What’s happening with Big Oil?

  Horacio Coutino, Equities investment writer

Energy prices trended higher in Q1 2024 but the future direction of the wider Energy sector and the Oil sector in particular is not clear given ongoing geopolitical risks, global economic growth uncertainties, continuing inflation worries and still tight monetary policies. To better understand possible future directions, we examine the key drivers behind what has been happening in the Oil sector. We consider:

• Q1 performance to date
• Geopolitical and structural risk factors
• Oil companies projects portfolio

Big Oil Q1 2024 earnings

Based on LSEG I/B/E/S data as of 10th May, the S&P 500 Energy sector is projected to experience a 24.1% y/o/y decline in earnings for Q1 2024, representing the most significant decrease across all eleven sectors. All 22 companies within the S&P 500 Energy sector have released their first-quarter earnings, with 64% surpassing analyst estimates for earnings and 68% exceeding revenue expectations. Despite this, y/o/y revenue growth for the sector is only projected to be 1.8% in Q1 2024.

The Energy sector's earnings surprise factor stands at 1.6%, the lowest among all sectors, compared to the overall S&P 500 surprise factor of 8.3%.

However, it is worth noting that, according to FactSet, during April, analysts raised their S&P 500 EPS estimates for Q2 2024. The bottom-up EPS estimate for Q2 increased by 0.7% from 31st March to 30th April, marking the first time since 4Q 2021 that such an increase occurred during the first month of a quarter. Notably, the Energy sector experienced the largest upward revision in its bottom-up EPS estimate for Q2 2024, rising by 8.6%.

Some of the biggest players in the Energy sector experienced significant changes during 2023 and into Q1 2024. We’ve taken a closer look at these changes for ExxonMobil, Shell, Chevron, ConocoPhillips, TotalEnergies, and Eni SpA.

ExxonMobil doubled its Permian footprint

ExxonMobil reported Q1 2024 adjusted EPS/CFPS of $2.06/$3.17, below consensus estimates. The Upstream segment underperformed due to lower US liquids production and weaker liquids realisations.

The Energy products segment also delivered earnings of $1.376 billion, below the 8-K implied range. Despite record first-quarter throughput of 87% utilisation, margins were likely weaker than anticipated. Conversely, the Chemicals segment showed significant q/o/q improvement with increased volumes and better margins. ExxonMobil continues structural cost reductions, saving an additional $0.4 billion this quarter, reaching $10.1 billion cumulatively.

ExxonMobil distributed $6.8 billion to shareholders in Q1 2024, including $3.8 billion of dividends and $3.0 billion of share repurchases. The buyback program was briefly paused prior to the Pioneer Natural Resources special shareholder meeting. The Pioneer transaction, expected to close in Q2 2024, will increase the annual shares buyback pace to $20 billion.

Upon completion, ExxonMobil will focus on integrating Pioneer assets. This will expand its Permian footprint to over 1.4 million net acres in the Delaware and Midland basins, with an estimated resource of 16 billion barrels of oil equivalent (boe) and projected production of 2 million barrels of oil per day (mmboe/d) by 2027.

Shell continues to be an exciting rate-of-change story

Shell reported Q1 2024 adjusted EPS/CFPS of $2.38/$4.95, exceeding consensus estimates of $1.99/$4.21. This strong performance was driven by the Integrated Gas and Chemicals & Products segments, which outperformed expectations by approximately $800 million and $550 million, respectively. While the Upstream segment missed consensus by ~$250 million, this was offset by robust downstream results. Better-than-expected Downstream was largely attributed to Shell high refinery utilisation of 91% during a quarter of favourable margins and planned maintenance shutdowns at competitor facilities.

Shell’s management, led by CEO Wael Sawan and CFO Sinead Gorman, has revamped the company’s culture to focus on operational efficiencies, pivoting back towards its core oil and gas segments, while curbing low-carbon spending at the margins. Though early in this process, two consecutive quarters of outperformance and ongoing structural cost reductions including those reaching $1 billion in 2023, suggest Shell is on track to achieve its target of exceeding 10% per share FCF growth by 2025.

Chevron: Upstream execution drives performance

Chevron reported Q1 2024 adjusted EPS of $2.93, meeting consensus estimates of $2.90. This alignment was driven by robust performance in US retail marketing and a slight outperformance in Exploration and Production (E&P). Total oil and gas production for Q1 2024 averaged 3,346 thousand barrels of oil equivalent per day (mboe/d), exceeding the consensus of 3,288 mboe/d due to stronger US liquids and gas output. 

Worldwide upstream adjusted net income of $5.2 billion slightly surpassed consensus estimates of $5.1 billion, with international E&P earnings primarily responsible for the positive variance. Downstream net income fell marginally below consensus at $700 million compared to the expected $778 million. Chevron returned $6 billion to shareholders in Q1 2024, maintaining an equal split between base dividends and share repurchases.

Chevron anticipates swift clearance by the SEC and FTC in relation to the pending Hess acquisition. Among the assets Chevron would acquire through the takeover is Hess' stake in an offshore oil block situated off the coast of Guyana, Stabroek Block. However, a contentious dispute concerning Guyana is casting a shadow over the transaction. ExxonMobil, holding a 45% stake in the Stabroek Block, claims a right of first refusal over Hess's 30% stake.

Institutional Shareholder Services (ISS), a prominent proxy advisory firm, has recommended that Hess shareholders abstain from voting on the proposed $53 billion takeover by Chevron. ISS has said Hess investors should support a delay in the proceedings to allow for further details regarding an arbitration process initiated by ExxonMobil to come to light. The shareholder vote on the deal is scheduled for 28th May.

ConocoPhillips Q1 2024 results meet expectations, production guidance revised

ConocoPhillips reported adjusted EPS/CFPS of $2.03/$4.32, aligning with consensus estimates of $2.04/$4.28. Total production averaged 1.90 mmboe/d, within the midpoint of the 1.88 - 1.92 mmboe/d guidance range. While North American earnings were softer than expected, international segments outperformed. Weather disruptions impacted production by 25 mboe/d during the quarter, slightly exceeding the anticipated 20 mboe/d impact. The company disclosed ongoing board discussions regarding a potential primary listing on a US exchange to broaden its US investor base.

For Q2 2024, production guidance is set between 1.91 - 1.95 mmboe/d, below the consensus estimate of 1.94 mmboe/d. Scheduled turnarounds will impact production by 25 mboe/d in Q2 2024 and 90 mboe/d in 3Q 2024. FY2024 guidance remains unchanged.

ConocoPhillips’ major projects, including the Willow project in Alaska, US, are progressing as planned following the first major winter construction season. The company reaffirmed its commitment to a planned return of capital exceeding $9 billion in 2024. During Q1 2024, ConocoPhillips distributed $2.2 billion to shareholders. This consisted of $1.3 billion in share repurchases and $0.9 billion in ordinary dividends and variable return of cash (VROC). The company maintained its ordinary dividend at $0.58/share and VROC at $0.20/share.

TotalEnergies eyes US listing

TotalEnergies reported adjusted EPS/CFPS of $2.14/$3.34 in Q1 2024, modestly exceeding consensus estimates of $2.06/$3.38. Total production of 2,461 mmboe/d surpassed guidance of 2.45 mmboe/d. TotalEnergies concluded positive appraisal work on the Venus oil discovery in Namibia, progressing towards a Final Investment Decision (FID) in 2025 for a potential development of 150-180 mbbl/d capacity.

For Q2 2024, TotalEnergies anticipates an average LNG selling price between $9-10/mmBtu. Hydrocarbon production is projected at 2.40 - 2.45 mmboe/d, reflecting planned maintenance activities, while refining utilisation is expected to exceed 85%. Net investment guidance remains within the $17 - 18 billion range for 2024. 

Eni SpA beat estimates, dividend reaffirmed, buyback increased

Eni SpA delivered robust Q1 2024 results, with a group operating income of €3.03 billion and adjusted net income of €1.58 billion, surpassing consensus estimates of €2.78 billion and €1.56 billion, respectively.

The Enilive and Plenitude segments achieved an operating income of €427 million. Exploration and Production (E&P) operating income reached €2.33 billion, exceeding consensus by 3%. The Gas & Power segment saw operating income of €293 million, below the consensus forecast of €500 million, due to reduced trading opportunities stemming from lower prices and volatility relative to the previous year.

Eni SpA generated €1.9 billion in free cash flow for Q1 2024 due to strong quarterly operating cash flows (CFO) of €3.9 billion and capital expenditures of €2.0 billion.

In March, the company completed its FY23 buyback program, repurchasing 153.5 million shares for €2.2 billion between May 2023 and March 2024. Additionally, the company increased its FY24 buyback to €1.6 billion from the previous guidance of €1.1 billion. EniSpA also reaffirmed its FY24 dividend of €1.0 per share, paid quarterly beginning in September 2024.

For FY2024, EniSpa maintained upstream hydrocarbon production guidance of 1.69 - 1.71 mmboe/d, announced during its Capital Markets Day on 14th March. Organic capital expenditure guidance was confirmed at a range of €7 - €8 billion. Group EBIT guidance was revised upwards to exceed €14 billion, reflecting a revised Brent scenario of $86/barrel.

Drivers of change: geopolitical and structural

Several broader factors have influenced the performance of the oil and gas sector over the past quarter, with growing geopolitical risks particularly swaying performance. The chief concerns to investors include the ongoing conflict in Ukraine, the war between Gaza and Israel, and the activities of Iran's proxies in the Middle East. Structural factors also play a role, such as the consolidation of the US oil and gas industry within the Permian Basin, the ongoing voluntary production cuts implemented by OPEC+, and the persistent effects of capex underinvestment in the sector.

The continuing war between Russia and Ukraine

Europe's gas and energy map has changed fundamentally following Russia’s attack on Ukraine and the introduction of sanctions against Russia. While Russia accounted for 42% of European imports of natural gas in 2021, this had fallen to 14.0% by 2023, comprising 5.3% LNG and 8.7% pipeline gas. Gazprom, majority owned by the Russian government, saw its revenues decline 41% in H1 2023 compared to H1 2022, mostly driven by the 45% drop of the Title Transfer Facility (TTF) gas price in RUB terms. Its operating profit dropped more than 66%, to around $10 billion vs $37 billion in H1 2022. Based on the current price, at 31.83 EUR/MWh, H1 2024 seems to be on a similar trajectory with the TTF gas price in RUB down 39% y/o/y. Russian pipeline gas to Europe is currently restricted to flows entering Ukraine at the Sudzha interconnection point, with deliveries via the European string of TurkStream. A total of around 80 million cu m/d currently flows into Europe by pipeline, but half of this could be lost when Russia and Ukraine’s transit deal expires at the end of 2024. Ukraine and the EU have not signalled any intention of extending this agreement.

Iranian backed attacks: Downstream most affected 

Attacks by the Iranian backed Houthis in the Red sea and the Indian ocean have contributed to price increases in refining and freight markets. Although vessels are opting for the longer route around the Cape of Good Hope to avoid direct and drone attacks, the actual implications for crude flat prices remain modest ($3 - $4/bbl) despite a full redirection. However, this rerouting has exacerbated existing tightness in tanker markets, leading to a spike in tanker freight rates. 

Oil flows through the Bab-El-Mandeb Strait have declined significantly, down 3.2 mb/d (or 44% on a 14-day moving average basis) compared to the 2023 pre-disruption average. This has directly contributed to rising global freight rates for both clean (finished refined products such as gasoline or diesel) and dirty (crude or residual) oil tankers.

Regional product price differentials have widened accordingly. The Europe-Singapore (E-S) diesel spread and Japan-Europe (J-E) naphtha spread have expanded as net importing regions – Europe for diesel and Asia for naphtha – absorb higher freight costs. The E-S spread has increased 4$/bbl, while J-E 1$/bbl, on a 7-day moving average basis since attacks by the Houthis in the Red sea area started on 18th December, 2023.

More importantly, forecasts for the next few years highlight a regional mismatch between supply growth sources in the Americas and rising demand and refining capacity in Asia and the Middle East. This structural shift will further increase demand for oil transportation.

Nevertheless, the rise in long-haul travel demand could translate to higher average freight rates, ultimately affecting refined product cracks in net importing regions. This has implications for forecasting crude and product differentials, as well as refined product cracks in key markets like New York Harbour and North West Europe (Amsterdam Rotterdam Antwerp), which are net short of refined products. The rising freight rates lift the cost curve of marginal molecules, benefiting domestic refiners in those regions.

New supply: The consolidation of US shale oil

The 2009 - 2016 oil & gas revolution was led by US exploration and production companies. However, the industry is now undergoing a significant consolidation. It is transitioning from a market populated by numerous smaller drilling companies to one dominated by a few large, publicly listed players. As noted by the Financial Times, according to data from consultancy firm Wood McKenzie, 

• Ten companies now control over 6.4 million barrels of oil equivalent per day (boe/d) within the Permian Basin's total 12.1 million boe/d output.
• Six of these companies produce over 700,000 boe/d each, surpassing the output of some OPEC nations.
• ExxonMobil and Diamondback Energy control approximately 50% of acreage in the Permian's Midland sub-basin.

These firms have shifted their focus towards prioritising shareholder returns over increasing production levels, signalling a departure from the US’ traditional role as a global swing producer, capable of rapidly adjusting output to influence global oil prices.

Diamondback Energy's $26 billion acquisition of Endeavor Energy Resources on 12th February underscores the ongoing consolidation trend in the US shale sector. The total value of mergers and acquisitions (M&A) in the industry has increased to approximately $180 billion since early 2023, significantly transforming the landscape of the shale sector. Other key deals are ExxonMobil's acquisition of Pioneer Natural Resources for roughly $60 billion, and Chevron's $53 billion purchase of Hess.

A decade ago, shale's capacity for rapid output increases effectively moderated oil prices. However, over the past five years, investor emphasis on returns has refocused companies towards shareholder distributions rather than drilling growth.

In contrast, private operators, unconstrained by dividend and buyback demands, maintained production increases. Within the Permian Basin, top private companies Endeavor, Mewbourne, and CrownRock doubled their production between early 2021 and late 2023, while public companies achieved single-digit annual growth rates.

The acquisitions of Endeavor by Diamondback Energy, and of CrownRock by Occidental Petroleum, are potent symbols of industry transformation. These transactions signal the end of an era characterised by private operators creating volatile boom-and-bust cycles. The formation of these newly enlarged major companies will likely result in a reduction in volatility within the Permian. As these larger oil companies are more likely to pursue consistent strategies, they are less inclined to adjust operations based on short-term price fluctuations, resulting in more stable activity levels.

Old supply: OPEC+ supply cuts

On 1st January, Angola formally withdrew from OPEC, following similar exits by Ecuador in 2020 and Qatar in 2019. Angola produces approximately 1.1 million barrels per day (bpd), a relatively small amount compared to the group's total output of 28 million bpd. However, Angola had struggled to meet its OPEC+ production quota due to declining investment.

In November 2023, OPEC+ reduced Angola's oil production target for 2024 to 1.11 million bpd. Angola, which had requested a quota of 1.18 million bpd, disagreed with the lowered target and submitted a formal protest to OPEC. Angola quit OPEC+ because its quota limits hindered the country’s plans to stabilise crude production above 1 million bpd, according to Mineral Resources Minister Diamantino Azevedo.

On 29th January, Saudi Arabia announced it was abandoning its plan to grow its own capacity to 13.0 mmbbl/d by 2027 from its current 12.2 mmbbl/d. This significantly reduced the longer-term over-supply risk.

On 3rd March, OPEC+ announced the extension of voluntary production cuts totaling 2.2 million bpd through Q2 2024. Saudi Arabia agreed to continue its additional voluntary reduction of 1 million bpd through the end of Q2, putting its crude output at approximately 9 million bpd until the end of June.

Voluntary cuts, unlike formal policy changes, do not require unanimous consent during official meetings and avoid the need for complex quota reallocations among OPEC+ members. This flexibility allows for streamlined output adjustments in accordance with existing policy.

OPEC+'s next policy discussions are due to take place in June. It is widely expected current supply cuts will be extended into 3Q 2024.

Consequences of the ‘Age of Restraint’

Underinvestment in the Oil sector, coupled with a heightened focus on returns, deleveraging, free cash flow, operational efficiency, and sustained capital discipline, has significantly impacted oil resource life. This phenomenon is characterised by a market that undervalues undeveloped resources due to a high risk premium. In this landscape, value accrues to companies capable of self-financing development and managing risk through a diversified portfolio that offers economies of scale. Exploration and production companies (E&Ps) have seen the most substantial reduction in resource life over the past decade, while Big Oil has exhibited a more stable pattern.

Oil assets are increasingly becoming stranded, meaning that they lose value or turn into liabilities before the end of their expected economic life. Oil remains stranded in the ground. This has largely been driven by the market's shift away from resource expansion and towards the transition to low-carbon energy sources. However, 2023 marked a turning point, with higher returns and a renewed emphasis on energy security incentivizing the industry to resume investment growth.

As a result, Big Oil has strategically shifted its focus towards cost discipline and maximising production uptime, fundamentally rethinking its approach to oil and gas project development. By concentrating on brownfield developments, these companies have been able to unlock "short-cycle" hydrocarbon resources within their core area of expertise, offshore operations. These projects offer several advantages, such as shorter development timelines and higher returns, leading to immediate benefits in the form of reduced decline rates (the lowest in 20 years in 2022 and 2023) and improved project execution. However, these developments also tend to have shorter lifespans, suggesting a tougher long-term supply picture.

Key projects to drive discovery, cash flow, production, and diversification

Big Oil retains the exclusive ability to generate value through exploration drilling. Galp has emerged as a leader in exploration success this year, with its substantial estimated 10 billion-barrel discovery in Namibia in April of 2024. Eni SpA has also engaged in successful exploration activities including Zohr in Egypt, Mamba-Coral, Agulha in Mozambique, Mexico Area 1, and multiple oil discoveries in Angola's Block 15-06. Hess made significant discoveries in Guyana's Stabroek block between 2015 and 2023.

Operating cash flow (CFO) growth is expected to be driven by several project start-ups and ramp-ups. Eni SpA anticipates significant CFO growth from 2023 to 2028, with key projects including the launch of deepwater Baleine field Phases 2 and 3, the build-up of Congo LNG, the expansion of North Field East LNG, and the start-up of multiple gas fields in Indonesia (Gendalo, Gehem, and Geng North) in 2027 and 2028.

Galp also forecasts CFO growth with the launch of the Bacalhau oil field in Brazil in 2026. Ithaca Energy is poised to benefit from the development of the deepwater Rosebank field in the UK, while Aker BP is expected to see gains from the Noaka development in Norway.

TotalEnergies, and Shell stand to benefit from increased production due to a record number of projects either currently coming online or in the process of ramping up.

TotalEnergies's most important projects include Blocks 1-3 in Uganda, the deepwater Libra field in Brazil, the launch of additional floating production, storage, and offloading (FPSO) vessels, the expansion of North Field East LNG in Qatar, and the development of gas field Block SK408 in Malaysia.

Shell's largest projects encompass LNG Canada, gas field Block SK318 in Malaysia, the Libra deepwater oil field in Brazil, and the deepwater Whale project in the Gulf of Mexico.

ExxonMobil and ConocoPhillips are expected to grow with the expansion of offshore projects with ExxonMobil focusing on Guyana. Both companies are expanding operations in the Permian Basin.

ExxonMobil is also projected to assume a leading position among US Big Oil companies in terms of net cash flow growth, primarily due to its operations in Guyana. Within the US exploration and production (E&P) sector, Diamondback Energy, Devon Energy, and Apache stand out due to their strong production and cash flow growth, primarily attributed to their activities in the Permian Basin.

Conclusion

Despite the Energy sector's subpar earnings growth in Q1 2024, it is the sector whose estimates for Q2 2024 have seen the most significant upward revisions during this earnings season. This suggests strong underlying dynamics that may mitigate volatility and enhance profitability for major oil companies within the sector.

The rally in the Energy sector has been propelled by heightened market expectations for oil demand. The International Energy Agency (IEA) has revised its 2024 oil demand growth forecast upwards, citing robust demand data outside of China and positive GDP revisions. Stronger demand from Europe as its economic prospects brighten further reinforces the optimistic outlook for oil prices.

Although the geopolitical risk premium, reflecting investor apprehension about potential supply disruptions due to geopolitical events, escalated following attacks on Russian refineries and as tensions heightened between Iran and Israel, the cost of insuring against oil price spikes, measured as the implied volatility of call options (Brent 3-months ahead), remains below the levels observed in October 2023 and 2022, primarily due to the stability of Middle Eastern crude production.

Another positive is that we are seeing a heightened focus on capital discipline across the industry, resulting in fewer project delays and curtailed capital expenditures in LNG. Last year marked the third consecutive year of capex growth primarily driven by increased investment in LNG projects. This was itself spurred on by the volatile commodity price environment and renewed emphasis on energy security in Europe.

The sustained period of high interest rates has been a key driver in strengthening the US dollar this year, consequently exerting downward pressure on global oil demand. Furthermore, the increased cost of borrowing associated with these higher rates may deter major oil companies from initiating new projects, potentially impacting future production levels and overall supply. The cost curve for oil production has been consistently rising since 2017 due to project delays, inflation in capital and operating expenses, increased taxes, and a rising cost of capital for hydrocarbon projects. This necessitates higher oil prices to incentivise incremental production.

In this new landscape, capital expenditures are shifting towards short-cycle, short-life projects. While these projects offer quicker returns and reduced decline rates, they also decrease visibility into long-term resource life, raising concerns about the sustainability of future production levels.

Industry consolidation, coupled with stricter lending standards and heightened scrutiny of new project proposals, is fostering a more stable and less cyclical market environment. This enhanced market structure is resulting in higher barriers of entry, improved returns and more efficient project execution for existing players. Additionally, the increased rigour in project evaluations is contributing to a significant rise in the projected profitability of new ventures. In summary, this confluence of underlying factors may lead to a more profitable sector in Q2 2024 and beyond.

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