DEP returned yesterday from our ~3,800 mile odyssey through the Bakken, PRB and DJ Basins. Along the way we had time to catch up with friends across the U.S. upstream energy complex as well as conduct multiple yard drive-bys. Needless to say, the current business climate is less than ideal, but signs of life are emerging.
- Rig count inquiries developing – sharp increase in Q1’21 forthcoming?
- More signs completion crews will go back to work
- Well service rig reactivations persist
- Industry leaders’ desire for M&A remains high – our suggestion to help accelerate the process.
- BKR rig count declines again, but appears to be bottoming.
- Permian tour: Heading back to the Permian in two weeks (June 29 – July 1)
Rig Count Expectations: The Wyoming/North Dakota/Colorado rig count has been decimated. Per BKR, these three states collectively operated an average of ~115 rigs during the 2018 and 2019 timeframe. Today, this number stands at 18 rigs. While there is little reason to expect the rig count in these states to inflect higher in the coming months, quoting activity for Q1’21 tells a different story. In Wyoming, we visited with a land drilling contact who is presently running two rigs. Based on inquiries, the company sees an opportunity to operate as many as 12 rigs during the first quarter of next year. Yes, there are no commitments with these inquiries and as we all know, things change quickly in energy these days. But, E&P desire to add rigs in a $35-$40 oil world seemingly exists. Now, we didn’t just hear this anecdote from one person. We like to sanity check our data points, so we visited with a capital equipment/rental player in Casper. We shared the land driller observations to which this contact agreed. Specifically, this company operates primarily in the PRB where there is one rig running today. Our contact walked us through its customer list and these customers purported rig count expectations. He quickly arrived at 10 rigs in the PRB in early 2021 (and these are name-brand E&P’s). Keep in mind, he’s PRB focused while our drilling contact is CO/WY/ND focused, thus his count should be lower. As important, the cap equipment/rental contact’s product is used in the front-end of the D&C process, therefore this contact interfaces with customers’ drilling departments. In other words, those discussions are apropos when contemplating rig count direction.
What does this mean? For one, we doubt many market forecasters are calling for a huge spike in land rig activity, at least not in Q1’21. We chatted with one leading investment bank who is forecasting a ~10% or ~25 rig q/q improvement in drilling activity in Q1. A 10% improvement may sound like a lot, but it’s really not when one considers the industry is coming off such a low base. Perhaps, the research team doesn’t want to stick their neck out due to fear of getting fired or being wrong. Since we are our own boss and don’t intend to fire ourselves, we’ll endeavor to be bold. Specifically, if the Bakken/DJ/PRB basins can potentially witness a 3-4x improvement in activity (i.e. do the math on what our private contacts say and then discount that) then other basins such as the Permian should see an even greater increase. If not mistaken, don’t some of the areas in the Permian work better at lower price decks? Gassy areas may see some increase, albeit less robust. Blend these together and assume oil prices stay in the $35-$40/bbl window, then it’s entirely reasonable to see the U.S. land rig count increase 200-250 rigs in Q1’21. This amounts to an average weekly gain of 15-18 rigs. In the 2017 recovery, the weekly improvement was ~12 rigs/week in 1H’17 while in 2010, the recovery averaged 15 rigs in 1H’10. On this point, we will be finalizing our land rig forecast this week and will include it in our weekly summary next Sunday evening, but our gut says a U.S. land rig count in excess of 450 rigs by the end of Q1 is not crazy. This, of course, assumes we don’t all succumb to COVID and Saudi does not destroy the oil market again (i.e. the forward curve stays in the $40 vicinity).
Completion Crews: We continue to hear anecdotes of more frac crew demand. Admittedly, most of the evidence points to August/September as the primary window when people want crews, but a few examples of quicker reactivations abound. Notably, in the Bakken we learned of three private E&P’s who wish to add crews. In one case, the desire for a crew now vs. later is the ability to get a “hot” crew as well as to benefit from lower pricing. The lower pricing data point remains a point of frustration for us as multiple frac companies regularly tell us where leading edge bids are. In one case, a frac company with exposure to the Eagle Ford and Haynesville claimed most recent bids by larger peers for high pressure work were in the $4,500/hour vicinity vs. their pricing closer to $10,000/hour. This is horsepower only. Whether the winning bids were precisely that low, we do not know, but the purported disparity between bids suggests some continue to opt for market share vs. returns. We understand the rationale to keep crews working, but we simply disagree with the notion that losing money on work makes sense.
Well Service Rigs Returning to Service: This is a development we’ve written about in recent weeks and we saw evidence of this during our tour. Here’s the situation: rigs are going back to work as E&P’s seek to return wells to production. In fact, we visited with one E&P who claims they too will soon follow the path of their peers and will begin calling out rigs. The herd mentality is alive and well. This means E&P’s will begin to respond to higher commodity prices as a group which sometimes means they will be their own worst enemy. Lots of inbound calls for equipment is like red meat for service companies. This should be the point when smart companies test the water with price increases. To be fair, we do not expect any consequential price recovery in the next 1-2 quarters, particularly not for well servicing given how wildly oversupplied it is. Other well service thoughts – P&A activity is one bright spot as potential mandates from the state/federal authorities, along with potential funding, could spur incremental P&A activity. One well service company we visited acknowledged this would be an area of focus/investment in the coming quarters.
M&A and Other Governance Thoughts. Everyone knows M&A is needed, but various reasons seem to delay the inevitable (i.e. balance sheets, relative valuation disagreements, management egos, inept and/or sterile boards, etc.). What we continue to hear from our private company contacts is a desire to pursue M&A – lots of people discussed this on our tour. In some cases, we have interested buyers. In other cases, we have interested sellers. Here are our quick suggestions which might expedite the M&A process. First, we believe all management teams should immediately be provided a three-year severance provision in the event of a Change of Control whereby the Change means you’ve been bought or merged. This should give management enough incentive to get a deal done since many of them have equity which is underwater. We know this suggestion may offend the rank-and-file. Here’s our rejoinder. The OFS industry will be unlikely to achieve meaningful (and sustainable) pricing recovery as long as it remains fragmented. This means the wage cuts and benefit cuts incurred in recent quarters could last longer than desired. It also means incentive comp may be a distant memory as it too could be slow to recover.
In our humble view, higher compensation and job security should arise from working at a more profitable company. This, we submit, could be achieved for companies who compete in a more consolidated sector. Therefore, if paying people to go away in order to effect industry transformation is what’s needed, let’s get it done.
For private companies who are open to doing deals, be realistic with your expectations. Yes, your relationships are probably really good. Yes, your customer service is also probably pretty good too as you don’t have the bureaucracy of a public company. Unfortunately, most OFS equipment, including yours, is largely the same and asset values are depressed due to oversupply. Consequently, don’t expect a lucrative purchase price (at least not in this market) and don’t expect it all to be paid at close. A few thoughts: (i) be willing to take stock so you can ride a recovery; (ii) understand a portion of the purchase price should be deferred such that you don’t quit and immediately go start a competing business; and (iii) be willing to participate in some earnout as a means to achieving the value you think you are worth. Why? The industry has seen too many people build/flip companies only to go back and do it again. This means public companies need to walk a fine line and pursue rational consolidation. They simply can’t be the estate planning department for their respective industry sector.
Finally, as a subscription-based service, we prefer more companies, not less. This equates to more potential subscribers and hopefully more revenue. So, broad-based industry consolidation probably hurts us more than it helps us. At the same time, we know the OFS industry needs to make positive cash flow and we believe OFS employees deserve to make a good living. This takes a combination of higher activity and higher pricing. The latter, we contend, requires consolidation.
Notwithstanding our prior commentary about realistic seller expectations, Daniel Energy Partners would gladly entertain buyout offers with an excessive purchase price, all cash at closing, no non-compete provisions and a generous contract to stay. We promise to behave.
BKR Rig Count. Down again. The BKR U.S. land rig count fell 5 rigs to 266 last Friday. This is the smallest w/w decline in both rigs dropped and percentage decline since late March. Not ready to call a bottom just yet, but it certainly feels as if it will occur sometime in the next few weeks. Obviously, not a bold prediction at this point. As a friendly reminder, our original prophesy of a 150-200 U.S. land rig count trough which we made in early April appears too conservative. Seems like a 225-250 is a bit more appropriate.
CNX Resources Operational Update: It’s not often an E&P will publicly praise a service company, but kudo’s to CNX who highlighted this week the success it is having with an Evolution Well Services fleet. The company reported the completion of an eight well pad which used an electric frac fleet. The company estimates it used 140,000 Mcf of its nat gas to power the fleet which resulted in fuel savings of $2.4M. Also, CNX averaged 1,570 completed lateral feet per day with a peak of 2,600 lateral feet in a 24-hour period. Further, it reported two PA Utica wells were recently drilled in record times.
As always, this is not investment research as we do not attempt to make any investment recommendations. We’re not good stock pickers anyway which is why we left that side of the business. Also, if you have not subscribed to DEP research (i.e. no commitment on your part to pay yet), we would really appreciate your support and a chance to visit with you about the pricing methodology.