A mature US shale industry embraces challenges as the dream run of 2022 grows distant

Exceptions are just that – exceptions. Close on the heels of a year in which the US shale industry saw almost every major financial metric turn out to be the best on record, the outlook has changed sharply in a clear sign that the exceptional run has come to an end. Increased volatility in oil prices, in addition to a plunge in natural gas futures, is weighing on cash flows. Margins and profitability are getting squeezed as costs – while no longer on their sharp ascent as a red-hot supply chain market cools – remain elevated still amid labor shortages. The historic highs of 2022 came about on prospects of supply shortages triggered partly by years of underinvestment as trade flow routes were disrupted by the Russian invasion. A year later, as the war rages on, a subdued consumption outlook, concerns over demand growth in China and fears of a global economic slowdown are weighing on sentiment. US onshore drilling is witnessing a pullback across basins, with rig counts sliding below year ago levels, puncturing a recovery from the lows touched during the peak of the Covid-19 downturn in 2020.

Even so, unlike the previous downturns in which the unconventional industry was forced to hunker down, this time it is confronting those challenges while remaining profitable, all together suggesting that the sector is maturing in several dimensions. It is exhibiting a lot lower sensitivity to oil prices and less variability in well results, while cash rich players snap up smaller peers and acreage positions to consolidate. The fourth quarter earnings season was too soon, but the subsequent three months have been long enough to suggest that the volatility is here to stay for now. It has given the industry enough time to absorb and adjust their guidance to factor in the changes in market conditions. The latest reporting offered a window to gauge the shale industry’s outlook, including its supply chain, through the lenses of its financial results and investment decisions. Based on those latest findings, this issue of REview studies the sector’s evolution and its near-term trajectory.  

Corporate earnings and guidance

For nearly three years now, companies have refrained from overspending and are reaping the rewards of large investments made in the previous decade. Re-investment rates – or the ratio of capital expenditure (capex) on drilling and completing new wells to the cash flow generated from these operations – have been dropping, from almost 200% in 2017 to 55% in the third quarter of 2020 and to as low as 35% in the third quarter of 2022, when commodity prices peaked. The latest earnings and those of the preceding three months reveal two consecutive quarters of reinvestment rate increases. The industry now sits at 60%, a figure unimaginable some years ago – when it lived beyond its means for a growth for growth’s sake mantra – and is handing out generous payouts.

This means that a whopping 40% of the cash flow resulting from sales of hydrocarbons minus operating expenses and taxes are returned to shareholders in the form of dividends and buybacks or kept as dry powder. Indeed, majors and large independents are sitting on cash of tens of billions of dollars, ready to be deployed on acquisitions to gain market share and leverage on synergies gained from acreage consolidation, profiting further from inorganic growth. The recent announcement of Chevron’s acquisition of PDC is a prime example. Even so, the plunge in natural gas markets so far this year and a pullback in oil prices may make potential buyers await more favorable conditions in the acquisition market as prospects of a softening in valuations grow.

During the first-quarter earnings season, all public operators reaffirmed their guidance, a sign that a maturing shale sector can continue to grow amid price volatility. The willingness of producers to hold firm, and in some cases slightly increase, their growth expectations underscores that players remain confident about meeting their targets, and that spending can be kept in check despite the price volatility. Some of this can be explained by easing inflation. As anticipated, all earnings metrics ticked down for another consecutive quarter from the high marks reached in mid-2022, while reinvestment rates inched up due to higher capex, with strong first-quarter activity, higher well costs, and lower commodity prices. In the second half of the year, we expect the reinvestment rate to keep increasing, with the industry remaining profitable, while defending its buybacks and dividend programs and target higher production. Rystad Energy believes that production is still set to grow materially this year and next despite all infrastructure bottlenecks and weakness in commodity prices. The 13 million barrels per day (bpd) pre-pandemic high in total US crude and condensate production is likely to be surpassed at some point in June or July of this year.

Gas prices remain depressed, with associated production continuing to grow in the Permian, with no outlet, resulting in large increases in flaring, in-field use and re-injection into the ground. The Mountain Valley pipeline now appears likely to be completed, following negotiations in Congress as part of the broader debt ceiling bill. This will still not help in raising gas prices going forward, and gas-focused operators will have to hang on to their very profitable hedging positions for as long as they can before again being exposed to the realities of the spot market.

Oilfield services companies – drilling contractors, pressure pumpers and others – have been able to tidy up their balance sheets over the past couple of years due to an increase in service prices and margins. The capital discipline behavior showcased by operators has rubbed off on the services side as well. Drilling contractors have stayed disciplined by not getting into a new build cycle or spending substantial capital in re-activating cold-stacked rigs, which require higher investment. Pressure pumpers have mostly improved their fleet technology by converting their legacy diesel fleets to natural gas capable fleets or next gen fleets.

Operator activity and supply chain trends

The US Lower 48 region has witnessed a significant drop off in rig activity over the past month due to a lower commodity price environment. The count has dropped by more than 80 active horizontal rigs in the past eight months, leading to a drop in rig day rates. The completions space is witnessing a pullback in fleet activity as well. Oilfield services companies have offered more of a cautionary tone in their latest earnings calls in contrast to a more bullish 2023 tone that was struck in the earlier three months. Services companies are between a rock and a hard place as they ascertain whether to hold pricing up by cutting rigs or fleets or chase market share by lowering rates. They are also worried about losing personnel when they stack equipment, after only just replenishing their ranks vacated during the lockdown. The labor market is still tight and hence service companies will face an uphill task in recruiting and training personnel should the market pick back up in the second half of 2023.

Operators held off dropping rigs in the first few months of the year in the hopes of commodity prices improving but have decided to cut drilling and completions activity as they accept the new reality of a lower and more volatile price environment. It is going to take some time for operators to gain confidence to deploy rigs and fleets back even if the price environment improves. All the factors highlighted above suggest that activity is to remain at a lower level in the coming months and all signs are pointing to oilfield service pricing possibly already peaking this year.

Prices for onshore US drilling and completions services have decreased by almost 5% since the beginning of the year until the second quarter. We expect service prices to continue declining, albeit at a much slower pace, through the fourth quarter of 2024. Volatile commodity markets could cause service prices to fluctuate dramatically in either direction. For example, drilling and completions costs would rise by 26% in a high commodity price environment and fall by 20% in a low-price environment.

Spot land rig rates for 1,500 horsepower (HP) AC rigs have been falling on the back of declining activity in the second quarter. US rig counts are down by 35 month-on-month, 67 quarter-on-quarter and by over 80 in the past eight months. The market is relatively fragmented, with 330 operators running less than two rigs on average in 2022, accounting for 46% of the total land rig market. Given the significant impact oil price fluctuations can have on private and small operators, there is a vast range of potential spot land rig day rates that may be observed in the next 18 months. In our high case, elevated prices would drive land rig rates above $38,000 per day. Conversely, weaker markets would see rates fall to $23,000 per day by fourth quarter of 2024.

Prices for frac services and frac sand are expected to see marginal decreases. In an elevated price environment, fresh frac water prices would rise by 35% from their current levels. A lower price environment would see freshwater pricing drop by nearly 17%.

However, while prices have been falling through the year, they will be reflected in companies’ average well cost performance metrics with a lag.  A sample well in the Delaware South shows that wells completed in the second quarter will see a $700,000 cost increase relative to the fourth quarter of 2022. The legacy contracted rates, which are higher than current spot levels, are causing an increase in these metrics. We expect this to cause some confusion during the earnings season, as costs per completed well go up, but spot service prices continue to fall across categories.

Majors increase cash reserves and announce key FIDs

For their part, global supermajors – namely, BP, Chevron, Eni, Equinor, ExxonMobil, Shell and TotalEnergies – have thus far weathered this year’s volatility quite effectively. Although oil prices decreased by 9% in the first quarter of 2023 compared to the fourth quarter, the impact on majors’ net income and cash flows was more muted, with aggregate cash flow from operations declining by only 3% over the same period. By the same token, the peer group exited the first quarter with record high cash levels of approximately $150 billion. ExxonMobil has exhibited the most impressive cash build over the past 12-18 months, growing from less than $10 billion at end-2021 to nearly $35 billion by the end of the first quarter of 2023. The sequential quarterly uptick observed between the fourth and the first quarter could be partially related to ExxonMobil’s unconfirmed market talk of acquiring Permian producer Pioneer Natural Resources. Meanwhile, Shell and BP ended the first quarter with cash reserves of between $30 billion and $45 billion each. Although this does not represent a significant departure from their post-Covid-19 balance sheet cash equivalents, maintaining robust levels of dry powder will be important for the two European supermajors’ energy transition plans, which still rely heavily on inorganic growth.

On the conventional sanctioning front, the majors have both pursued major positive FIDs and deferrals during the first half of the year. In April, ExxonMobil – along with partners Hess and Chinese state-owned CNOOC – sanctioned the $12.7-billion Uaru project offshore Guyana, representing the fifth major development in the country’s Starbroek block, with proposed production capacity of 250,000 bpd and startup in 2026. Similarly in May, Equinor and project partners Repsol Sinopec Brasil and Petrobras reached FID for the $9-billion BM-C-33 pre-salt project in Brazil’s Campos Basin, with oil production capacity of 126,000 bpd and startup in 2028. Positive FIDs were likewise taken for smaller subsea tiebacks, including Shell’s Dover (GoM) and Victory (UKCS) developments and Equinor’s Halten East field in Norway’s Voring Basin. On the flip side, Equinor shocked the market with its May decision to defer the $10-billion Bay du Nord development offshore Canada by up to four years, underlining persistent cost inflation and, perhaps, a reticence to move forward with another large-scale FPSO-based project against the backdrop of increasingly uncertain macroeconomic conditions.

Meanwhile, the pace of the energy transition continued to make waves for many of the majors during the first half of 2023, with the annual general meetings (AGMs) of Shell, BP and TotalEnergies seeing an uptick in climate-related protest activity. Climate-focused investor activism likewise featured prominently on the agenda, with demands for more stringent decarbonization targets garnering between 15% and 30% of investor support at European supermajor AGMs (similar activist proposals aimed at ExxonMobil and Chevron garnered only 10-11% of shareholder support). Although defeated across the board this year, such climate-focused activism has nevertheless seen incremental gains over the past few years and could portend increased shareholder strife should other majors follow the example of BP and soften their decarbonization targets.

So what? Natural gas prices turn more bearish and oil prices more bullish

What can we infer from the latest corporate earnings, operator guidance and supply chain trends to shed some light on the outlook for the second half of 2023?

On the gas side, markets are expected to remain bearish in the coming months. Public E&Ps are still holding onto their guidance. There hasn’t been much of an impact from the activity drop given the lag as it takes a few months for production declines to show up. The overall industry is as profitable as it ever has been, despite rig count reductions – mostly affecting gas rigs. The impact on oil, or exploration and production (E&Ps), is, in turn, positive and there is no major risk of production taking a hit on the oil side. But for gas, if oil prices are lower for longer, then we might start to see some impact on private operators, especially in the Permian. As such, reduced associated gas supply and some decline in gas activity is expected in the second half of 2023 as suppressed prices are keeping the supply side bearish. Gas in storage could be above the 5-year average by the fourth quarter of 2023 if LNG exports remain flat or reduce, considering Europe and Asia aren’t starving for gas this year, at least not yet.

The last quarter of the year will be the show to tune in to, but what happens in the injection season, doesn’t stay in the injection season – it sets the tone for the fourth quarter – and right now several scenarios could play out. It is possible that we could see gas prices dip closer to the $2.00/MMBtu range if this summer proves to be cooler and LNG trade flows are muted due to marginal demand coming from Europe and Asia this year. For now, we still forecast an uptick in international demand over the next six months, but it’s possible this could all change if weather in those regions remain mild. Still, there is a high(er) case here, one that is more aligned with our house view. While our gas price outlook remains bearish – in the sense that sustained $4.00/MMBtu Henry Hub prices are unlikely to materialize this year – we still expect incremental price improvements for gas in the second half of 2023, closer to $3.00 per MMBtu. The price bump will materialize when that lagging lowered gas production and activity, mentioned above, finally kicks in – just as gas markets experience a seasonal demand uptick to support gas stocks ahead of the 2023/24 winter. Plus, a boost in gas deliveries to Mexico is expected with a new LNG export facility coming online there and requiring low-cost gas from the US.

US gas market equilibrium will hinge on more than weather-driven demand this year. The pace of supply will determine the fate of balances: if gas production slows down too much too soon, the risk of an undersupplied market could present itself. But if gas supply growth continues for the rest of the season, an even more bearish road is ahead this year.

If gas prices are likely to turn more bearish in the second half of the year, the good news for oil & gas producers is that oil prices are about to turn decisively more bullish, as a result of the huge OPEC+ supply cut announced in April, and subsequently confirmed and ‘augmented’ in June. The OPEC+ strategy is perfectly rational: With the maturing of shale, periods of fast galloping US production growth are over, albeit spikes of extremely high oil prices may give shale a temporary boost.

OPEC+ must have calculated that even if Brent were to exceed $100 per barrel for the next few quarters, which is far from a remote possibility in the absence of an economic slowdown, it will not stand to lose significant market share to the benefit of US shale, like in the 2011-2015 period when the US shale revolution ramped up rapidly.

Therefore, the combination of renewed confidence from OPEC+ and shale producers’ investment caution will likely keep balances tight and oil prices high for the next few quarters and would provide a support in case the economy were to enter a period of slowdown in China and/or the developed nations.

Sign up to be the first to read REview every month.


Claudio Galimberti

Senior Vice President, Head of North America Research

Emily McClain 

Vice President, Gas Markets Research

Matthew Fitzsimmons 
Senior Vice President, Supply Chain Research

Manash Goswami

Vice President, Analytics

Thomas Jacob
Senior Vice President, Supply Chain Research

Thomas Liles
Vice President, Upstream Research

Alexandre Ramos-Peon
Vice President, Shale Research

(The data and forecasts contained in this column are Rystad Energy’s and the opinions are of the authors.)