- In the Williston, QEP has completed its completion activity.
- In Q2, QEP drilled 12 Permian wells and 6 Williston wells.
- Average Permian lateral = 11,099 feet.
- Average Williston lateral = 12,760 feet.
- QEP originally planned 8 refracs in 2020, but it will now do 5.
- The company has 100 remaining refract candidates.
- Refrac costs are roughly $3.9M per well, down from $5.2M in 2018.
- The company expects to place a total of 44 wells on production (vs. an original plan of 69 wells).
- QEP reports an average of 3,867 completed lateral feet per day in the Permian (up from an average of 2,583 feet in 2018/2019).
- Highlighted cost cutting measures.
- QEP has reduced headcount by 60%.
- Cash G&A is down 60% since 2018.
- QEP highlights its current 2021 capex plan which calls for flat y/y capex, with most money going to the Permian.
- The 2021 budget will be 70% 1H’21 weighted.
- Revised 2020 capex plan is $610M to $630M – down ~26% vs. original budget and down 39% y/y.
- Company has drilled 45 wells YTD in the Midland Basin with 32 remaining.
- Company has completed 29 wells YTD in the Midland Basin with 39 remaining.
- SM is running 4 drilling rigs and one frac crew – all in the Midland Basin.
- The company plans to drop a rig in October.
- The company plans to add a frac crew in October
- D&C costs in the Midland Basin expected to be $560/lateral foot in 2H’20 vs. $600/lateral foot in April.
- Lateral lengths to average 11,430 in 2020, a 23% increase from 2017 levels.
- Company reports its sand costs are 49% lower in June 2020 vs. January 2019.
- 95 DUCs as of June 30, 2020.
- 2021 capex would likely be up slightly with more emphasis on completions.
- Drilled 30 wells in Q2 vs. 38 wells in Q1.
- Completed 31 wells in Q2 vs. 22 wells in Q1.
- 2020 budgeted wells drilled = 90-100, thus 22-32 left to be drilled.
- 2020 budgeted well completions = 90-100, thus 37-47 left to complete
- SWN expects to exit 2020 with 20-30 DUCs
- Total 2020 capex budgeted at $860M to $915M
- The high end of the 2020 capex range was previously $940M.
- Q2 capex = $238M. YTD capex = $470M.
- Average lateral length – Southwest Appalachia = 11,469 feet.
- Average lateral length – Northeast Appalachia = 9,693 feet.
- Well costs coming in at $691 per lateral foot vs. original guidance of $730.
- SWN expects costs to average $650 per lateral foot in 2H’20.
- In Q2, SWN averaged 5 drilling rigs and 4 frac crews.
- Company is running two rigs today and will exit Q3 with one frac crew running.
- Thus, capex moves lower in Q3/Q4.
- Our impression is the company will increase activity in Q1, thus a front-end loaded budget in 2021
- Permian rig count reduced from 12 rigs to 7 rigs.
- Williston rig count reduced from 3 rigs to 2 rigs.
- Suspended completions, but has now brought back two crews (1 Permian / 1 Williston).
- Will add another Delaware crew in August.
- Will drop another Williston rig this year.
- Should exit 2020 with 35-40 DUCs.
- Highlighted WPX wells outperformance of Felix wells (i.e. potential upside in our view).
- Page 5 of IR slide deck walks through difference in WPX vs. Felix well completion design.
- Q2 capex = $188M vs. $313M in Q1.
- 2020 capex budget now $1.05B to $1.15B (previously $1.1B to $1.2B)
- WPX believes it can maintain flat production with a capex budget of $800M to $850M.
No investment advice. Just observations from earnings season. Hopefully no typos. We’ll summarize more calls/transcripts this week.
Hope everyone had a great weekend.