How to Invest in Oil and Gas: A Guide for Private Investors
Written By: Ryan Morrison
Based on a Navigating Wealth conversation with Blake London.
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Oil and gas investing looks straightforward from the outside: buy Exxon, or don't. The actual landscape for private investors is considerably more varied, and the differences in structure, return profile, and risk between the segments matter significantly. Blake London co-founded Formentera in 2020, has raised roughly $3 billion across five funds, operates nearly 4,000 wells producing 70,000 barrels of oil equivalent per day, and spent 15 years before that as head of energy equity capital markets at Credit Suisse. His framework for how private investors should think about oil and gas exposure is built from the inside of the market, and the current macro environment adds an unusually specific context to the general framework.
Private investors can access oil and gas through three upstream segments: operated positions (investing with the company drilling and managing wells), non-operated working interests (investing alongside an operator with proportional upside and no operational control), and minerals and royalties (owning a royalty stream that pays regardless of operating costs). Each carries a different return profile, risk structure, and degree of control over timing and development decisions.
Key Takeaways
The three private upstream oil and gas segments (operated, non-operated, and minerals and royalties) carry meaningfully different return profiles, risk structures, and levels of investor control
Shale well economics are highly compressed: a typical well pays back its drilling cost in 12–24 months, generates roughly 70% of its total production in the first year of peak output, and continues producing for 30–40 years
Private oil and gas operators offer more direct exposure to fundamental performance than public energy stocks, which carry sentiment, ESG narrative, and index rotation risk that can disconnect from actual operational results
The US shale industry has shifted from a growth-oriented model to a capital-discipline model; operators are rewarded for returning cash flow, not adding rigs, which explains why price spikes produce less supply response than in prior cycles
Natural gas has a compelling secular thesis driven by LNG export expansion and AI data center demand; US gas prices are expected to converge toward global LNG prices as export terminals come online
The Three Ways to Invest Privately in Oil and Gas
Most investors default to public energy stocks when they want oil and gas exposure. Within the private markets, there are three distinct upstream segments, each with a different risk and return profile.
Operated positions mean investing with the company that drills, completes, and manages wells. The operator controls every material decision: timing of development, which locations to drill, how to manage production. Competing for operated assets requires a team that can run an operation, which limits the competition to a smaller pool of sophisticated participants than other segments attract. For investors, an operated fund gives the most direct exposure to management's skill and operational execution.
Non-operated working interests mean investing proportionally alongside an operator in specific wells or acreage. The investor participates in the same well economics as the operator but has no say in operational decisions. The return profile on individual wells can be comparable to operated investments, but the investor is making a larger bet on an operator they do not control, on a development timeline they cannot predict. Blake's observation is pointed: the barrier to entry in non-operated is lower (all you need is capital and the ability to underwrite the opportunity), which means more competition for the same assets and generally thinner return differentiation over time.
Minerals and royalties mean owning a fractional interest in the subsurface resource itself. When an operator drills a well on land where you own mineral rights, you receive a royalty payment off the top line of production revenue, regardless of operating costs or capital expenditures. This structure is the most defensive of the three: no operational risk, no capital calls, no exposure to cost structure. The tradeoff is that you do not control when development happens; that is entirely the operator's decision; and the return profile tends to be lower than operated positions precisely because the downside protection is priced in.
Beyond upstream, there is a private midstream market primarily accessed through dedicated infrastructure funds. Downstream and oilfield services have largely returned to the public markets; meaningful private investment in those segments is limited.
Watch the Full Conversation
This article draws on a Navigating Wealth conversation with Blake London, where we discuss how private oil and gas investing works, what shale well economics look like, why the industry is no longer responding to price spikes with new rigs, and how to think about energy as a portfolio allocation. Watch the full episode for the broader discussion.
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Blake London is co-founder of Formentera, a private oil and gas upstream operator focused on shale production in the US and Australia. He began his career in oil and gas investment banking at Credit Suisse, where he spent 15 years and eventually led the energy equity capital markets business. He co-founded Formentera in 2020 with the thesis that capital flight from the sector created an opportunity to combine an upstream operator with a private equity fund structure, emphasizing cash flow and risk-adjusted returns over production growth.
Shale Well Economics: What the Numbers Look Like
Shale well economics are fundamentally different from conventional oil in their speed and their production profile. Understanding both is essential to evaluating any private oil and gas investment.
The timeline from drilling decision to first production runs roughly six to twelve months. Drilling itself is fast: in North Dakota, Formentera drills a three-mile horizontal well in twelve days. In more complex formations in South Texas, the same process takes twenty to twenty-five days. The time between the decision to drill and the point where a well is generating revenue is measured in months, not years.
Production decline is steep in the early years. A shale well will typically produce roughly 70% less at the end of its first year of peak production than it did at its peak, a pattern that looks alarming until you account for the fact that the same well continues producing, at a declining but steady rate, for thirty to forty years. A typical shale well returns 2.5 to 3 times invested capital over its life.
Well payout periods run twelve to twenty-four months depending on oil price and well quality. A development program combining acquisition of acreage and drilling of that acreage targets 20 to 30% IRR. Individual well returns are higher, but the cost of acquiring the land is part of the total investment package.
Break-even thresholds vary by region:
| Basin | Break-even oil price |
|---|---|
| Permian (Tier 1) | ~$35–$40/bbl |
| South Texas | ~$40/bbl |
| North Dakota (Bakken) | ~$45–$50/bbl |
| Average marginal well | $60+/bbl |
The Permian Basin carries the lowest break-even costs in North America, and accordingly commands the highest land prices, currently $30,000 to $40,000 per acre or roughly $4 million per tier-one drilling location. In less competitive plays, acreage costs are lower but break-even oil prices are higher. The investment decision comes down to whether the return profile at a normalized oil price justifies the combination of acreage cost and development cost.
Oil and Gas Mineral Rights and Royalties
Mineral rights in oil and gas represent ownership of a fractional interest in the subsurface resource beneath a piece of land. When an operator drills a well on land covered by mineral rights you own, you receive a royalty payment (typically a percentage of gross production revenue) regardless of what it costs to produce that oil or gas. The royalty sits off the top line, not the bottom line.
This structure attracted significant private equity attention over the past decade because of its perceived defensive qualities. Without operational risk, without capital calls, and without exposure to operating cost inflation, mineral rights and royalties offer commodity price exposure through a less volatile financial structure than an operated working interest. Large dedicated PE funds formed specifically to aggregate mineral rights positions, and the asset class became a recognizable alternative investment category.
The practical limitations are worth understanding clearly. The fundamental constraint is that you do not control when development happens. An operator who owns the working interest decides when to drill, how fast to develop the acreage, and how to sequence their capital program. A mineral rights owner with a large position in an underdeveloped area may wait years for the operator to get to their acreage. In the meantime, their royalty income is limited to whatever production is already flowing.
Return profiles in minerals and royalties tend to run lower than operated positions, partly because the lack of operational complexity lowers the barrier to entry and drives more competition for good assets. Minerals and royalties are best held as long-term positions where patience with development timing is part of the investment approach rather than a source of frustration.
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Why Private Beats Public for Fundamental Energy Exposure
Energy as a sector has undergone a dramatic shift in its public market weighting. At its peak, energy represented roughly 15% of the S&P 500. Today it sits around 2%. That compression was driven by the long bull market in technology, the ESG movement's rotation away from fossil fuels, and institutional index funds mechanically reducing their energy exposure as the weighting fell.
The practical implication for investors in public energy stocks is that a company can execute exactly what it said it would execute, deliver the production it promised at the costs it projected, and still see its stock underperform because of factors that have nothing to do with its operational performance. The S&P rotation happens, sentiment shifts, or a large index fund rebalances. The stock price moves independently of the underlying business.
Private oil and gas operators offer a narrower band of outcomes relative to actual operational performance. If the investment thesis plays out, the returns track the performance of the assets more directly. The investor does not need to worry about whether an index fund decided to reduce energy exposure this quarter. The tradeoff is that there is no daily liquidity and no ability to exit at any moment.
Blake's framing is precise: private energy investing is for someone who wants fundamental commodity exposure and is willing to accept illiquidity in exchange for outcomes that track actual performance rather than market sentiment. How private credit compares as an alternative investment provides a useful parallel structure for thinking through the same private vs. public tradeoff in credit markets.
The sensitivity to exit multiples is also different. Private oil and gas returns are typically measured on cash-on-cash IRR and multiple of money, not on enterprise value multiples at exit. A cash flow-focused fund can return capital to investors without needing to sell assets at a public-comparable multiple, reducing reliance on timing the exit to a favorable market environment.
Why the Shale Industry Is No Longer Adding Rigs When Prices Spike
Until around 2019, US shale operated on a simple growth logic: if you can drill it, drill it. Operators reinvested every dollar of cash flow and more, prioritizing production growth over capital returns. Institutional investors rewarded that behavior when energy was a significant portion of the S&P and production growth drove valuation. When energy's S&P weighting collapsed, so did the reward for growth.
The remaining shareholders in public energy companies pushed hard for a different model: capital discipline, modest growth, and cash flow return through dividends and buybacks. Management teams that reverted to growth-at-any-cost were penalized. The business model changed fundamentally, and it has not reverted despite the current price environment.
The implication for supply response to price spikes is direct. A large public operator facing an oil price that moved from $57 in January to $90 in April, with futures markets pricing a reversion toward $75 by October, is not going to commit to a twelve-month rig contract and order several months of casing based on a spike it expects to partially reverse. The company's shareholders do not want the production growth; they want the cash flow. And the volatility itself, oil going from $50 to $130 and back to $60 in the span of a few years, has made operators deeply cautious about capital commitments that take six to twelve months to generate first production.
Service cost dynamics compound the hesitation. During a price rally, drilling service providers begin raising prices, but the increase arrives with a six-to-nine-month lag. The first months of a spike are the best period for operator margins precisely because service costs have not yet reset to the new price environment. An operator who locks in a long-term rig contract during the spike will watch margins compress as service costs catch up. The rational response is to run existing programs more efficiently and hedge new production rather than aggressively adding capacity.
The result is that price spikes today generate hedging activity, modest acceleration of planned programs, and cautious evaluation of new rig adds, not the supply surge that characterized earlier shale cycles. Private operators, who are not accountable to public shareholders on the same timeline, have somewhat more flexibility to be dynamic, but even private operators face the same uncertainty about where prices will be in twelve months.
The Natural Gas Secular Thesis
US natural gas has been a domestic commodity for most of its history: priced by weather, supply, and local demand, largely disconnected from global energy markets. That is beginning to change, and the transition creates a specific investment thesis.
The current US natural gas production capacity far exceeds domestic export infrastructure. The limiting factor on US gas prices has not been supply or demand. It has been the absence of enough LNG export terminals to connect domestic prices to global LNG prices. Qatar, which handles a substantial share of global LNG trade, recently had a major export facility disrupted, and the perceived LNG glut that had been expected over the next several years largely evaporated overnight.
LNG export terminals under construction and recently permitted in the US will begin coming online later this year and into 2027. As export capacity grows, US gas prices will increasingly be set at the intersection of domestic supply and global LNG demand rather than by US weather patterns alone. Current US gas prices in the mid-single digits per million BTU are substantially below global LNG prices. Convergence, even partial, represents a significant price upside for US gas producers.
The demand pull is structural and growing. Artificial intelligence and data center buildout will require substantial incremental electricity generation over the next decade. Natural gas is the lowest-cost, most reliable bridging fuel for that demand in the US. The Energy Information Administration projects continued growth in gas demand from power generation even under conservative electrification scenarios.
Blake's framing of "energy addition, not energy transition" captures the investment implication. Global population growth, rising living standards in developing economies, and the extraordinary energy demands of the AI buildout all point toward sustained and growing oil and gas demand regardless of the long-term renewable energy trajectory. The question for investors is not whether oil and gas remain relevant for the next decade (the answer is clearly yes) but whether the investment is structured to capture that value over time with appropriate management of downside scenarios.
Evaluating private oil and gas operators requires current, practitioner-level intelligence that is hard to find outside a structured peer network.
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How to Think About Private Oil and Gas as a Portfolio Allocation
The investment thesis for private oil and gas is not primarily about the current oil price. Near-term volatility, while it creates opportunistic entry points, is not the foundation of a durable allocation decision.
The medium-to-long-term case rests on two structural observations. First, global capital has left the sector at a scale and speed that is unusual even by energy industry standards. With energy representing roughly 2% of the S&P 500 and dedicated energy PE funds having contracted significantly since 2015, the competition for good private assets is lower than it has been in decades. Second, global Tier 1 inventory (the most productive, lowest-cost acreage) is being consumed at a rate that will require the development of higher-cost resources over time. The marginal cost of the next barrel of global supply is rising, which creates a structural floor under long-term oil prices even in scenarios where near-term demand softens.
For investors who want private oil and gas exposure, the practical framework is hold for the long term, play for short-term opportunities as they arise. The long-term thesis generates the baseline return. Price spikes and capital dislocation events create windows to improve entry economics. A well-structured fund with disciplined operators can layer in hedges during price spikes to protect downside while retaining upside on unhedged production, compressing the range of outcomes in a volatile commodity market.
The due diligence questions that matter most: What is the operator's track record on cash-on-cash returns across full cycles, not just in favorable price environments? What are the break-even costs of the assets being acquired or developed? How does the fund handle hedging, and what percentage of production is hedged at any given time? What is the fee structure, and how is the promote aligned with investor outcomes? And critically, for operated funds, what is the team's operational capability, not just their capital markets or financial background?
For context on how high-net-worth investors are currently sizing private energy allocations relative to other alternatives, the 2026 asset allocation report covers current allocation patterns across 230+ respondents at an average net worth of $17M. Alongside private energy, alternative investments like hedge funds and private credit provide complementary return profiles worth considering in the context of a broader alternatives allocation. Long Angle's private market investment offerings provide members with access to institutional-quality private energy opportunities alongside peer diligence.
Frequently Asked Questions
What are the main ways to invest in oil and gas privately?
The three primary private upstream segments are operated positions (investing with the company drilling and managing wells), non-operated working interests (investing proportionally alongside an operator without operational control), and minerals and royalties (owning a royalty stream off production revenue regardless of operating costs). Each carries a different return profile, risk structure, and level of investor control over development timing.
What is a working interest in oil and gas?
A working interest is an ownership stake in an oil and gas well or lease that entitles the holder to a proportional share of production revenues and requires them to bear a proportional share of drilling, completion, and operating costs. An operated working interest means the holder controls the operation; a non-operated working interest means the holder participates financially alongside an operator who makes all operational decisions.
How do oil and gas mineral rights and royalties work?
Mineral rights represent ownership of a fractional interest in the subsurface resource. When an operator drills on land covered by your mineral rights, you receive a royalty payment off the top line of production revenue, typically a percentage of gross sales, regardless of what it costs to produce the oil or gas. The primary limitation is that you do not control when the operator drills; development timing is entirely the operator's decision.
Why do private oil and gas investments sometimes outperform public energy stocks?
Public energy stocks carry risks that are unrelated to operational performance: ESG-driven selling pressure, declining S&P 500 index weighting, and rotation toward or away from the sector based on macro sentiment. A public operator can execute its plan perfectly and still see its stock underperform because an index fund reduced its energy weighting. Private investments track actual performance more directly, with returns measured on cash-on-cash IRR and multiple of money rather than public market multiples.
Why hasn't the US shale industry responded to higher oil prices with more drilling?
The US shale industry shifted from a growth-oriented business model to a capital-discipline model over the late 2010s and through COVID. Public shareholders now reward operators for returning cash flow through dividends and buybacks, not for adding production capacity. In a volatile price environment where oil can move from $57 to $90 in weeks and back toward $75 in months, signing long-term rig contracts and committing large capital programs is difficult to justify. Operators are managing existing programs more efficiently and hedging new production rather than aggressively adding capacity.
Final Thoughts
Energy investors who want exposure to actual commodity fundamentals rather than public market sentiment have one clear path: private upstream oil and gas. The structure gives direct exposure to the performance of the assets without the overlay of ESG narratives, S&P index rebalancing, or quarterly earnings pressure pushing operators toward decisions that serve shareholders over the medium term.
The current environment is unusually specific. Long-term oil prices remain at historical lows despite the near-term supply disruption. The operator base is the most capital-disciplined it has been in decades, which means assets are being managed for cash flow rather than growth. Natural gas has a secular demand thesis that is just beginning to be priced in. For investors with the appropriate risk tolerance and liquidity horizon, the combination of structural underinvestment and durable demand creates an investment case that does not depend on predicting where spot oil trades next month.
Private energy is the kind of allocation decision that benefits from honest peer conversation, not just manager pitches.
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