Energy Sector Investment Perspectives For 2026
Energy investing is rarely hard because the math is complicated, but hard because cycles mess with judgment. When oil is cheap and the sector is hated, it feels irresponsible to touch it. When oil is expensive and headlines are everywhere, it suddenly feels like the simplest trade in the world. That’s typically when investors take the most risk for the least incremental reward.
As with most investing topics, we think the right way to evaluate energy equities is as a mosaic, with the mind and machine working together to weigh the evidence. You don’t need one perfect indicator, but a set of clues that improve your odds of avoiding two classic mistakes in energy: showing up too late and owning the wrong subsector for the environment. What follows is a brief review of recent and long-term energy subsector performance; our thoughts on why the unfolding cycle may look different than the prior cycle; a framework for thinking about which sub-sectors tend to lead at the onset of an energy cycle; and a breakdown of two specific sub-sectors to watch over the coming months and years (depending on the length of the current cycle) with specific, data-driven indicators to watch. Additionally, in the appendix we provide a brief overview of each of the main energy sub-sectors.
Energy Stocks Don’t Act the Same in Every Cycle
Many assume investing in energy (oil and gas, specifically) stocks is simply one trade based on oil and gas prices. In reality, the energy complex is a collection of very different businesses that respond to different triggers. Some are in fact tied tightly to commodity prices, while some are tied to activity levels like drilling and completions. Others behave more like long-duration cash flow machines, where contract structure and capital allocation matter more than the spot price of oil.
That distinction matters because the market does not reward oil exposure the same in every cycle. Oil prices are typically the catalyst but spending and activity are typically the factors that drive value-creation (and destruction) throughout the cycle, and therefore are key to uncovering equity leadership ahead of the crowds.
To provide a baseline on where we are today, in terms of leadership, we highlight energy sector and sub-sector stock index performance on a near-term and long-term basis in “Refiners Have Outperformed Over the Last Year, While Midstream (Pipelines) and E&Ps Lagged” (exhibit 1) and “Long Term Energy Sector and Sub-Sector Price-based Index Returns” (exhibit 2).
Why This Cycle May Look Different Than the Shale Boom Years
Capital discipline is now religion. The mid‑2010s downturn and COVID forced a painful reset. Many producers that survived have de-leveraged and made “returns over growth” a default posture. Dividends and buybacks aren’t a “nice to have” anymore. In many boardrooms, they are the core promise to shareholders.
This matters because the classic chain reaction (oil rises → E&Ps flood the field → rig counts explode → services go vertical) may not be as automatic as it used to be. Management teams may choose to return cash rather than reinvest aggressively, especially if they don’t trust the duration of the price move. Oil and gas exploration and production company EOG Resources (ticker: EOG) is a capital discipline evangelist of sorts and provides several anecdotes of this behavior. On their most recent earnings call on February 25, 2026, management characterized their flat Permian basin production outlook as an exercise in capital restraint: “Given the macro environment, we are keeping oil production flat with fourth quarter 2025 levels, which results in annual oil production growth of 5% and total production growth of 13%. We can deliver this disciplined plan for a capital budget of $6.5 billion.” Additionally, EOG based their production forecast on oil prices — at the time – well below current levels based on the futures curve: “Our breakeven price to cover the 2026 capital program and regular dividend is $50 WTI (West Texas Intermediate).”
The private capital behind the shale boom is not what it used to be. The shale era had a giant tailwind from the private equity industry, which was at the time flush with cheap money to deploy, filling in for a banking industry still reeling from the financial crisis. Today, with higher rates and a notably different risk environment, the availability of capital for marginal drilling is more constrained.
That doesn’t mean shale disappears. It means the industry’s ability to respond quickly and aggressively to rising prices may be more restrained. For investors, that has two implications that can coexist: (1) Less oversupply response can extend the cycle’s duration, but (2) it can also shift opportunity away from higher-risk growth and toward high-quality execution.
The marginal barrel may be more international with a longer lead-time. The Permian Basin remains a world-class resource, but multiple independent data providers, sell‑side analysts, and Permian‑exposed executives now agree that Tier 1 inventory is largely depleted. While absolute production may continue to grow near‑term, future gains will require higher capital intensity as geology and higher water-to-oil and gas-to‑oil ratios limit repeatability of historical productivity gains. Meanwhile, global energy demand doesn’t pause while U.S. shale debates the reinvestment rate (see above point on capital discipline).
If incremental supply increasingly comes from international capacity expansions and offshore developments, that changes who benefits most. Long-cycle markets tend to reward companies with scale, integration, and project execution. This is one reason we believe large, well-capitalized service firms and offshore/subsea supply chains could be more central players in this upcycle.
However, we must note, given the conflict in Iran and the Middle East broadly, international exposure comes with geopolitical risk. In a March 11, 2026 Form 8-K filing, SLB N.V., formerly Schlumberger, (ticker: SLB) disclosed that Middle East disruptions were expected to reduce first quarter revenue and create additional costs, with an estimated earnings impact of roughly $0.06 to $0.09 per diluted share. This is a good reminder that international cycles can be attractive, but not smooth, and that like mining operations, jurisdiction and location should always be front and center in underwriting equity risk.
A Practical Road Map of What Tends to Lead Based on Cycle
People often say that oilfield services are the “tip of the spear” and generally lead out of the gates in an upcycle, followed by the E&Ps. While there is certainly truth in that, we prefer a more conditional way of describing leadership. It depends on what the market believes about the duration of the move in the commodities. When investors get whipsawed in energy, it’s often because they think they’re buying one thing, but they’re actually buying another. A helpful way to structure this is based on how the sector reacts to three different views on the duration of the oil move, and how we characterize the returns generated by those views.
1. If oil rises but investors don’t trust it, the market often prefers short-cycle commodity exposure like certain exploration and production companies (E&Ps) and treats the move as a trade. These businesses move most with oil and gas prices and the forward curve. We characterize the returns here simply as “oil beta.”
2. If oil rises and the market starts believing it, leadership often shifts toward activity and pricing power. This is where oilfield services (OFS) will typically lead and outperform. These businesses benefit when industry spending rises and the service supply chain tightens. The equity upside historically has come not just when revenue climbs, but when utilization tightens and pricing power shows up in incremental margins.
3. If the cycle broadens into international/offshore, the market starts to focus on visibility and leadership can shift again toward backlog, project awards, and execution. In other words, the parts of the ecosystem that benefit from long lead-time investment. Large service platforms, offshore/subsea participants with backlog, many integrated majors, and midstream “toll-road” models often show up here.
In the shale boom era, a lot of investors built their energy toolkit around scenario #1 (beta and leverage). In this cycle, we believe the better risk-adjusted approach may lean more heavily toward scenario #2 and #3 earlier than investors are used to. Why? Because capital discipline dampens the “growth impulse” that once made pure commodity beta the easiest trade.
Since the recent pre-war lows in oil prices on December 16, 2025, energy equities have largely moved with oil (exhibit 3, “WTI Crude Oil Prices Have Outpaced Energy Equities Since War Broke Out”). The notable standout was Oilfield Services, which tends to move with oil as a cycle develops, but moved well ahead of the commodity leading up to the war. The OFS group has underperformed since the war broke out (for reasons we discussed in regards to risks of international exposure, vis a vis SLB’s press release about Middle Eastern activity levels). The outperformance of the commodity relative to the stocks since the war broke out is not surprising given the physical nature of the supply disruption. However, we also believe this may point to the market not trusting the commodity move (scenario #1), and thus there is room for catch-up potential should oil prices sustain higher levels. In other words, we don’t think it’s too early to consider certain energy sub-sectors.
Two Energy Subsectors to Watch
The preceding sections, notwithstanding, were not suggesting that commodity prices won’t have a large impact on sentiment and performance across each energy sub-sector. They will. And the broad sector will certainly provide exposure to commodity prices and the sub-sector specific return drivers detailed. For those willing and able to be more tactical and look for areas of the sector to potentially add differentiated returns from the broad sector, we highlight two specific areas we believe are well-positioned for the current environment and beyond.
Refiners: Capacity Constraints Can Keep Utilization Rates High, With or Without Conflict
We highlight the refining sub-industry because we believe the world is entering a period where gasoline, diesel, and jet fuel may stay relatively scarce and valuable compared with crude oil. In simple terms, refiners make money on the spread between what they pay for raw inputs (i.e., crude oil) and what they can sell finished products (i.e., gasoline, diesel, jet fuel) for; in the industry, that spread is known as the crack spread. While every conflict is unique, the war in Iran re-surfaces the familiar issues these periods of conflict and geopolitical instability typically bring, namely disrupted shipping routes, changes in trade flows due to sanctions, and a general feeling of fragility in the global economy. In these scenarios, fuel markets often tighten because supply becomes harder to move and replace. At the same time, no significant greenfield refinery has been built in the U.S. since the Ford administration, the refinery count has been cut nearly in half since 1982, and existing refineries are expensive and slow to replace, all limiting supply even further. If this environment continues, crack spreads can remain high for longer than normal, which should support earnings and cash flow for well-run refiners.
If a prolonged Iran war keeps European Brent benchmark prices higher relative to the U.S. benchmark West Texas Intermediate (WTI), U.S. refiners should see margins expand, particularly through product exports to Europe. A widening Brent-WTI differential supports higher crack spreads for U.S. refiners against a backdrop of structurally tight global refining capacity. Gulf Coast refiners, operating highly complex facilities optimized for discounted heavy, sour crude, are well positioned to enhance margins vs. simpler global peers. Resilient demand for distillates (diesel and jet fuel) and seasonal strength in gasoline during summer driving season support utilization and profit.
The indicators we are watching in the refining industry (specifically domestic refiners) are specific product-level crack spreads (diesel, jet fuel, gasoline, etc.), refinery utilization rates, inventories, and export-driven demand pull.
• Crack spreads, specifically diesel and jet fuel cracks, provide high-level signal on refining margins. Refined product supplies can remain constrained even when input (crude oil) supplies normalize or are abundant. Refining stocks move directionally with crack spreads, especially in periods of extreme spikes (exhibit 4, “Refiner Equities Tend To Move With Crack Spreads…”), and this dynamic then appears in gross margins due to the expected uplift in profitability (exhibit 5, “…And Refiner Margins Follow Crack Spreads (On A Lag)”. Currently, diesel and jet fuel margins are unusually high due to supply disruptions and sanctions-related tightness. Watching these products specifically, and whether these unusually high product cracks hold above seasonal norms and don’t mean-revert will provide a signal that these levels are due to refining capacity bottlenecks, not solely crude supply constraints.
• U.S. product inventories and Gulf Coast utilization levels. If inventories continue running below five-year averages, and utilization levels remain north of 92–93%, this could signal that capacity is running tight enough for refiners to maintain pricing power.
• Refined U.S. product exports and European (Atlantic basin) inventory levels. Many U.S. refiners serve as “swing” suppliers to foreign markets, therefore if domestic exports of diesel and gasoline remain strong as European inventories decline, this could signal that domestic refiners are capturing displaced global supply and that the market remains short products, not just crude oil inputs.
The important risk management caveat for investors to note is that all of the above can still be overwhelmed by a real demand shock to the economy. If recessionary conditions hit trucking, industrial activity, or air travel hard enough, cracks can compress even with closures and low inventories.
Oilfield Services (OFS): Global Exposure to Supply Response and Reserve Diversification
Another energy sub-sector we are watching is Oilfield Services (OFS), given the global need to replace depleting oil & gas reserves, and the desire to diversify resource supply. The Iran war has once again exposed how fragile reliance on Middle East resources is, be it oil, natural gas, or refined products. That is not to say that a post-war Middle East won’t continue to be a key energy producing region; its resource-rich geology assures that it will be. It is our view, however, that the impulse from regions dependent on those resources, such as Europe and Asia, will be to diversify their supply base, and thus increase spending (capex) on exploration and development in other parts of the world. This potential for increased capex flows first to OFS companies, primarily the “big three” U.S. headquartered companies SLB Ltd (Ticker: SLB), Halliburton Co. (Ticker: HAL), and Baker Hughes Co. (Ticker: BKR). In other words, the current geopolitical shock is not just an oil shock, but a potential catalyst for higher activity across more basins.
What makes the setup especially attractive is that this demand response is running into real capacity constraints, particularly offshore, where years of underinvestment have left the market tight. At the same time, a longer-cycle secular tailwind is developing as more countries try to export the Permian playbook to their own tight-rock (shale) resources. This favors the large, technologically capable OFS players that can bring drilling, pressure pumping, reservoir expertise, and completion know-how abroad.
The indicators we are watching in terms of the OFS industry are capital spending plans from global E&Ps, international spending plans and project sanctioning, and pricing/utilization/backlog.
• Much of energy producer capex translates to OFS revenue. Oil and gas exploration, development, and production (often referred to as “upstream” activity) from E&Ps, integrated oil companies (IOCs), and national oil companies (NOCs) is largely executed by OFS companies. This dynamic is apparent in the time-series chart “Oilfield Services Revenue Largely Tied to Oil & Gas Producer Capital Spending” (exhibit 6). Therefore, an upward inflection in upstream activity (i.e., producer capex plans) provides a potential signal for increased OFS revenue; investors have already begun to expect this, as shown via consensus revenue estimates. The chart also shows the reduction in overall investment from the high levels seen at the peak of the shale boom (2011–14), pointing to broad-based underinvestment in resource development. While those figures certainly include elevated service pricing amid a tight market (not to mention a flood of available capital) and efficiency gains, we must also note these are nominal figures from 12-15 years ago.
• International spending plans and project Final Investment Decisions (FIDs). If a supply response does in fact show up across more diverse geographic locales, we would expect to see increased international spending plans from large global E&Ps and IOCs relative to domestic spending. This is showing up in outlooks from companies such as ExxonMobil (Ticker: XOM), Chevron (Ticker: CVX), and ConocoPhillips (Ticker: COP), who have all highlighted the growing importance of international and offshore projects to supply growth. Meanwhile, as efficiency gains appear to be offsetting maturing fields in the U.S. Permian in terms of production, spending plans in the region have largely been flat to down. Another indication of international spending comes from offshore FID announcements, which then flow to subsea infrastructure and service awards, which are supplied by OFS companies.
• Increased activity should lead to an increase in OFS and rig contractor backlog and utilization, which will lead to pricing power for OFS providers and rig owners. An indicator to watch that also provides a signal on the prior point of international spending is offshore rig day rates and utilization. Given the importance of ultra-deepwater (UDW = >7,500 ft ocean depth) resource plays, focus on new contracts, day rates, and utilization for the high specification UDW drillships that can access these far-flung oil fields. If day rates and utilization start to inflect higher and contracts start getting written for longer terms, that is usually the earliest sign that spare capacity is tightening and service pricing power is returning. In “Marketed Utilization Suggests a Tightening Market for High-Spec UDW Drillships” (exhibit 7), we show average day rates and marketed utilization for UDW drillships. This matters because offshore supply is structurally constrained after years of underinvestment, minimal new build rigs, and fleet attrition, so once utilization firms up the earnings leverage can be sharp.
The main caveat to consider is that timing will not be perfectly linear. Offshore can see near-term noise from project delays in specific regions, and international shale adoption (i.e., exporting the Permian playbook) may be slower than some assume. That said, the broader direction for activity and pricing power still looks favorable, in our view.
