A few random thoughts from this past week. Apologies for being late on our weekly note. We were having fun on Sunday and didn’t get around wrapping this up until late last night. It happens.
- We are initiating our U.S. land rig forecast. Details below, but we envision a respectable recovery.
- Recent E&P conference commentary confirms what we all know – everyone is bringing wells back on line.
- Observation/Question: Is Zoom the nail in the coffin for the traditional energy sell-side research model?
DEP Rig Count Forecast. Time for DEP to dive into the world of forecasting. Frankly, this is the part of the job we hate the most. Why? Because we don’t know what we are having for dinner tomorrow night, yet we’re supposed to predict where the rig count will be over the next few years. And some may make decisions based on our forecast? Uh oh. If this isn’t a disclaimer and word of caution, then we don’t know what is. Nevertheless, people want our views and some actually pay us for them (thank you loyal subscribers). But before we reveal the anticipated numbers, let us first give you our methodology and importantly, we begin by telling you what don’t do. We do not attempt to make a prediction on oil prices. DEP is not a commodities expert because we learned many years ago there is simply no way we know what OPEC+ will do; nor do we have a leg up on the competition with respect to a global economic growth forecast since we’re not economists either. That makes pinpointing demand a challenge. Rather, we consider the forward oil curve; we read/listen to what smart commodities experts and economists say; and we therefore assume (as well as hope) these experts are directionally correct. These big picture views collectively influence our thinking.
But years of spending time in the field tells us a bottoms up approach to forecasting is equally, if not more, important. This is why we spend so much time driving around and checking in with industry friends. And thankfully, our industry contacts allow us to often lean heavily on them. In nearly all instances, we are given honest, off-the-record feedback and history has proven these discussions frequently paint a good near-term picture. Case in point, our discussions with contacts at the beginning of April foretold a massive activity collapse and that’s precisely what happened. We weren’t so smart to independently make that call. Rather, we asked multitude of people what was unfolding within their business and the collective message told the story. We believe the Daniel Energy Partners inaugural note was relatively early with respect to highlighting an impending industry disaster. Again, the credit goes to the willingness of industry contacts to impart their knowledge, not our divine intelligence.
We again employ a bottoms up approach with respect to our rig count forecast, but a key challenge is we are attempting to predict quarters and years, not months. Moreover, another key difference this time is there is not the same level of consistency in the responses relative to what we heard the first week of April. For instance, for those who read our Bakken recap note last week, we reported optimism from local contacts with respect to Q1’21 drilling activity. The optimism is not due to wishful thinking, but their discussions with customers. Remember our note from two weeks ago, when we reported similar optimism emanating from East Texas and before that, budding optimism in the Permian. Most of that optimism surrounded frac fleet reactivations because customers were calling looking for quotes. Fast-forward a few weeks and this is now playing out. Then the message was consistent: E&P’s are going back to work. First with the workover rigs, next with the frac crews and eventually with the drilling rigs. As for the positive comments made up north regarding Q1’21 rig inquiries, let’s hope those turn out not to be a mirage as our outlook is partially predicated on these field observations (i.e. customer inquiries).
Back in Houston last week, we made a number of calls to E&P and OFS contacts. The message was a tad toned down relative to what we heard in the field. The message, however, still points to a likely drilling activity increase later this year, but some additional near-term softness is likely. Here’s the quick and dirty – E&P’s who had the most pronounced activity reductions (i.e. going to zero rigs and zero frac crews) will bring back rigs. The notion of running at zero isn’t sustainable, thus this group of E&P’s will return to work. One E&P is slotted to reactivate rigs in 2H’20 while another will activate rigs in Q1’21. Both E&P’s acknowledge a potential fast-tracking of rig additions if (1) commodity prices strengthen further and (2) it appears a momentum shift is developing. In other words, getting a good rig with a cheap dayrate may become a sooner-rather-than-later decision, particularly if you think others will follow the same playbook. Now, we also visited with E&P’s who claim rig additions will be a distant proposition for them. These companies generally did not slow down to the same degree as other E&P’s and/or have more profitable operations outside the U.S. In the latter case, the company will employ a portfolio approach to capital allocation. Makes sense. Of note, all of the E&P’s were quick to state any plans for 2021 are highly subjective as most are still dealing with challenges surrounding the here-and-now. Also, several believe their peak rig counts achieved during 2018-2019 may never repeat given efficiencies and focus on capital discipline.
Our Houston discussions also included updates with a few land drilling friends. Their outlook was also not as optimistic as what we gleaned on our Bakken trip. In one case, our drilling contact still expects to see its rig count decline over the next few weeks while two other contacts see relative stability near-term. Any visibility into 2021 is cloudy at best. Importantly, at least one of them disagrees with our more upbeat activity view. That’s ok. It takes a village.
So where does that leave us? Honestly, a bit confused. We have a general agreement over the near-term, but conflicting views on the medium-to-longer term. Consequently, we need to go with our gut, so here it is:
- We assume the U.S. land rig count moves lower by another 20-30 rigs, bottoming in Q3 (of course, now that we’ve said this, the rig count will probably jump this Friday).
- Our near-term view is based on a small data set of near-term predictions by industry friends.
- We are concerned by the rapid response by E&P’s to bring production back on line so fast.
- Several E&P’s tell us wells brought online have had no issues and in some cases produce more (in the short-term) because of a build-up of downhole pressures.
- Not making an oil price forecast, but once all E&P’s report Q2 and we can tabulate production back on line, does this cause a short-term pullback in crude price?
- In keeping with the prior bullet, we wonder what OPEC+ will do if they believe U.S. producers are effectively “cheating” – why maintain cuts if others are not?
- Meanwhile, CY’21 oil prices are hovering in the $40-$42/bbl range. Not great, but we hear from several contacts that at current OFS pricing, new well economics work. Hard to believe, but that’s what they claim.
- Notwithstanding our near-term concern on WTI, we are more upbeat medium-to-longer term as we believe demand continues to improve (more below), so we’ll accept a premise of low $40’s oil in 2021.
- Many E&P’s dropped their rig counts to zero. You can’t maintain zero activity for long, particularly when you will soon work down your DUC balance.
- Many E&P’s need to drill wells to hold acreage. Not high calorie work, but it does require a rig.
- We know some E&P’s are adding frac crews while frac pricing is low. They want to capture these rates. Couldn’t this logic apply to drilling rigs as well? Remember dayrates are still repricing lower and there’s a ton of good equipment on the fence. We hear lots of anecdotes of Tier 1 rigs being priced in the $16,000/day range. Some who have performance based rates are purportedly offering lower dayrates, but we suspect the all-in rev/day or rev/well is likely better than the headline rate implies.
- E&P’s believing in the long-term outlook for oil may just elect to lock-in good deals (i.e. secure a rig in Q4 and be ready to go in 2021).
- Keep in mind – just because you drill a well, doesn’t mean you have to complete the well, at least not right away. This means even in a flat-to-higher capex spend vis-à-vis 2H’20 run rate, money can still go to the drill bit. Why not employ a drill cheap, complete later strategy?
- E&P bankruptcies will rise this year, but once those companies emerge from the restructuring process, isn’t it reasonable to see them potentially spend more D&C dollars? We would think so.
- COVID: We believe media negativity of COVID will subside after the election. For now, report the bad news (and ignore the good news) seems to be a consistent theme across the major networks.
- A recent Department of Defense article highlighted 14 vaccine candidates with another 100 under development. That’s a lot which leads us to believe the world will be a step-change further in the COVID vaccine / anti-viral development process by Q4, right as we enter 2021 budget season. Oil prices are forward looking. Perhaps, positive drug development news will serve as renewed support for a faster reopening of the global economy. Would you take a long flight and vacation if you knew a remedy existed should you get sick? We would.
- In other words, remove the fear and people might just return to their normal lives (i.e. drive, eat out, etc.). We see this happening now as we drive around the country. More of it would be a nice uplift to the economy which, in turn, helps drive energy demand. Remember, consumer spending accounts for ~65-70% of U.S. GDP and consumer sentiment heavily influences consumer spending.
- Collectively, we are optimistic for a continued economic recovery which we believe will support stronger, not weaker commodity prices. Moreover, we believe decline curves are real which means the E&P industry will have to go back to work. Consequently, we see the reactivation of frac crews as well as a small sample of E&P’s securing quotes on rigs as a basis for our view that rig activity rises early next year.
What we don’t foresee:
- We are not one of those consulting firms who will always model things up-and-to-the-right or simply model activity levels flat. This is still a cyclical business and flat doesn’t really exist in oil and gas.
- Instead, we assume bad behavior returns as people will chase returns.
- This leads us to believe we see a recovery in 2021 and into 2022, but a fade in 2023. Can we prove this to you with a fancy model? Nope. Just call it a hunch.
- We have read recent reports of some analysts calling for $100/bbl oil. Man – I hope they are right, but we would bet they are simply looking for headlines and a chance to be quoted in the media.
- We do not see a return to ~1,000 rigs, a view shared by many of our industry friends. Drilling efficiencies are simply too good and it’s hard to paint the scenario where we are that short of crude or nat gas. That said, we would not have predicted COVID or the Saudi/Russia tiff, so anything is possible.
Finally, our forecast. The table below presents our quarterly view through YE’21 as well as a five-year outlook. We model the U.S. rig count bottoming in Q3 with an average of ~238 rigs running. We assume the industry returns to an average of ~371 rigs by Q1’21 which means we exit Q1 with over ~400 rigs drilling. We subsequently mode improvement over the course of the year with a seasonal fad at the end of 2021. This distills into an 8% y/y improvement in 2021, but a more than doubling of the rig count from where we are today. Yes, this sounds aggressive, but keep in mind our modeled recovery rate is actually a bit slower than what we witnessed in the 2017 recovery, not withstanding the fact our collapse this cycle occurred much faster.
Again, our view is a more gut, bottoms-up and guesses approach as opposed to a top-down view based on E&P cash flow modeling and a formal oil supply/demand model. This forecast, as with any forecast, is a living breathing model as it will be reviewed with each and every field tour, channel check and public company activity/budget announcements. Should CY’21 WTI prices stay in a $40-$45/bbl band during the Q4 budget season, we think we’ll be directionally right. If COVID becomes worse than we envision and people retrench, oil prices likely fade and we’ll be wrong. We are happy to walk through our modeling thoughts if you want more color, so give us a call if you like.
Recent E&P Comments: A number of E&P’s have participated in recent virtual conferences/NDR’s. The responsible one’s post updated slides on their websites or allowed their presentation to be webcast thus yielding a transcript. Some kindly issued a press release. For our public friends, it’s always helpful when you employ this approach so everyone can hear what you’re saying. For the few which we were able to review, the commentary is relatively consistent. MTDR, CLR, DVN, EOG, PE and NBL (among others) all note efforts to bring production back on line. Few provide any new detailed operational guidance, although DVN’s response to a question seems to imply its rig count may nudge lower a tad while we believe EOG’s comments suggest it may have added a rig. DVN seemed to suggest its rig count could go from 10 to 8 (it may have already done so). For EOG, we thought they bottomed at ~6 rig and the transcript reference ~7-8 working now along with five frac crews. Much of the other commentary was relatively bland, so we don’t have any juicy nuggets to impart. Again, the common theme is bringing production back on line with some referencing higher completion activity in 2H – all consistent with what we’ve been writing. And while the market clearly knows oil production is coming back on line, we are not alone in our concern about the speed of this recovery. Several articles, including one on Bloomberg on Friday, share our concern.
Energy Sell-Side Model and Corporate IR Evolving? The past few weeks have featured multiple virtual conferences and virtual NDR’s. We had a chance to catch up with a few sell-side friends and industry IR contacts to gather their feedback on the new norm. Here are a few quick observations.
- Firms are able to assemble quality virtual meetings allowing corporate clients to do 1×1’s with preferred investors.
- More meetings per day can be accomplished as there is no travel time between meetings.
- In a single day, companies can visit with best-of-breed investors from multiple cities (i.e. L.A., Kansas City, Chicago, NYC and Boston).
- Companies can be more selective in their meetings such that they can visit with mature energy investors vs. dealing with 26 year-old hedge fund analysts who live life via an excel model and foolishly believe they know how to run your business better than you do.
- Management teams can squeeze in bathroom breaks as well as take time to eat a meal.
- After a full day of 1x1s, you can go home to your family.
So what does this mean? As a former Wall Street analyst, the implications of the Zoom era is not good for the broader sell-side community. Before we explain why, let us first provide background color for our private company readers. In the past, sell-side firms would organize investor meetings either at a conference or through a non-deal road show. The conferences, for the most part, are me-too events where companies give their standard company slide deck which adds very little new color. Then the management team is shuttled off to a room where they sit trapped for hours doing back-to-back meetings with investors, many of whom will never buy the stock. Moreover, sell-side firms tend to allocate 1×1 slots to the highest paying clients (hedge funds) which is not necessarily the right investor (long-only) for the company. This same dynamic occurs on NDR’s as well. Notably, if a marketing schedule isn’t lining up well, it’s not uncommon to ask clients to take a meeting as a favor. This often becomes a waste of time as the client probably has no desire to own the stock and most likely comes poorly prepared to the meeting. For energy sell-side analysts, the situation is made worse given the lack of institutional investor interest in energy; a growing rise of ESG investing and a lack of capital markets activity. That latter is what funds the bonus pools. Package this all together and compensation moves lower. Hence, why some of the more seasoned energy research analysts have departed from equity research.
From the company’s perspective, they are frequently overcovered. Case in point, pick any mid-to-large cap company and go to the IR section of their website to see how many analysts cover that stock. Just for grins, we looked at two examples: Nabors Industries and Continental Resources. These were just random picks on our part, but what did we see? There are 30 analysts who cover CLR and 22 listed who cover NBR. Does either NBR or CLR really need that many analysts? Nope. Does the broader buyside really give much credence to what some of those analysts write/say? Nope. Yet companies with this type of coverage, we submit, are often asked to participate in a multitude of industry conferences and/or NDR’s? Why? Because the sell-side needs corporate access in order to get paid. This is why so many research teams opt for more coverage as opposed to less because it increases the opportunities to coordinate corporate access events (as well as more chances for capital markets/banking). Even during the past few months when the energy market has been terrible, we see new firms initiating coverage on already overcovered stocks. A bit surprising.
But what happens when companies realize the diminishing value of low quality NDR’s and me too conferences in part because of the success of virtual meetings? Smart ones may opt for IR efficiency just as we’ve seen a focus on efficiency in the field. Another consideration is the sad reality of very little discretionary G&A in the system, not to mention most investors are still reticent to own energy. With this backdrop, why would any company want to incur the costs of attending a me-too conference or conducting a less-than-ideal NDR? Think about it. A couple plane tickets, hotels, car service and meals are not cheap. Particularly when you travel to NYC or Boston. Forget the fact that many E&P’s and Tier 1 OFS franchises fly charter. Why not save money by arranging Zoom meetings instead? Why not save time and target investor meetings which actually matter. We think this makes sense. Therefore, if companies agree with us, we submit the implication then paints a dreary picture for the energy sell-side business model. Gone will be the days of plentiful energy specific industry conferences as the Tier 2 events won’t justify the cost, nor will the attendance justify corporate participation. If NDR opportunities also fade, it’s another reason for the buyside to stop paying the sell-side, a secular trend which has been underway for years. Don’t forget, energy capital markets activity is on life support – this is what funds bonus pools, so incentive compensation could remain weak. Finally, with growing ESG pressures and energy’s weak returns, some banks have blown up their energy research teams or slashed costs by cutting headcount. Several teams have shrunk in size; coverage lists have winnowed; senior analysts have departed (i.e. juniorization of the research field) and perhaps, we’ll see some legacy conferences go away next year. We have also witnessed a rise in podcast interviews, another cost effective way to convey a message which does not require travel. As for listed companies, we bet the cost-focused ones will take even more ownership of IR coordination, employing use cost effective tools such as Zoom in order to radically reduce IR travel budgets and minimize time out of the office. Will conferences go away completely? Of course not. The best-in-class ones stay, particularly those with a destination theme or those with a more intimate feel. But discriminating management teams may realize attendance at just a few and not all the events is right decision. Just our humble opinion, but a take is the energy sell-side model will remain under pressure for some time.