Basin Profile, Permian FY24 Outlook

Basin Profile: Permian FY24 Outlook

With the E&P FY24 Outlook (link) completed, the next step is to delve into the regional activity to get a better sense of which E&Ps are among the top operators in a given region or basin. Up first is the largest oil-producing region in America, the Permian.

For the regional analysis, I’ve consolidated the prominent producers in either the Midland basin or Delaware basin. As noted in the chart above, the aggregated production outlook among the nineteen Permian E&Ps profiled is forecasting +5% YoY growth, while aggregated capital spend is estimated to realize +10% YoY growth to reach ~$46B in 2024. Among the seven major basins in America, only the Denver-Julesburg/Powder River region (+21% YoY in Capex) is expected to see a higher surge in YoY capital spend growth. However, the scale of production and capital spend in the Permian should make it the focal point for any oilfield services or distribution supply provider in America.

Capital Discipline and Efficiency are the Focal Point for 2024

While the aggregated Capex projection of ~$46B among the 19 E&Ps represents a sizeable opportunity for business development across the Midland and Delaware basins, further analysis of operating metrics can highlight specific opportunities for oilfield supply and distribution. In particular, the discussion will focus on Capex per Flowing Barrel (boepd) as well as D&C Cost per foot. Both metrics illustrate the capital discipline (or lack thereof) between E&Ps, while also illustrating whether the company is planning to build out further infrastructure such as gas plant expansions and/or added gathering systems.

D&C Cost per Lateral Foot

When evaluating operating metrics among E&Ps, it is critical to understand the operational factors that drive costs associated with drilling activity. My belief is that three factors contribute to differentiated storylines among producers. These factors include, (1) rigs, frac spreads and sand, (2) drilling productivity, and (3) materials.

While I won’t elaborate on the nuances of rigs, frac spreads and sand, the second D&C cost factor, drilling productivity, is driven by the depth and lateral lengths that an E&P drills each year. Extension of lateral lengths has been a common theme the past few years, with Permian laterals extending well beyond the 2-mile range. With longer laterals generating improved production yields, E&Ps effectively do not need to drill as many wells when compared to historical well counts. This has been the common trend throughout the United States, and expectations are for well counts to decline YoY though my macro production forecasts anticipate modest, incremental growth YoY.

Third, OCTG tubulars and related materials represent ~60% of a typical well cost. While North American steel prices have declined from the inflationary pressures of 2022, the steady, downward price decline is presently at -13% on a year-over-year basis. Currently, the St. Louis Federal Reserve PPI for iron, steel pipe and tubing manufacturing from purchased steel has effectively remained static month-over-month for January and February (link). Expectations are for modest cost inflation in FY24 with E&P corporate guidance anticipating ~5% YoY. This corporate guidance has been factored into my modeling and tailored to the E&P specific guidance parameters.

With these cost factors in mind, the following table illustrates my calculation for D&C cost per lateral foot by E&P. What immediately stands out are the elevated costs for E&Ps specific to the Delaware basin (predominantly to the left) versus the E&Ps operating in the Midland basin (predominantly to the right). As well, the largest producers, namely ConocoPhillips (COP) and Chevron (CVX) have higher than average costs on a per lateral basis, though offset by substantial production volumes. Among the low-cost leaders, Occidental Petroleum (OXY), Pioneer (PXD) and Diamondback Energy (FANG) lead the way with D&C cost per Lateral Foot ranging between -20% to -40% below the Permian average. Correspondingly, these three producers are also among the largest acreage holders in the Permian, which highlights the combination of excellent operational and supply chain capabilities, and top-tier acreage. Overall, the aggregated Permian average for FY24 is USD $921/lateral foot, a -2.5% reduction from FY23 (USD $946/lateral foot).

Capex per Flowing Barrel (boepd)

While D&C Cost per Lateral Foot helps understand drilling productivity, Capex per Flowing Barrel helps understand whether an E&P is focused strictly on D&C activity or if related infrastructure and other non-D&C Capex is an investment activity. Additionally, the metric helps evaluate whether the E&P asset is capital efficient relative to its peers.

As illustrated above, the aggregated Capex per Flowing Barrel is forecasted to increase to $6,100/boepd in FY24, up +3.5% from FY23. Recognizing that the overall pace of production is expected to slow in 2024 (link), there are a couple potential catalysts to consider among the Permian E&Ps. One, infrastructure investment to retain profitability from the wellhead to processing. As an example, Matador Resources (MTDR) has higher than the basin average Capex per Flowing Barrel due to the company’s midstream investment in the Eddy County based San Mateo processing facility. Having invested $148MM in 2023, this non-D&C capital spend is the catalyst for why MTDR’s Capex per Flowing Barrel is higher than the basin average. Conversely, HighPeak Energy (HPK) has the highest Capex per Flowing Barrel for a number of reasons. Namely, an overly-aggressive drilling program in late 2H22/1H23, coupled with tertiary acreage and well production that has yet to meet the basin average of the company’s Permian peers.

What This Means For Oilfield Services, Distributors and OEMs

D&C Cost per Lateral Foot and Capex per Flowing Barrel are two metrics that can help decipher whether an E&P has a dynamic procurement process that drives cost improvements through recurring, long-standing relationships via master service agreements or competitive bid RFP processes. For the Permian, these two metrics and the year-over-year comparison charts highlight E&Ps that are driving cost leadership at the wellhead with OXY, FANG and PXD identified as basin leaders, while E&Ps above the basin average for either metric offer an opportunity for oilfield services, distributors and OEMs to improve capital productivity.

_{Disclaimer: All information contained in this publication has been researched and compiled from sources believed to be accurate and reliable at the time of publishing. However, in view of the natural scope for human and/or mechanical error, either at source or during production, Patrick Enwright accepts no liability whatsoever for any loss or damage resulting from errors, inaccuracies or omissions affecting any part of the publication. All information is provided without warranty, and Patrick Enwright makes no representation of warranty of any kind as to the accuracy or completeness of any information hereto contained.}