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Instant Insights: Key Takeaways From Our Research


North American Upstream Capex Growth To Decelerate In 2024 Amid Greater Capital Efficiency Gains

E&P Capital Expenditure Trends Continue To Evolve

Public oil and gas exploration and production (E&P) operators have maintained capital discipline in recent years, shifting their focus from production growth to maximizing free cash flow generation, and allocating an increasing amount of this cash flow to shareholders via dividends and share repurchases. While public operators' reinvestment rates increased to about 50% in 2023 from about 37% in 2021, spending as a percentage of operating cash flow still remains well below historical levels--when operators spent over 100% of operating cash flows to achieve production growth.

The days of leveraging up the balance sheet to boost production are gone. As balance sheets have been largely repaired, we expect this maintenance capex trend to continue in 2024. We believe E&P operators will prioritize free cash flow generation and commit to delivering returns to shareholders.

E&P operators are also deploying free cash flow for mergers and acquisitions (M&A). The perceived lack of higher-quality inventory and ongoing need to replace reserves to offset natural declines, pursuit of greater operating efficiencies to counterbalance inflationary pressures, and relatively supportive commodity prices have pushed producers to consider business combinations. We expect M&A activity will continue this year. Longer term, E&P producers may enter deals as they seek ways to broaden their portfolios to better prepare for future environmental regulations and the energy transition.

Given our current expectations for commodity prices and maintenance capex, we expect E&P players will generate another year of significant free cash flow. Our 2024 price deck assumptions are $80 per barrel (bbl) for West Texas Intermediate (WTI) crude oil and $2.50 per million Btu (mmBtu) for Henry Hub natural gas (Chart 1).

Chart 1

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E&P Capital Spending Will Likely Decelerate In 2024

Chart 2

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In aggregate in 2023, E&P capital spending increased toward the higher end of our initial 15%-20% forecast (Chart 2). This year, we anticipate upstream spending in North America will decelerate to 0%-5% in aggregate as producers continue to improve capital efficiencies and benefit from modest deflationary pressures, and reflecting the pull-back in natural gas activity due to weaker gas prices. Specifically, we expect relatively flat capital spending for public independent producers and a mid- to high-single-digit percent capex reduction for private operators in 2024 compared to 2023. We expect a roughly 4%-5% increase in capital spending for the U.S. major companies, primarily because of Exxon Mobil Corp.'s increased investments in its key operating areas in the Permian Basin and Guyana.

Initial Signs Of Cost Deflation Boost Capital Efficiency

After almost two years of continuously rising costs, the conversation has turned to cost deflation, with some companies signaling low- to mid-single-digit percent declines in 2024. E&P players benefit from reduced prices for materials (especially steel) and consumables, including oil country tubular goods, proppant, diesel, and chemicals. This reduces costs year over year, though we expect costs for services such as drilling rigs and hydraulic fracturing will remain relatively flat. Labor costs tend to be stickier, and we expect they will remain elevated this year. Overall, we project average cost deflation in the low- to mid-single-digit percent range for 2024.

Assuming most E&P operators will maintain essentially flat production levels, we believe service cost deflation and enhanced operating efficiencies will exert downward pressure on 2024 capex budgets.

Capital Efficiency Continues To Improve As Operators Drill Longer Laterals, Utilize Latest Technologies

Last year, most E&P players highlighted meaningful operational efficiency improvements as supply chain constraints and tightness in service markets have been mostly alleviated. This year, we anticipate further improvements in drilling and completion productivity and efficiency that are more pronounced in shale regions. E&P producers continually explore ways to reduce costs by increasing the speed it takes to drill and complete a well, extending drilling lateral lengths, modifying completion designs, and integrating technologies including artificial intelligence. Companies are also fracking wells simultaneously, which reduces time and can have productivity benefits.

These strategies enable the companies to extract more oil and gas without increasing capital budgets. Since service costs such as drilling and fracking are based on day rates, E&P operators can conserve capital by drilling and completing wells faster. Additionally, producers consistently work with the same drilling and completions crews, gaining knowledge and experience. The continued shift to longer laterals and rig efficiency (the ability to drill a well more quickly) contributed to lower well costs across producers. There is a growing trend of increasing lateral lengths across all major basins, with three-mile laterals becoming more common in producers' programs.

Following mid-single-digit percent production growth in 2023, we expect low- to mid-single-digit total production growth this year, mostly due to expected oil-weighted peers' production growth, while we project gas production to be flat to down.

Natural Gas Producers Cut Capex In Response To Weaker Prices

Following increases in late 2021 and 2022, natural gas prices have largely weakened to an average of about $2.10/mmBtu year to date compared to about $2.50/mmBtu in 2023 and $6.40/mmBtu in 2022. Therefore, we estimate that U.S. natural-gas-focused producers will reduce capital spending 10% in 2024 compared to 0%-5% growth for the E&P issuers that we rate (Chart 3).

Chart 3

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For example, Chesapeake Energy Corp. announced a 20% year-over-year reduction in capital spending while curtailing production and building an inventory of drilled but uncompleted (DUC) wells and deferred turn in lines. Similarly, EQT Corp. announced its intention to curtail production (and associated capex), while CNX Resources Corp. delayed completion of wells due to the current natural gas environment. Antero Resources Corp. announced a 26% decrease in its drilling and completion budget, which we anticipate will result in a relatively flat total production in 2024, while Comstock Resources Inc. recently dropped two rigs in the Haynesville shale.

However, Range Resources Corp. does not expect any curtailment or decrease in activity given that its current program is already minimized to maintain operational efficiency. While natural gas prices remain weak, some producers are strategically building up their backlog of DUCs, anticipating higher natural gas prices in 2025.

Given that some natural-gas-focused producers have hedged a significant portion of their gas production and also some have exposure to liquids, we expect they will be partially insulated from the full impact of the downturn in U.S. natural gas prices. Nonetheless, we expect natural gas prices to improve in 2025 as exports of liquefied natural gas (LNG) increase, linking U.S. prices more closely to higher international price levels. Our 2025 price deck assumption is $3.50/mmBtu for Henry Hub natural gas, which we believe will lead to a resumption of natural gas drilling activity. We believe most of the production growth will come from the Haynesville shale as growth in the Appalachian region remains constrained by the lack of takeaway capacity and limited opportunity for capacity expansion.

However, the story is different for oil-focused peers. Following a nearly 12% increase in capital spending in 2023, large E&P oil-focused operators now guide relatively flat capital spending in 2024 with modest low– to mid-single-digit percent production growth. We attribute flat capex mostly to capital efficiency gains, modest cost deflation, and ongoing consolidation.

Chart 4

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DUC Inventories Remain Low

From mid-2019 through late 2020, oil and gas producers built DUC inventories by opting not to complete wells, conserving capital amid low commodity prices. As prices recovered in 2021, E&P operators started drawing down their DUC inventories as a relatively quick and inexpensive method of boosting production. As of December 2023, the U.S. Energy Information Administration reported a U.S. DUC well inventory of 4,533, down nearly 50% from the peak in June 2020 and 15% below 2022 (Chart 5). Most of the reduction was in the Permian Basin.

E&P operators will need to drill and complete new wells to maintain production volumes. However, considering cost deflation and improved capital efficiencies, we don't expect they will increase capital spending.

Chart 5

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As we forecast last year, capital spending across U.S. E&P firms that we rate increased around 17% in 2023. However, the average U.S. rig count decreased approximately 5% year over year, according to data from Baker Hughes, supporting our view that the capital increase was largely because of inflation, not more activity. While softer commodity prices accounted for some of the drop, rigs also declined with advancements in technology and greater operational efficiencies. Natural gas rig count reductions were particularly noticeable in the Marcellus, Haynesville, and other U.S. gas plays (Chart 7).

For oil-focused producers, rig count changes were a function of greater operating efficiencies and ongoing consolidation (Chart 6). As oil producers have worked through their DUC inventories and shifted focus back to drilling new wells, we expect the total oil rig count to continue to increase in 2024.

Additionally, we expect natural gas activity to continue to decline for the first half of 2024 with a potential pick-up later in the year. Overall, we expect the total rig count to remain relatively flat to down this year.

Chart 6

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Chart 7

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Oil-Weighted E&P Companies Dominate Canadian Industry's Capital Spending Increases

In 2024, we anticipate high-single-digit percent year-over-year growth in capital spending for Canadian oil and gas companies that we rate. Most of this comes from liquids-weighted E&P companies, which we anticipate will increase capex just under 15% relative to 2023 spending.

In contrast, we expect gas-focused companies will hold capital spending relatively flat versus 2023 given weak natural gas pricing stemming from exceptionally high storage and stagnant demand (until LNG export capacity increases meaningfully beginning in 2025). We similarly expect natural gas producers will target drilling their more liquids-rich assets given the stronger pricing fundamentals for Canadian produced condensate (which is used to blend with heavy oil for pipe transport and priced closely to WTI).

Increased Crude Oil Egress Will Drive Higher Canadian Heavy Oil Production

We anticipate the start-up of the Trans Mountain Expansion (TMX) in the second quarter of this year. The expansion project for 590,000 barrels per day is a crucial piece to release the bottleneck in western Canada's crude transportation system and the impetus behind 2024 capital spending and production increases for many of Canada's heavy oil producers. We believe the excess pipeline capacity will offer some long-awaited stability to the Western Canadian Select (WCS) heavy oil differential, which we project at $15 per barrel, down from the $18-$20 average differential in 2022-2023.

We believe future WCS differential volatility will also be limited because we anticipate TMX will provide comfortable egress to the western Canadian supply at least through 2025. Based on announced 2024 capital spending budgets and production forecasts, we expect total Canadian hydrocarbon production (liquids and gas) to increase by about 6% in 2024 relative to 2023, with heavy oil accounting for roughly half of the growth. Unlike in the U.S., most Canadian producers have ample core acreage remaining, which will likely support higher capital efficiency as producers optimize assets and expand production.

Availability Of High-Quality Targets Continues To Shrink As Consolidation Continues

In 2023, according to S&P Commodity Insights, North American upstream M&A activity totaled about $150 billion in 2023 (Chart 8), primarily because of billion-dollar takeovers: ExxonMobil's announced acquisition of Pioneer Natural Resources Co. and Chevron Corp.'s pending acquisition of Hess Corp. This significant deal-making marked a return to consolidation among E&P peers after transaction count and value had plummeted in 2020.

The new wave of consolidation that began in 2023 has continued in 2024 as M&A have become the preferred tool to replace declining reserves and secure longevity in the business. The biggest deals to date include the Diamondback Energy Inc.-Endeavor Energy Resources L.P. merger at roughly $27 billion and the Chesapeake-Southwestern Energy Co. merger for a total value of about $12.8 billion.

Although most privately held companies in the Permian were sold in 2023, we expect further industry consolidation as producers focus on operational scale and long-term inventory depth. While this means potentially fewer rigs and frac crews, it also means an increase to service intensity, drilling longer laterals, resulting in increased stages per well. In addition to "high grading" their portfolios, E&P operators are seeking to increase scale to have greater negotiating leverage with oilfield services companies, which ultimately results in greater cost savings. However, regulatory scrutiny of M&A will continue with several large transactions having received second requests for information from the FTC.

The continued consolidation of public and private E&Ps often leads to reduction in capital spending and because we expect the M&A activity to continue, it will likely constitute a headwind for capex growth in 2024.

Chart 8

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The Above-Ground Risks Remain

While E&P players high grade their portfolios and shift to maintenance production programs to sustain capital efficiency, external forces will also play a role in oil prices and capital allocation decisions. These include rising geopolitical risks, macroeconomic conditions, and the pace of the energy transition, heightening the volatility of global commodity prices and capital spending.

Later in 2024 and beyond, upcoming elections around the globe could influence the entire energy landscape, shaping regulatory environments that may either support further development of or accelerate the transition away from fossil fuels.

Related Research

This report does not constitute a rating action.

Primary Credit Analyst:Victoria Godunova, New York +1 212 438 0280;
victoria.godunova@spglobal.com
Secondary Contacts:Carin Dehne-Kiley, CFA, New York + 1 (212) 438 1092;
carin.dehne-kiley@spglobal.com
Laura Collins, Toronto +1 4165072575;
laura.collins1@spglobal.com
Thomas A Watters, New York + 1 (212) 438 7818;
thomas.watters@spglobal.com
Contributor:Ashutosh B Sarda, Pune;
ashutosh.sarda@spglobal.com

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