BKR U.S. Land Rig Count: Two weeks in a row, the BKR rig count is down. This week moving lower by 3 rigs to 760 rigs. We are not freaking out, yet.
How Washington Persuaded Europe to Put a Price Cap on Russian Oil – WSJ
Utility Bills Rise as Americans Pay Off Storm-Recovery Costs for Decades to Come – WSJ
How Exxon Mobil’s CEO Views Energy Shortages and Increasing Profits – WSJ
DEP Update: We will be in Denver on Monday/Tuesday this week and then off to OKC on December 19-20. Have a couple open spots on our schedule. Let us know if you are in town those days. This week’s note kicks off with some thoughts on E&P inventory with observations on the XOM/CVX capex announcements as well as thoughts on recent OFS M&A and newbuild orders. In other DEP news, our final Thrive Agenda will be published next Sunday while we expect to finalize/publish our Telluride and Pebble Beach agendas in mid-January. Lastly, we hope to reintroduce the London Energy Day on June 12-13, 2023 – pestering companies now for participation. Stay tuned.
DEP Podcast: Bill & John traveled to the EnQuest Energy Solutions facility in Houston to talk with the President of EnQuest, Jamie Stewart. As many of our readers know, Jamie is an oilfield veteran with expertise in manufacturing, repair and service of oilfield equipment. EnQuest provides equipment, parts/service for OFS, Compression, Drilling, & Battery Storage. This was a wide-ranging conversation, touching on numerous topics in the OFS world from supply chain troubles to the electrification of frac.
Next up on our podcast list will be a discussion with the team at iNet. If you would like to do a podcast, let us know.
Locations, Locations, Locations (Authored by Geoff Jay): The notion that US shale is petering out has been getting increasing airplay recently, particularly in light of comments from the CEOs of PXD and most recently HES. The latter suggested that US growth is waning, and that OPEC is “in the driver’s seat.” Well results (in the Permian and elsewhere) also appear to be underperforming results from last year. Whether this is a sign of reservoir exhaustion or merely a return to trendline is a matter of debate, but this deterioration has sparked a lot of questions about the industry’s inventory of drilling locations. Most of the interest centers on whether or not we have exhausted the best (Tier 1) inventory, what the quality of the remaining locations is, and what it means for US activity and production growth. We thought it would be a good opportunity to recap the conversations we’ve had on this topic during the year.
Several basins have shown persistent reductions in production per rig, according to the EIA’s Drilling Productivity Report:
When you look at the full-year averages, the picture is less grim:
Source: Energy Information Administration Drilling Productivity Report, November 2022
It’s worth saying from the outset that we aren’t trying to pinpoint a number. We don’t have any reason to believe we can do that better than the major data providers or high-powered energy consulting firms. Rather, we thought it would be helpful to provide color and context around the issue that we’ve picked up as we’ve bounced around the country this year. Notably, inventory is a key discussion item which even comes up when our OFS research team visits E&P clients.
As for our process, we started by trying to figure out what Tier 1 is. The only thing that’s clear is that Tier 1 acreage requires fewer dollars for every barrel produced. Is Tier 1 always the best quality rock? Not necessarily, but of course it doesn’t hurt. E&P contacts we talked to suggested that there is plenty of heterogeneity in well results in the best rock. Also, if you’re co-developing zones, you’re likely to get a mix of wells, some with very high rates of return and others that are lower due to communication. A lot of the folks we talked to would consider these clusters of wells as Tier 1, despite the individual disparities, since their aggregate returns are very high.
Downspacing (versus co-development) doesn’t necessarily relegate locations to Tier 2 (or worse) but could. One Eagle Ford operator told us that narrowing spacing didn’t mean lower EURs or IPs for them, but it did require bigger fracs. Others did worry a bit about the impact on future development of other formations. “We now know there’s vertical communication as well as horizontal, and the best Wolfcamp B and C is generally where you have the best Wolfcamp A. Once the upper benches are developed, it could impact the lower stuff.”
In areas that used to be well outside the core, better drilling and completion techniques have pulled these wells into Tier 1 country. “A lot of what we think of as Tier 1 now was definitely lower on the totem pole a few years ago.” A Bakken player suggested that their old Tier 2 now compared very favorably with their old Tier 1, having the same EUR and IP 180s. Several folks we spoke with echoed this sentiment, arguing that completion techniques are nearly as important as rock quality to returns on capital.
Are companies running out of inventory? We quizzed a lot of companies about this, and the answers were mixed. Most of our contacts believed that most of their peers had a least a decade of profitable drilling ahead of them. Some thought there was some overstatement in their competitors’ estimates, with one private telling us that in the Permian “there’s probably only 5-8 years of inventory that’s as good as what we’re drilling today”. A surprising few felt like inventory was likely understated, but with the proviso that further inventory would be unlocked with improvements in technology or commodity prices. One executive said, “Guys that had 10 years of inventory five years ago still have 10 years of inventory.” Another shrugged, “We leave a lot of oil behind. We’ll figure out a way to get it if it makes sense. I’m not sure we can grow much doing that though.” Some believe that more inventory will be unlocked with eventual refracs of existing wells.
Even if ten years of drilling runway is the magic number, it doesn’t mean that all ten years of wells will look the same. There was a general agreement that the wells slated for years 1-4 would be significantly better than those in years 5-10. “Companies generally drill their best stuff first,” one executive we spoke to said. “It is possible that you’d drill out lesser locations first, but only if you had to hold acreage, or if you had Minimum Volume Commitments that required production from a specific area.”
As we think through all of these conversations, we surmise inventory quality and life is undoubtedly lower than it was a few years ago. The industry is ingenious, though, and will ultimately figure out new techniques to transform locations which are now marginal. The fact that growth may be harder in this environment should be a boon for commodity-price strength. This combo makes us feel pretty good about the longer-term prospects for both the E&P and Service industries in the US.
XOM Capex: XOM held a Corporate Plan Update webcast and revealed that its total capex budget is $23-25B for 2023, up 9% from 2022. This figure is at the high end of its $20-25B per annum guidance (which it is maintaining through 2027), largely due to accelerated completion of its Payara well in Guyana, which will now come online in late 2023 vs early 2024. Exxon did not provide granularity by basin but did indicate during the meeting that it expects its Permian production to grow by ~10% a year, with volumes of 900-1000 MBOE/d by 2027. Last week, Chevron pointed to roughly 7% growth, and a peak of 1-1.5 MMBOE/d for its assets in the 2030’s. Exxon said its production growth would be underpinned by Guyana, Brazil, and the Permian. Exxon also expects its share repurchases to average $17.5B over the next two years, up from $15B in 2022.
CVX Capex: released their 2023 plan, which is up 25% from 2022. The company plans to spend $17B overall ($3B of which is from affiliates), with $8B earmarked for US Upstream. Permian spending is expected to clock in at $4B, a figure that assumes “low double-digit inflation,” according to management. Recall that in 2022, Chevron budgeted $3B for the Permian, a number that may have risen somewhat with inflationary pressures during the year. Chevron will spend another $2B on other shale and tight assets (DJ Basin, Vaca Muerta). The company indicated that GoM operations would consume 20% of Upstream capex. Note that CVX spent $1.85B during Q3 on U.S. Upstream, or $7.4B annualized, thus the 2023 U.S. Upstream budget relative to the Q3 annualized run-rate is about an 8% increase.
OFS M&A Continues: More signs of OFS integration/consolidation as ProFrac Services (“ACDC”) announced the acquisition of Monarch Silica while Gladiator Coiled Tubing acquired the coiled tubing assets of Key Energy Services. With respect to the ACDC deal, this is their second sand acquisition and follows a number of other consolidation steps incurred by the company. The Monarch asset is located in the Eagle Ford and presently has name-plate capacity of 3M tons, but ACDC is expected to increase that to 4M tons by Q1’23. Much of the sand, we believe, will go towards ACDC’s eight Eagle Ford fleets. The Monarch transaction gives more sand ownership to ACDC with its total nameplate capacity rising to ~12M tons by the end Q1. In another deal, Gladiator acquired the CT assets from Key Energy Services. Terms of the deal were not disclosed. This is the second CT purchase by Gladiator as it previously bought the NEX assets. The combined transactions, we believe, make Gladiator the largest U.S. CT player based on working units as we estimate 22 units are working today, a count which should go higher as Gladiator has several additional units in the upgrade process. Recall too that STEP bought the CT assets of PUMP, thus we now have three consolidation deals behind us in the CT market.
VoltaGrid / Pilot Transaction: More news from VoltaGrid as it announced the purchase of Pilot’s CNG compression, virtual pipeline and logistics platform. The deal includes 870,00 diesel gallons/day of CNG production capacity and a logistics platform includes an expected 160 committed CNG trailers by Q2’23. These trailers will largely support electric and dual-fuel frac spreads. If our understanding is correct, there are about 4 CNG trailers allocated to a frac spread, thus the VoltaGrid fleet would appear to service about 40 fleets. Terms of the deal not disclosed, but our guess is this combination puts VoltaGrid into the $1B enterprise value vicinity – if that’s right, it’s pretty impressive growth for a company that is only about two years old. More importantly, however, is it shows the surging demand for natural-gas fuel solutions.
PUMP Electric Fleets: PUMP announced additional orders of electric frac fleets, bringing total orders to four fleets. The fleets, according to the company, will most likely be used to replace existing diesel capacity, a wise move given the plethora of new fleets now on order. We track (aka estimate) 28 fleets on order, but we believe the number will move higher given recent anecdotes from power providers. What’s important is the lead times for fleets is not short. The first two fleets which PUMP ordered in August are not supposed to be deployed until Q3’23 while the next two fleets are likely a Q4’23/Q1’24 event.
Refining Observations: A tough week for inventories and crack spreads, as high utilization and low apparent demand pushed product inventories higher in what’s become a trend (see charts below). Inventories remain supernormally low, but the recent spate of builds has pushed Gulf Coast cracks down nearly 70% from their highs. We continue to believe that some level of demand destruction is necessary, but we are surprised to see it in the current falling-price environment.
Phillips 66 announced expected 2023 spend of ~$2B, with $865mm of sustaining capital and $1.1B earmarked for growth. Refining spend of $1.1B includes $389mm of maintenance spend. Growth spend includes the renewable-fuels conversion of its Rodeo refinery in CA. Midstream will command $639mm and Marketing and Specialties will spend $39mm. Equity affiliates (CPChem and Wood River Refining) will consume another $1.1B of capex, not included in the $2B figure. The company intends to return $10-12B to shareholders from 2H 2022 through the end of 2024 through dividends and buybacks.
Product Inventory, Demand, and Margin Charts
(Shaded areas show the 5-year range)
Source for Inventory and Demand Charts: Energy Information Administration
Source for Margin Charts: Bloomberg, LP.
John M. Daniel
Managing Partner, Founder
Daniel Energy Partners, LLC
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