A Due Diligence Framework for Oil and Gas Investing

By Dylan Robertson

Oil and gas (O&G) syndications appeal to high income earners and experience LP’s already swimming in private markets. While O&G can offer cash flow, tax deductions against active income, and exposure to a non-correlated asset class, the due diligence playbook is quite unique. Therefore, I hope to add value by sharing the framework I personally use to navigate this complex asset class.

How I Got Here

I'm an accountant by trade and have worked in several industries, including oil and gas and ocean logistics. Over the past six years, I have also invested in more than 20 deals across multiple asset classes, including two oil and gas funds. Those experiences shaped this framework, and my goal is to help investors make informed, risk-adjusted decisions.

Why Oil and Gas Requires a Specialized Framework

Risk mitigation is the most important filter when evaluating an oil and gas investment. For LPs new to the space, understanding these risks is also the largest hurdle to investing. Below are six risks to incorporate into your due diligence framework.

1. Sponsor Risk

Every other risk on this list runs through the sponsor, so it is the right place to start. Before reviewing projections, check the following:

• Offering documents. Search SEC EDGAR for the offering's Form D. Confirm the issuer name, exemption claimed, and amount raised match what the sponsor told you.
• LP reviews. Check the sponsor's Invest Clearly profile for verified reviews from existing LPs.
• Team and advisors. Look for petroleum engineering, geology, or operating experience on the team or advisory board, alongside the financial expertise needed to manage a fund.
• Track record. Request results for every prior fund, including wells drilled, dry-hole rate, projected versus actual production, and distributions per dollar invested. Ask how quickly distributions began; interests in producing wells can generate cash within a few months of closing, while new drilling can take 12 to 18 months to come online.
• Third-party professionals. Confirm the fund uses independent legal counsel, an outside CPA firm for audited financials, and tax preparers experienced in oil and gas.
• Key person risk. Small teams often depend on one or two people. Ask who would manage the fund if a principal left, and whether the operating agreement addresses it.
• Reporting and candor. Quarterly business reviews open to all investors show a willingness to explain results. Ask current investors how the sponsor communicated when results fell short.

2. Drilling Risk

Drilling risk is the chance that a new well produces far less than projected, or nothing at all. How LPs evaluate it depends on how the fund is structured.

For a fund that partners directly with an operator, the reserve report is the oil and gas equivalent of an appraisal. Ask who prepared it and who paid for it; an independent petroleum engineering firm carries more weight than an in-house estimate. Then look at how reserves are classified, since the categories carry very different levels of certainty:

• Proved developed producing (PDP): Reserves from wells already flowing.
• Proved undeveloped (PUD): Reserves in proven areas that require drilling capital before they produce.
• Probable and possible: Lower-confidence estimates that deserve heavy discounts.

Non-operated working interest (NOWI) funds typically have no single reserve report, since they buy small stakes in many wells drilled by different operators. For these funds, diligence shifts to the quality of the operators, the sponsor's process for selecting wells, and results from comparable wells nearby.

Location also matters. Exploratory or "wildcat" wells in unproven areas carry the highest dry-hole risk. Programs limited to proven locations near existing production reduce that risk considerably. Ask what share of a sponsor's past wells actually produced; strong development-focused sponsors can point to few or no dry holes.

Diversification is another key defense. A single-well or single-operator program concentrates risk in one set of geology and one team. A fund holding interests in dozens of wells, run by multiple established operators across several basins, limits the damage from any one disappointing well.

3. Commodity Price Risk

Every projection rests on price assumptions for oil, natural gas, and natural gas liquids. LPs should compare those assumptions against industry cost data and ask what happens to distributions if prices fall.

A sponsor modeling today's elevated prices across a multiyear hold is building in optimism. Ask for projections at several price levels (a sensitivity analysis), including one near the relevant basin's breakeven. Also ask whether the fund hedges any production, and how revenue splits between oil and natural gas, since the two prices often move independently.

4. Decline Curve Risk

Production from shale wells falls quickly after the initial flush, and that curve drives every distribution. Research from Enverus found that average U.S. shale oil well production is declining faster each year.

Ask the sponsor to show the decline curve in its model and the offset wells behind it. Then ask how the fund plans to counter decline. In my experience, only a handful of funds reinvest a portion of cash flow into additional working interests, which grows the asset base and helps offset the inevitable decline. Full return of capital is one of the most common shortfalls in oil and gas funds, and reinvestment can improve both the odds of getting capital back and the final equity multiple. The tradeoff is lower distributions in the early years.

Reinvestment also determines whether a sale at the end of the fund's life is realistic. Buyers value oil and gas assets on current production and remaining reserves. A fund that distributes all of its cash flow while its wells decline will hold a shrinking, less valuable asset by the end of its term. A fund that keeps adding working interests can maintain production and reserves, which keeps a sale or recapitalization realistic. Ask the sponsor to describe its exit plan and the production level it assumes at the time of sale.

5. Fund-Level Risk

Strong alignment means the sponsor does well only when investors do well. In oil and gas, fees and revenue carve-outs can pay a sponsor well even when LP returns disappoint, and upfront fees create an immediate drag on performance. Review the following in the private placement memorandum (PPM):

• Total fee load. Add up management fees, sales commissions, acquisition fees, and any turnkey drilling markups over the life of the fund. In my experience, total fees range from roughly 4% to 15% of invested capital.
• Asset transfers. Ask whether assets are transferred to the fund at the sponsor's cost, or whether the sponsor keeps an overriding royalty interest (ORRI). An ORRI gives the sponsor a share of production revenue ahead of investors, and it can quietly lower LP returns for the life of the well.
• Co-investment. Ask how much the GP, management, and advisory board have invested across the sponsor's funds, and how much the GP is committing to the current one. A GP commitment of 5% to 10% of capital raised signals strong alignment.
• Profit split. Review how distributions are divided between LPs and the GP, and whether LPs receive their capital back before the GP shares in profits. LP/GP splits commonly range from 70/30 to 90/10.

6. Strategy Risk

Most oil and gas offerings follow one of three strategies. Each carries a different mix of risk, investor liability, and tax treatment, so confirm which one you are buying before comparing returns:

• Operated working interests. The sponsor or an affiliate drills and operates the wells, and investors pay a share of drilling and operating costs. These programs offer the most control and upside, along with more concentration risk and the possibility of cash calls. Investors receive IDC deductions and percentage depletion.
• Non-operated working interests (NOWI). The fund buys smaller stakes in wells drilled by established operators, spreading exposure across many wells and management teams. Investors still pay their share of drilling costs, so investors receive IDC deductions and percentage depletion.
• Royalty and mineral interests. The fund owns a share of production revenue without paying drilling or operating costs. Risk and upside are generally lower. Because royalty owners pay no drilling costs, they receive no IDC deduction but can claim percentage depletion.

How the IDC Deduction Works

Intangible drilling costs (IDCs) are the non-salvageable expenses of drilling a well, and they typically make up the majority of its cost. Working interest owners have been able to deduct them in the year incurred since 1913, and percentage depletion has been part of the tax code since 1926. Sponsors commonly project first-year deductions of roughly 70% to 90% of invested capital, depending on the mix of drilling and acquisition costs. Ask for prior funds' K-1s to see what investors actually received.

Common Misconceptions About the IDC Deduction

For investors with high W-2 income, the first-year write-off is often the centerpiece of the pitch, and capital raisers frequently concentrate their marketing in the fourth quarter. The deduction has real value, but several common assumptions about it are wrong:

• “Any oil and gas investment generates the deduction.” Only working interest owners who pay drilling costs receive IDC deductions. Royalty and mineral funds do not, and purchases of already-producing wells generate much smaller first-year deductions than new drilling.
• “The deduction will offset my W-2 income.” Working interest losses offset wages only when the interest is held directly or through an entity that does not limit liability, such as a general partner interest. Limited partner and LLC interests generally produce passive losses. To claim the deduction against active income, which the IRS calls nonpassive income, investors typically must elect to invest as general partners in the first year. Most programs then convert all investors to limited partners, often after year one. Ask when that conversion happens and what liability you carry until then. 
• “The deduction is permanent tax savings.” For most investors, the IDC deduction is largely a deferral. It reduces your tax basis, so later production income has few deductions left to offset it, distributions above your remaining basis can be taxed as gain, and if the wells are eventually sold, IDCs can be recaptured as ordinary income. The deferral still has value if you invest the savings or expect a lower tax rate later. Percentage depletion is the more permanent benefit. Investors can deduct 15% of gross income from each property, limited to the first 1,000 barrels per day, the property's net income, and 65% of taxable income, and the deduction can continue after their cost has been fully recovered.
• “A large deduction makes a good investment.” Don't let the tax tail wag the dog. An investor in the 37% federal bracket who deducts a full $100,000 investment in a program that never pays back still loses about $63,000. Underwrite the deal on its cash flow and return of capital first, and confirm the expected tax treatment with a CPA who works with oil and gas clients.

Conclusion

Oil and gas can add diversification beyond stocks and real estate, along with cash flow and tax efficiency, to any investor's portfolio. It also carries unique risks that every investor should understand. LPs who assess sponsor, drilling, commodity price, decline curve, fund-level, and strategy risk on every deal, and who underwrite the investment before the tax benefit, will be well positioned to find disciplined operators.