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2024 Market Outlook: Caution in Near Term But Optimistic in Medium-to-Longer Term



Making a strong call on the 2024 outlook is tough. Naturally, we want to wax poetic and author positive missives given the large industry readership of the EWTC; however, WTI is unexcitingly hovering in the $70-$75/bbl vicinity while front month natural gas languished in the mid-$2’s for much of Q4 but has recently (and thankfully) crept above the $3 mark. 

By historical standards, today’s oil price would be viewed as supportive for industry activity growth, but with WaHa trading near $2.25/mcf (and closer to $1.50 for much of Q4), realized prices for Permian producers (~52% of the rig count) are less generous than what the current WTI price implies. 

Meanwhile, front-month natural gas prices, which admittedly have rallied YTD, still feel low, particularly as a potentially strong winter front is soon to hit much of the U.S. Further, the CY’24 strip at ~$3.10/mcf is hardly the requisite nitroglycerin needed to juice an activity acceleration, at least not in the near-to-medium-term.  

Thankfully, the 2025 strip is respectably trading in the ~$3.75/mcf vicinity. Finally, don’t forget three other factors. First, there is the lingering reality of E&P capital discipline, a theme which remains alive and well. Second, the industry is doing far more with less, due to D&C efficiencies. And third, in an era of Tier 1 inventory scarcity, the notion that a public E&P company would race to develop its best rock seems unlikely. Package all of this together and the 1H’24 backdrop (and possibly all of 2024) for the domestic onshore oil service and capital equipment complex is an environment best characterized as fragile or perhaps steady if one were to be generous. Of course, nuances exist, a point which we will elaborate on shortly.

2023 Started Slow But Picked Up Towards End of Year

As we look back on 2023, the industry entered the year with a domestic onshore rig count of 762 rigs, per Baker Hughes. We exited the year at 602 rigs, a ~21% decline. We are at 601 today. Completion activity also moderated as the active frac crew count declined as well.  Recall many spot-market-focused frac players during 2H’23 called out white space on the calendar.  Multiple public frac companies similarly cited declining active fleet counts throughout the year.  

Yet, despite declining onshore activity, U.S. oil production grew from 12.4 million b/d in October 2022 to 13.2 million b/d in October 2023, according to EIA 914 data (there’s a two-month lag with the data).  The EIA further assumes record U.S. oil production in 2024.


Similarly, natural gas production has been robust as well. U.S. natural gas production is up 2.6% year-over-year during the same time frame despite a 23% year-over-year reduction in gas-directed drilling activity. Thank you associated gas. 

The result is elevated natural gas storage levels with current storage of 3.49 Tcf, +10% higher than the five-year average. To be fair, the most recent EIA 914 data does show flat U.S. oil production in October, with a modest month-over-month decline in North Dakota, but important regions such as Texas still show growth. Thankfully, Louisiana gas production is rolling, down month-over-month in October, but keep in mind overall U.S. nat gas production still grew month-over-month in October.  One would think reduced D&C activity will yield more visible production declines when new data is released in Q1. Such an outcome, coupled with cold weather, is needed to help bring storage levels back to historical averages.
Reviewing the EIA 914 data from the 30,000-foot perspective, a few things stand out. First, hats off to the U.S. upstream industry for its ability to grow production in a lower activity environment. That’s a strong testament to the concept of doing more with less.  It is also a reflection of ongoing completion efficiencies. Arguably, the rise in simulfrac, improved drilling techniques as well as longer laterals are playing a role. Yet, the virtue of being really good comes at a cost which, in this case, is growing inventories and lower commodity prices. And complicating matters further is the potential implication of rising U.S. oil production on OPEC+ (i.e., Saudi policy). For much of the year, OPEC+ has been playing the role of rational guardian, cutting production as necessary to support oil prices. 

Unfortunately, not everyone has been playing ball, making us and others wonder whether the global upstream community will be flipped the bird, as was the case in 2014 when Saudi elected to defend market share. Loyal and longtime EWTC members know that international and OPEC prophesies are not at the core of Daniel Energy Partners research focus, but it seems odd to us that Saudi would willingly and continually opt to cede market share to others.  

Here’s another consideration worth remembering: Q4 earning season is just weeks away from now. This is a time when public players must discuss upcoming spending, activity and production plans. It’s not just Wall Street who reads these press releases, but surely other global players do as well. For this reason, in an environment where oil and natural gas prices and outlook are top of mind for investors, it would seem unlikely the largest, best-of-breed U.S. public E&P players would deviate from the capital discipline narrative and attempt to extol growth. Rather, we would expect more restrained comments. If that plays out, it’s not bullish for near-term OFS activity.

Going back to the U.S. onshore market for a moment, another key consideration is the risk of further M&A within the E&P community. This, by the way, is not a new story. For a moment, reflect on the companies who are going or have gone away – Hess, Pioneer Natural Resources, CrownQuest, Earthstone, Southwestern, PDC Energy, Callon, Rockcliff, FireBird, Tug Hill, Patriot Resources, Vencer, Tall City among others. Reminds us of the annual ‘People We Lost’ articles which are published this time each year – a bit depressing. And for friends in the OFS sector, this should be a red flag. It means greater purchasing power on the part of the customer. It means vendors lists get squeezed. It perhaps means that historically spot market customers vanish – a strong spot market, in our opinion, is key for higher OFS prices.

The good news is M&A can and should be a tool for the OFS sector as well. That is, consolidation is a good strategic move if it (i) results in true consolidation, (ii) does not stress one’s balance sheet, (iii) adds a differentiated technology or service offering and (iv) is consummated at a fair valuation. Overpaying for old equipment and/or non-differentiated businesses is an ill-advised strategy. Unfortunately, the speed of M&A within OFS during the past two years is woefully slower than the transition underway within the E&P community. As a result, market fragmentation combined with lower industry activity levels yields lower OFS prices, all else being equal. It may also yield lower margins. Consequently, the need to drive out costs and regain pricing power is paramount, particularly if one buys into a flattish and/or range-bound activity scenario. M&A could help with this. Lastly, being a small-cap or micro-cap public OFS company is a bit like being stuck in purgatory. Market cap matters, another reason we believe and expect more M&A could happen in 2024.

There is, of course, more to the story than doing deals just for the sake of doing deals. One needs to find a niche and/or offer differentiated service. We see this in the case of efrac where, to date, demand exceeds supply. We also see it in technology which enhances automation or connection times. On the drilling side, consider the rise in automation and enhanced technology, nice add-on charges to the traditional day rate.

Simplistically, differentiated services or technology which reduce costs or enhance operating efficiencies generally carry a higher price and benefit from higher utilization. Yes, there is still the relationship game, something we see in non-differentiated businesses, but as Bob Dylan once sang, The Times They Are A-Changin’. In other words, as more acreage falls into the hands of larger E&P teams, which rely heavily on sophisticated supply chain functions and are more demanding vis-à-vis M&A’s, it would seemingly suggest to us that some smaller vendors may find life a bit more challenging.

2024 Tough Call, But Possible Recovery in Second Half of Year

Now, enough negativity. We kicked off this missive with a view that making a call on 2024 is tough and yes, much of this note has leaned overly cautious. That’s true. The reason we say 2024 is a “tough call” is because weird things happen which are often hard to predict.

For instance, in September 2023, we kicked off a rig count survey where we reached out to over 60 E&P company contacts. The survey was treated confidentially which means we glean better clarity. At that time, the survey suggested our operator list would grow rig count by over 8% in 2024 (from ~610 rigs at the time of our survey). Now, consider the survey was conducted when WTI prices were residing in the $80-$85/bbl window while CY’24 nat gas was comfortably over $3. In two short months, the unwind of commodities unfolded. No one’s crystal ball foresaw this retrenchment.

In light of the commodity sell-off, last week we reached out to a basket of land drilling contacts as well as a very small sample of E&P companies. The message from both operator and driller was largely the same. Private land drilling executives report little-to-no inquiries for additional rigs, but besides one company, none of the drillers have reason to believe their working rig counts go lower near-term.

As we were conducting our survey, Patterson-UTI provided an activity update which calls for a Q1’24 industry exit rate rig count to be potentially lower than the YE’23 exit rate. Precision Drilling also provided an activity update, calling for incremental activity in Q2. As for our E&P contacts, again our sample survey was small, but several executives foresee a rig count ranging from 550-600 in 2024. Feels right to think oil prices stay at ~$70 and sub-$3 gas.

As a result of these calls, we amended our rig count forecast lower. The forecast now reflects a slight moderation in activity in 1H’24 with a recovery in 2H’24. Specifically, a near-term decline of ~20 rigs feels reasonable, but we would expect a modest rebound in late 2024 as operators gear up for 2025. With respect to completion activity, field contacts have a slightly more optimistic outlook as crews are expected to go back to work in Q1. This largely reflects crews idled in late Q4’23 due to budget exhaustion now going back to work.

What makes 2024 tricky and could prove us totally wrong is the fact that so many variables exist which could change conventional wisdom. Consider the fact that Middle East tensions remain real and seem to be intensifying. The Houthis, in recent weeks, are doing their best to disrupt Red Sea traffic while Iran seemingly wants a bigger conflict. On January 10 the Houthi’s launched its biggest missile and drone strike to date. Of course, oil declined on the day. But what happens if it gets worse? Will global crude prices ever reflect a geopolitical premium? No idea but presumably a conflict escalation would be at some point a catalyst for oil.

What about the Presidential election? Would a Trump victory imply the same level of leniency with Iran as witnessed under a Biden Administration? Probably not. Could this potentially lead to stricter sanctions enforcement and thus, less Iranian oil on the market? Perhaps. What about the U.S. Venezuela relationship? How would a Republican Administration view the easing of sanctions there? Venezuela is presently expected to add incremental production, at least per media reports. What if the Venezuela/Guyana territorial dispute escalates? Could some oil not come to market as expected?

Or consider the U.S. Strategic Petroleum Reserve. Would there be a greater urgency in seeing a reserve refilled more quickly in a different Administration? Perhaps. Republicans do tend to talk a good game regarding energy security and energy independence. On the other hand, consider the timing of incremental oil production from Guyana or Brazil. Big numbers potentially (i.e., 100k+ b/d). Perhaps consider the implications of incremental crude exports via the TransMountain expansion (more Canadian crude export capacity). At least the latter three are likely factored into current oil prices. Nevertheless, incremental non-OPEC oil supply in a market which is considered by many to be balanced is not bullish and it is further evidence of other producers taking share from Saudi. Back to our earlier concerns about the willingness of some to cede market share to others.

Now consider natural gas. Weather, to date, hasn’t really been our friend. By the time this article is published, will we be experiencing a colder-than-normal winter? What about European temperatures over the next few months? We are clearly not Al Roker, but we know colder weather spurs incremental demand.

Consider the medium-to-longer term. We have LNG exports just around the corner. Yes, there have been some project delays announced over the past year, but eventually these get resolved. What about more near-shoring of manufacturing which could be an additional catalyst for natural gas demand, albeit on the margin. Or consider the ongoing transition away from coal. This has been happening for 10+ years and another large coal plant (Warrior Run in MD @ 205 MW) is expected to come offline this summer. One would think, all else being equal, the transition away from coal would benefit natural gas demand.

What if the global oil demand surprises to the upside? What if the Fed cuts quickly? Or, what if there is a head fake and no rate cuts are forthcoming? We’ll stop our rambling as you can see there are numerous factors which are hard to predict and that’s why no one really knows with any precision where commodity prices will be at the end of the year. Consequently, making a bold call is tough, but truthfully, that’s been the case over time.

So where do we stand? First, we are cautious near-term, but optimistic medium-to-longer term. Hardly a bold call, we admit, but we do believe global energy demand continues to grow (both oil and LNG demand). We further buy into the theory that the eventual transition to Tier 2 rock vs. Tier 1 rock will yield a higher call on OFS service capacity.

In the short-term, however, we advise EWTC readers to buckle their seatbelts. Remain disciplined. Focus on FCF. Pay down debt. Be opportunistic with respect to M&A, but don’t swing for the fences. And remember that free cash flow trumps market share, at least in our humble opinion. To the extent an unusual and unforeseen catalyst develops, that would be great, but in the meantime, run the business as if you owned 100% of the business and don’t waste shareholder money.

John Daniel OFS Outlook

John Daniel is Founder & CEO of Daniel Energy Partners. Prior to founding DEP, John served as a Managing Director and Senior Research Analyst with Simmons Energy, A Division of Piper Sandler, covering the U.S. onshore oilfield services sector for over 12 years. Prior to Simmons Energy, John worked for Key Energy Services for eight years, serving most recently as Vice President, Corporate Development. Responsibilities included investor relations and mergers & acquisitions. John also spent four years as an analyst with PNC Bank, serving in their corporate banking and leveraged finance groups. John graduated with a BS in Finance from Lehigh University and an MBA from Tulane University.

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