How to Invest in Oil and Gas: Private vs. Public, Unit Economics, and the Supply Non-Response
Written By: Ryan Morrison
Listen On: YouTube | Apple Podcasts | Spotify | Amazon Music
2026 Asset Allocation Report
See how 230+ HNW investors with an average net worth of $17M are allocating across public equities, private markets and alternative assets.
Most investors who want oil and gas exposure buy an energy ETF or a share of Exxon and call it done. That gives them exposure to the commodity, and to everything else the public market decides to layer on top of it: ESG sentiment, index rebalancing, analyst downgrades, and the rotation decisions of funds that have nothing to do with whether oil is coming out of the ground. How to invest in oil and gas as a private operator, or alongside one, is a fundamentally different question, and the mechanics are almost entirely absent from the standard financial media playbook.
Blake London co-founded Formentera in 2020 and has raised approximately $3 billion across five funds while operating nearly 4,000 wells producing 70,000 barrels of oil per day across the U.S. and Australia. Before Formentera, he spent 15 years at Credit Suisse as head of energy equity capital markets. That combination of institutional capital markets experience and hands-on operator judgment shapes every argument in this conversation, which was recorded live with the Long Angle community on April 22, 2026.
TL;DR
Private upstream oil and gas investing breaks into three structures: operated positions, non-operated working interests, and mineral rights and royalties, each with a different risk profile and degree of control over timing and returns.
A cash-flow-focused private operator who returns capital through ongoing production is structurally insulated from the ESG-driven multiple contraction that causes public energy stocks to underperform even when operations execute well.
Shale wells drill and complete in six to twelve months, pay back in twelve to twenty-four months at reasonable oil prices, and decline roughly 70% in the first year before settling into a long production tail.
The muted price response to the largest supply disruption in history reflects financial market optimism about a quick resolution, algorithmic trading dynamics, and a structural behavioral shift among public operators whose shareholders demand capital discipline over production growth.
The strongest long-term case for private energy investing is not the current price spike, it is that tier-one drilling inventory is finite, long-term prices remain near historical lows, and future global demand requires higher prices to justify the next generation of development.
The Three Ways to Invest in Upstream Oil and Gas
Private upstream oil and gas investing breaks into three structures: operated, non-operated, and minerals and royalties, each with a different risk profile, return potential, and degree of operator control.
Beyond those three, there is midstream infrastructure, which typically runs through dedicated infrastructure funds and has expanded well beyond traditional energy pipelines into data centers and other asset classes. Downstream, refining and distribution, is largely a public markets category, with little meaningful private entry point for most investors. For those evaluating private energy exposure, the decision almost always lives in the upstream tier.
Operated positions — higher competition barrier, higher return potential
An operated position means you are investing with the company that is drilling, completing, and managing the wells. Operators control the decisions: when to drill, what pace to develop at, how to respond to price changes. That control comes with responsibility, you have to stand up a technical team capable of running the operation, and that requirement is exactly what limits competition.
Blake's view on this is direct. The barrier to entry in operated positions is not just capital. It is the ability to build a team that can actually run wells. That narrows the field considerably relative to non-operated or royalty structures where, as he puts it, "all you need in reality is money." Fewer competitors chasing operated positions means the return profile is less compressed by financial players bidding up the same assets.
Non-operated working interests — the timing problem most investors underestimate
A non-operated working interest means you own a fractional share of a well alongside an operator you do not control. The economics can be similar to an operated position. You share proportionally in revenues and costs, but you have no say in when the operator drills, how much they spend, or what pace they develop the acreage.
That timing dependence is the underappreciated risk in non-op investing. You are making a larger bet on an operator you did not select in a timeline you cannot predict with any certainty. As competition for non-op positions has grown, financial players can participate without building an operating capability. Return profiles have compressed relative to operated structures where that same competition simply cannot show up.
Mineral rights and royalties — lower risk, but you do not control your destiny
Mineral rights and royalties have attracted significant private equity attention over the past decade precisely because they strip away operational risk. As a royalty owner, you receive a share of revenue from production without bearing any of the operating costs. You are not on the hook for drilling bills, service cost inflation, or equipment problems.
The tradeoff is real: you pay for that downside protection in the form of lower returns and, more importantly, in the loss of timing control. Your returns depend entirely on when the operator decides to drill and develop. A royalty stream over undeveloped acreage can sit dormant for years waiting on an operator's capital budget decisions. As Blake notes, that is a risk investors in minerals and royalties have to get comfortable with. You do not control your destiny from a timing perspective.
Beyond Wealth Newsletter
How HNW founders and executives navigate the questions wealth creates — grounded in peer data and Long Angle community discussions. Free, delivered every Thursday.
Private vs. Public Energy Investing — Why They Are Not the Same Bet
Buying a private oil and gas operator and buying Exxon or Chevron are fundamentally different investments. One gives you exposure to the underlying commodity economics, the other gives you exposure to public market sentiment layered on top of those economics.
The distinction matters because those two things can diverge sharply and for extended periods. A public energy company can execute its drilling program exactly as planned, hit its production targets, and generate strong cash flows, and its stock can still underperform if the broader market is rotating away from energy, if ESG-driven capital constraints are widening spreads, or if the index weighting of the sector has shrunk to the point where passive rebalancing creates structural selling pressure.
The ESG and sentiment overlay that private investors avoid
Energy's share of the S&P 500 has declined from roughly 15% at its peak to approximately 2.8% today, a contraction that reflects not just commodity price cycles but a sustained capital flight driven by the anti-fossil fuel movement and the performance disappointments of the prior decade. That decline reshaped how public company management teams are incentivized. When energy was 15% of the index, growth-oriented investors rewarded production growth. With energy at under 3%, the remaining investor base (mutual funds and dedicated energy funds) demands capital discipline, dividend consistency, and return of cash. The business model of the publicly traded operator has changed at the ownership level.
For a private investor, that shift creates an opening. The same dynamics that have compressed public valuations and suppressed supply response have also driven capital out of the sector, reducing competition for well-positioned private operators and leaving assets available at prices that work even at conservative oil price assumptions.
Why cash-flow return models change the exit multiple equation
The key question for any private energy investor is whether the fund's return model depends on timing an exit to a public buyer or a strategic acquirer, or whether it can return capital through ongoing production cash flows.
If the model is build-and-flip, public market multiple contraction matters directly. A public company trading at a compressed multiple cannot pay as much for assets, and that ceiling flows directly through to private market valuations. That is the mechanism through which public sentiment affects private returns in exit-dependent models.
Cash-flow-focused models work differently. As Blake explains it, "if you can return capital along the way, you can create a lot more certainty of the outcome and be a lot less sensitive to timing." A fund that targets 20 to 40% fully-burdened returns on individual wells and distributes cash as production flows does not need the public market to agree with its energy thesis. It needs oil above breakeven and wells that produce. When that combination holds, the fund delivers regardless of what the S&P 500 energy weighting does next quarter.
What multiple contraction does and does not affect in private structures
Multiple contraction in the public market is not irrelevant to private energy operators. It matters when assets are being bought or sold. When public multiples are compressed, private operators are also often buying assets at lower cash flow multiples, which can be a meaningful advantage on the entry side. The contraction that hurts exit-dependent models can benefit acquisitive operators expanding their base.
The discipline required is keeping the return model grounded in production economics rather than exit timing. That is a structural choice made at fund inception, not something that can be retrofitted after prices move.
The Unit Economics of a Shale Well
A typical shale well in the U.S. costs six to twelve months from decision to first production, pays back within twelve to twenty-four months at reasonable oil prices, and declines roughly 70% in its first year before stabilizing into a multi-decade production tail.
Those numbers vary meaningfully by basin, commodity mix, and rock quality — but they establish the basic rhythm of shale investing that every private energy investor needs to internalize before evaluating an operator or a fund.
Breakeven prices by basin — Permian, South Texas, North Dakota
The Permian Basin is widely considered the highest-quality shale acreage in North America and probably the world. It is also the most expensive. Tier-one acreage in the Permian trades at $30,000 to $40,000 per acre, or upward of $4 million per drilling location. Individual well returns at a normalized $70 oil price can run 50 to 60%, but that return has to be weighed against the premium paid for the land. The consequence has been substantial consolidation by large public operators who can stomach that cost — and diminishing opportunity for smaller privates finding new entry points at reasonable prices.
Other plays offer different tradeoffs. The Permian can be drilled profitably at roughly $35 to $40 per barrel breakeven. South Texas runs closer to $40. North Dakota sits in the $45 to $50 range. Higher-cost plays require $50 to $60 or above. As Blake summarizes it, the average marginal well needs oil north of $60 to truly justify new drilling — which is why when prices dropped below that threshold, 50 rigs came off in a matter of months.
A 12-day drilling time for a three-mile horizontal well in North Dakota illustrates how the short-cycle nature of shale differs from conventional oil. The speed from decision to production is what makes shale the effective swing producer in global oil markets — when operators choose to use that optionality.
The service cost lag and why early-cycle returns are the best you will make
One of the more operationally specific insights in this conversation is the service cost lag dynamic. When oil prices spike, service providers — drilling contractors, completion crews, casing suppliers — do not reprice immediately. There is roughly a six-to-nine month lag before service costs follow prices higher. During that window, an operator already running a drilling program captures the full benefit of higher prices without yet absorbing the higher costs.
The inverse is equally true. When prices fall, service costs lag on the way down as well, creating a period of margin compression before the cost base adjusts. This is why operators who hedge judiciously at the beginning of a price rally — locking in baseline margins before the cost base inflates — can extract returns that later entrants to the same price environment will not achieve.
What "20 to 40% returns fully burdened" actually means for investors
Target returns of 20 to 40% fully burdened mean the calculation includes both the cost to acquire the land or project and the cost to develop it — not just the well economics in isolation. A well with strong individual returns in a basin where land cost $4 million per drilling location produces a very different fund-level return than the same well in a play where acreage was acquired at a fraction of that price.
The production timeline reinforces this. A well that makes 2.5 to 3 times invested capital over its life and pays back in 12 to 18 months generates roughly a third to 40% of its total return in year one. The remaining return accrues over a well life that can extend 30 to 40 years at declining but persistent production rates. That long tail is the asset base a cash-flow-focused operator is holding and managing over time.
If you're re-evaluating your portfolio allocation, you're asking the same questions Long Angle members bring to the platform every week.
Long Angle members collectively hold $100B+ in net worth and deploy deploy $100M+ annually into institutional-quality private market investments, including private equity, private credit, real estate, secondaries and more.
Every offering goes through independent investment team underwriting, a recorded GP diligence call, and a community forum thread where members who've already evaluated or invested in the same deal post their questions, concerns, and decisions publicly.
Participation is completely optional. Members review every deal with no expectation to invest.
Why the Largest Oil Supply Disruption in History Has Not Produced a Proportional Price Spike
The muted price response to an unprecedented supply disruption reflects a structural behavioral shift among public operators, financial market speculation on a quick resolution, and a genuine disconnect between the physical oil market and paper futures.
The intuitive expectation — that removing 10 or 15 million barrels per day from global supply would push prices to $150 or higher — runs into a more complicated reality. Understanding why prices have stayed in the $80 to $90 range despite the disruption requires separating the financial market from the physical market, and separating what public operators will do from what private operators are doing.
The physical market versus the financial market disconnect
The financial market for oil and the physical market for oil are pricing different things right now. WTI futures — the paper market — reflect the probability-weighted expectation of where oil will be across the forward curve, heavily influenced by algorithmic trading, macro fund positioning, and optimism about how quickly the conflict might resolve. Physical barrels in the Middle East have been trading at a significant premium to that paper price, reflecting the reality of actual supply constraint for refiners who need to buy crude today.
As long as financial markets are pricing in a quick resolution, WTI futures will remain below what the physical tightness would imply. If the disruption persists and contracts roll forward, those futures will need to reprice toward physical reality. The backward-dated curve structure — where near-term futures are lower than forward months — will eventually force a reckoning as each contract approaches delivery.
Why public operators are not adding rigs — and whose decision that actually is
The absence of a supply response is one of the most consequential facts about the current oil market, and it requires understanding a structural shift in how public energy companies are managed.
A decade ago, when energy represented roughly 15% of the S&P 500, growth-oriented investors rewarded production growth. The entire shale industry was built on a model of outspending cash flow to accelerate net asset value accumulation. That model produced a lot of oil and a lot of value destruction for investors, and the capital rotation out of the sector that followed forced a fundamental business model change.
Public shale operators are now explicitly managed to prioritize free cash flow, dividend consistency, and share buybacks over production growth. Their management teams are incentivized by those metrics, and their remaining investor base punishes capital budget increases that might compromise cash return commitments. As Blake notes, adding five rigs into a $90 price environment when futures suggest oil may be back below $80 by October is not the decision a public company management team will make — not because they cannot, but because their shareholders do not want them to. Independent analysis from S&P Global Commodity Insights and the Dallas Fed Energy Survey confirms this structural dynamic has held across multiple price cycles since the late 2010s.
Private operators, without public shareholders to answer to, can move more quickly when the economics justify it. Accelerating a planned rig by a few months, pre-hedging new development at higher prices to lock in margins — those are decisions private operators make. Adding a multi-rig program on the basis of a price spike that may not last is not something either public or private operators are doing at scale.
What the supply non-response means for private operators and investors
The supply discipline that prevents a large price-suppressing response also preserves the margin environment that makes private operator economics work. The same behavioral shift that frustrates analysts expecting a shale surge is protecting the returns of operators who are already drilling and producing.
For investors evaluating private energy at this moment, the relevant question is not whether prices will stay at $90. It is whether the operator's return model works at the price the hedge book locks in — and whether the assets being acquired today are priced at levels that generate acceptable returns even if prices normalize to pre-war levels.
The Long-Term Investment Thesis — Hold for the Long Term, Trade the Short Term
The strongest case for private oil and gas investing is not the current price spike — it is that long-term oil prices remain near historical lows, tier-one drilling inventory is finite, and future global demand requires prices significantly above current levels to incentivize the next generation of development.
Near-term volatility is real and consequential, but it is not the investment thesis. Across Formentera's operating history, near-term oil has moved from the $50s to $130 and back, while long-term futures have stayed range-bound in the high $50s to low $70s. That long-term stability, combined with a structural case for rising demand and diminishing easy supply, is what Blake describes as the actual basis for investment conviction.
Why long-term prices matter more than near-term volatility
A private energy investor with a five-to-ten year horizon is not trying to time a quarterly price move. They are making a judgment about whether the assets they are acquiring today, at today's land prices and today's service costs, will generate acceptable returns across the range of plausible long-term price environments.
That framing changes the calculus. An operator who can demonstrate 20 to 30% returns at $60 oil — and who hedges opportunistically when prices spike to protect that baseline — is not dependent on the war continuing, on OPEC maintaining discipline, or on the financial market's next narrative about energy transition. The investment works or it does not based on the underlying geology, the cost structure, and the operational competence of the management team.
The energy addition argument — why AI, data centers, and population growth support long-term demand
The conventional framing of the energy transition assumes that oil and gas demand will decline as renewable capacity grows. Blake cites the OPEC secretary general's reframe — delivered at the major industry conference ADIPEC in Abu Dhabi — that we are not in energy transition but energy addition. The argument is straightforward: AI infrastructure, data centers, population growth in Africa, India, and Southeast Asia, and the ongoing electrification of emerging market economies all require enormous amounts of reliable, low-cost energy. Renewables will grow, but the scale of incremental demand means oil and gas will need to grow alongside them, not be replaced by them.
Natural gas is a particular beneficiary of this dynamic. U.S. natural gas is currently a domestic, weather-driven market because there is not enough LNG export capacity to connect domestic prices to global LNG prices. As new export facilities come online — a process that was paused under the Biden administration and has reaccelerated — domestic gas prices are expected to converge toward global LNG over time. AI data center demand adds another layer of structural demand growth that was not in the calculus five years ago.
How to think about the 30-year horizon without getting it wrong
The 30-year question — whether oil and gas are still relevant at the end of the investment period — is intellectually interesting and largely irrelevant to the investment decision at hand. Blake's response to this is precise: you are probably not going to need to hold these assets for 30 years. There will be opportunities in higher-price environments to monetize assets, redeploy capital, and take advantage of new opportunities that emerge over time.
The operational framework is: hold for the long term, trade the short term as opportunities arise. Build a resource-ownership base with cash-flow-focused assets that work at $60 oil. Layer in hedges at price spikes to lock in baseline margins. Accelerate planned activity where practical. Use option structures where available to extend information advantage without committing capital irrevocably. That combination of patient asset ownership and opportunistic capital deployment is what Blake argues creates the most durable return profile across the price cycle.
As he puts it: "If you go into it thinking, I can make a lot of money just holding assets into end of life over the next 30 or 50 years, you can make really attractive returns. And then you allow for opportunistic windows and times over the next 10 years to take advantage of that to bring value forward."
Frequently Asked Questions
What is the difference between operated and non-operated oil and gas investments?
An operated position means you invest with the company drilling and managing the wells; a non-operated interest means you invest alongside an operator whose decisions on timing and spending you cannot control. Operated positions carry a higher competition barrier because investors must be able to stand up a technical operating team, which limits the field to serious operators. Non-operated positions require only capital and technical underwriting ability, which means the investor base is broader and returns have historically been more compressed. The practical consequence is that timing uncertainty — when the operator will drill, how much they will spend, and at what pace they will develop the acreage — is a risk non-op investors accept in exchange for not having to run the operation themselves.
How do private oil and gas funds generate returns without selling to a public buyer?
Cash-flow-focused private operators return capital to investors through ongoing production revenue rather than timing an exit sale, making their return profile less sensitive to the public market multiple environment. The return model is built around production economics — the cost of acquiring and developing the assets, the price received for the oil or gas produced, and the pace at which that capital is returned to investors over time. A fund that generates strong production cash flows and distributes them consistently does not require a strategic buyer to pay a premium multiple on exit. Exit-dependent models, by contrast, are directly exposed to the valuation environment of potential acquirers — which in energy has been compressed by ESG-driven capital constraints and index weight reduction.
What oil price is needed for a shale well to be profitable?
Breakeven prices vary by basin — the Permian can be drilled profitably at roughly $35 to $40 per barrel, while other plays require $50 to $60 or above, with the average marginal well needing north of $60 to justify new drilling. These figures reflect full-cycle economics including drilling, completion, and land acquisition costs for development wells. Existing production on already-developed acreage can be sustained at much lower prices — the breakeven for pumping an already-producing well is far below the breakeven for drilling a new one. The distinction matters for investors evaluating operators: a fund holding significant producing assets has a different downside risk profile than one primarily deploying capital into new drilling programs.
Why hasn't the oil supply disruption caused prices to go much higher?
Financial markets are pricing in a relatively quick resolution to the current conflict while physical barrels remain significantly tighter, and public operators are structurally unwilling to add rigs because their shareholders have demanded capital discipline over production growth. The disconnect between physical barrels — where Middle East crude has been trading at a substantial premium to WTI futures — and the paper market reflects speculative positioning and algorithmic trading that weights toward an optimistic resolution scenario. Separately, the supply non-response from U.S. shale reflects a deliberate management choice by public operators who have transformed their business models from production growth to capital return. Private operators are moving more quickly, but they represent a smaller share of total production capacity.
How long does it take for a shale well to pay back its initial investment?
Most shale wells pay back their drilling and completion costs within twelve to twenty-four months at normalized oil prices, though production declines roughly 70% in the first year before settling into a long-lived but lower-output tail. The payback period is a function of both the oil price received and the initial production rate, which is highest immediately after completion and declines steeply in year one. An investor making roughly a third to 40% of total well return in the first year — with the balance accruing over a 30 to 40-year production life — is in a structurally different position than an investor waiting for a single exit event. The rapid payback dynamic is one reason shale investing is considered short-cycle relative to conventional oil projects, where payback periods can extend for many years.
What is the natural gas investment thesis and how does it differ from oil?
U.S. natural gas is currently a domestic, weather-driven market, but LNG export capacity growth and AI data center demand are expected to drive a structural convergence between domestic gas prices and global LNG prices over the next several years. Natural gas prices were not materially affected by the Middle East supply disruption because the U.S. does not yet export enough LNG to connect domestic prices to global supply constraints. As new export terminals come online — a process reaccelerated after the pause under the previous administration — that connection will tighten. The secular demand driver from AI infrastructure and data center buildout adds a layer of domestic demand growth that was not part of the investment thesis a few years ago. Natural gas is currently trading in contango, with futures prices above spot, reflecting the market's expectation of tightening domestic supply and demand as those export and demand drivers materialize.
How do mineral rights and royalties differ from working interest ownership in oil and gas?
Royalty owners receive a share of revenue from production without bearing operating costs, while working interest owners share proportionally in both revenue and expenses, giving them higher return potential but also greater exposure to operator decisions and cost overruns. The practical distinction for investors is control: a royalty owner has no say in when or how the acreage is developed, while a working interest owner — especially in an operated fund structure — retains meaningful influence over development timing and capital allocation. Royalties have attracted significant private equity capital over the past decade because they provide commodity exposure without operational risk. The tradeoff is that royalty values are directly dependent on an operator's willingness and ability to develop the underlying acreage, which can make returns highly variable depending on the quality and activity level of the operators holding the corresponding working interests.
Final Thoughts
The conversation with Blake London leaves one distinction standing above everything else: buying sentiment and buying fundamentals are not the same bet, and the gap between them is unusually wide right now. Energy represents less than 3% of the S&P 500. The capital that once rewarded production growth has migrated to technology and AI infrastructure. The management teams of public operators have responded exactly as their remaining shareholders demanded — with discipline, cash returns, and a studied reluctance to chase price spikes. That behavioral shift is the reason there has been no supply response to the largest disruption in oil market history.
For a cash-flow-focused private operator, this creates an environment where the fundamentals support the investment thesis and the behavioral dynamics of the dominant players preserve the margin environment that makes it work. Whether the current price level sustains, normalizes, or retraces, an operator with assets that generate strong returns at $60 oil does not need the macro thesis to be right on any particular timeline. They need the wells to produce, the cost base to remain manageable, and the hedges to be in place when opportunities to lock in margins appear.
That combination of operational control, cash-flow discipline, and patient resource ownership is what distinguishes private energy investing from its public market equivalent — and what Blake argues makes this one of the more durable return environments the sector has seen.
The decisions that come with meaningful capital — including how much private energy exposure belongs in an alternatives portfolio — are easier with peers who are working through the same questions.
Long Angle is a vetted community of 8,000+ high-net-worth founders, executives, and investors who compare notes on exactly these decisions. Members access peer research, private market investment opportunities vetted by a dedicated investments team, and candid conversations with others who have navigated similar complexity. The 2026 Long Angle Asset Allocation Report — drawn from 233 verified members with an average net worth of $17.3M — shows that private and alternative assets average 28% of portfolio across the membership, with that share increasing significantly at higher wealth tiers.
Membership is selective and requires verification of investable assets.
Resources Mentioned
Formentera — Blake London's company (formentera.com)
Long Angle 2026 HNW Asset Allocation Report — longangle.com
U.S. Energy Information Administration, Decline Curve Analysis — eia.gov/analysis/drilling/curve_analysis/
Subscribe to the Navigating Wealth Newsletter — longangle.com/navigating-wealth-podcast
