FAQ

A working interest in an oil and gas fund is one of the few investment vehicles in the U.S. tax code that can generate a deduction usable against active W-2 wages, self-employment income, and business income - not just passive income. Under IRC §469(c)(3)(A), a working interest held in a form that does not limit liability is specifically excluded from the passive activity loss rules. Combined with the 100% deductibility of Intangible Drilling Costs under IRC §263(c), this produces a first-year deduction in the 90%+ range on invested capital for Shalehaven investors, and Shalehaven has delivered exactly that - 90.7% on the 2024 Fund and 90.7% on the 2025 Fund - across two consecutive vintages.

Yes, and this is one of the more strategic uses of an oil and gas working interest investment for high-net-worth investors. A Roth conversion converts pre-tax retirement assets (Traditional IRA, 401(k) rollover, SEP, etc.) into a Roth IRA, with the converted amount treated as ordinary income in the year of the conversion. The tax cost is often the reason investors put off conversions despite the long-term benefits of tax-free Roth growth and no required minimum distributions.

An IDC deduction in the same tax year offsets that ordinary-income tax cost. An investor converting $250,000 from a Traditional IRA to a Roth - facing roughly $80,000 to $90,000 in federal tax at top marginal rates - can pair the conversion with a fund investment that generates a comparable deduction, effectively neutralizing the current-year tax bill on the conversion. The Roth assets then grow tax-free for the remainder of the investor's lifetime (and, under current law, for ten years after the investor's death for non-spouse beneficiaries).

This strategy is especially relevant in years when an investor's ordinary income is otherwise lower than usual - a sabbatical year, a partial retirement year, a down year for a business owner - where a conversion at lower marginal rates paired with an IDC deduction can produce a permanent tax-position improvement. Talk to your tax advisor and a retirement specialist about how this applies to your situation; the conversion mechanics, ordering rules, and five-year holding requirements have nuances that matter.

The most common comparison investors run is against real estate syndications and bonus depreciation strategies, since both target tax efficiency. Two structural differences matter.

Real estate depreciation phases in over 27.5 or 39 years, and accelerated/bonus depreciation under cost-segregation studies typically delivers a 20–35% first-year deduction on invested capital — useful, but smaller. Oil and gas IDC deductions can deliver 90%+ in year one because the underlying expense category is genuinely consumed in the drilling and completion phase, not amortized over decades.

The second difference is income type. Real estate losses are passive by default and require active participation or real estate professional status to offset W-2 income. Oil and gas working interests are explicitly carved out of the passive activity rules under §469(c)(3)(A), so the deduction is available against active income without any participation test.

The two strategies are complementary for many investors, not competing. Most of Shalehaven’s investors have real estate exposure, as well.

A specific note on §1031 exchanges: investors who have sold appreciated real estate and are facing a recognized gain often look first to a 1031 like-kind exchange to defer the tax. When the 1031 doesn't fit - the replacement property pipeline didn't materialize, the 45-day identification window expired, the gain is from a partnership interest that doesn't qualify, or the investor simply doesn't want to be a landlord again - an IDC deduction in the same tax year can produce a comparable economic outcome by offsetting the recognized gain rather than deferring it. The mechanisms are different (deferral vs. current-year deduction) but for an investor focused on after-tax dollars, the result can be substantially similar. Talk to your tax advisor about how this applies to your situation.

Shalehaven Partners Energy & Asset Management LLC is a Dallas-based asset manager that has sponsored three annual non-operated working interest funds (2024, 2025, 2026 vintages). Verification points available to prospective investors include the following information available for view / download in the investor portal: PCAOB-registered audit of fund-level financials; Schedule K-1s issued for each tax year; Third-party engineering reserves report covering the underlying assets; and Recorded acquisition documents (assignments, mineral deeds) for every wellbore in the portfolio. Additionally, leadership credentials (CFA charter, Board Certification, etc.) are independently verifiable online. Further, in most instances, we are happy to connect a prospective investor with an existing investor as reference.

The category has certainly earned its reputation. Since the first oil boom, promoters and wildcatters have found creative ways to sell the dream and extract dollars from investors. High fees, affiliated operators marking up costs, sponsors who get paid at closing regardless of how the wells perform, offerings structured around generating a tax deduction first and an investment return second - a lot of investors have lost money in those funds, and - sadly - the reputation is mostly accurate for them.

Three things distinguish a fund where investors can actually make money. First, fee structure: if the sponsor is taking acquisition fees, affiliate markups, cost-plus drilling margins, and turnkey activity fees, the well has to outperform underwriting by these amounts before the investor reaches par. Second, manager incentives: if the sponsor gets paid the same whether the well produces or comes in dry or below underwriting, there’s no real reason to be selective. Third, diversification and underwriting discipline: a fund holding dozens of wells across multiple operators and basins, underwritten by a credentialed technical team and audited by a PCAOB-registered firm, is a fundamentally different risk profile than a one-or-two-well direct deal.

The category is risky when it's structured to be risky. Built differently, it can actually produce results for investors.

An operated fund's manager (or its affiliate) actually drills, completes, and produces the wells — meaning the manager earns margin on drilling activity in addition to whatever fees it charges the fund. A non-operated fund holds fractional working interests in wells drilled by independent operators (Chevron, EOG, Devon, ConocoPhillips, etc.) and earns only when the underlying wells produce.

The non-operated structure removes the "activity trap" — turnkey operators get paid on drilling activity even when wells come in dry. It also eliminates the affiliate-markup problem, where the operating affiliate charges the fund cost-plus margins on drilling and completion. Shalehaven invests exclusively as a non-operator and does not own affiliated drilling, completion, or service companies.

The right fund for a given investor depends on capital amount, income type (W-2 vs business vs passive), state tax situation, risk profile, and time horizon. The structural attributes that distinguish a strong non-op fund from a weak one are consistent across investors: a 90%+ first-year deduction (driven by wellbore-only acquisition rather than naked leasehold), no acquisition fees or affiliate markups, PCAOB-registered audit, direct operator relationships rather than fund-of-funds layering, and demonstrated vintage-over-vintage execution. Shalehaven delivered 90.7% first-year deductions on the 2024 and 2025 Funds and the 2025 Fund portfolio is currently producing approximately 13% above original underwriting projections.

90.7% on the 2024 Fund. 90.7% on the 2025 Fund — same high-water mark, two years running. The 2025 Fund K-1s went out to investors on March 20, 2026. We’re targeting the same 90%+ deduction for 2026 and beyond. Redacted K-1s from prior vintages are available in the investor portal alongside the supporting allocation detail.

The 2024 Fund delivered a 42% annualized Q4 2025 distribution and a 40% full-year annualized cash return for that vintage. Q1 2026 came in at 22% annualized for the 2024 Fund and 8% annualized for the 2025 Fund — and the 2025 Fund only had ~12% of its portfolio online during Q1. Another 26% turns in line during Q2. Monthly distribution detail is in the investor portal.

13% above projections as of May 2026, based on wells currently online. Project-level performance and the third-party engineering reserves report are in the portal.

120+ across three active vintages, as of May 2026. Two years in. The 2024 Fund: 9 wells, 3 basins, 3 operators. The 2025 Fund: 68 wells, 7 basins, 10 operators. The 2026 Fund: 26 wells so far across four operators and three basins, and growing.

76% of 2024 Fund investors reinvested into the 2025 Fund. That's the only investor satisfaction number that matters — these are people who already had the K-1s and the distributions in hand before they wrote a second check.

Roughly 30% subscribed as of May 2026, and closing earlier than the 2025 Fund did. Demand has consistently exceeded available capacity. Shalehaven doesn’t raise capital simply for the sake of raising capital. Investors who wait to invest until December will likely be shut out of Shalehaven’s funds.

A Fund of Funds takes your capital, hands it to other managers, charges you a fee for the privilege, and surrenders direct control over what ends up in the portfolio. Two layers of fees. Zero oversight of the actual wells. When you invest with Shalehaven, you are investing directly with the fund manger that underwrites every well in the portfolio at the asset level, deals directly with the operator, and owns a wellbore-specific interest in each project. No middlemen and no secondary fees to an entity that is really just a capital aggregator.

When we participate in a project, the acquisition is strictly limited to the specific wellbore being developed — not an undivided slice of the broader leasehold. That concentrates capital where the tax efficiency lives: the drilling and completion phase, where IDCs and bonus depreciation are generated. We don't acquire raw, undeveloped acreage. That kind of capital has to be capitalized and depleted over years, which destroys the front-end deduction profile our investors actually came here for.

Yes — by PCAOB-registered auditors. The 2025 Fund audit is in progress and results go to investors in May 2026. PCAOB-level oversight is uncommon among retail-distributed non-op funds. We treat it as the floor, not a feature.

We reviewed approximately $4.36 billion in gross opportunities during 2025. The fraction that cleared underwriting is small by design. Most retail-focused funds run the opposite model – raise as much capital as possible and acquire as many deals as it takes to deploy the raise, generate the tax benefit, and move on. We are more selective on both capital raise and capital placement.

Chevron, ConocoPhillips, Devon, EOG, Hunt, Admiral Permian, Adamas Energy (formerly Aethon), Riley Permian, Kraken, Spur, Bandera, and Ballard, among others. Operator-level allocations and recorded acquisition documents are available to verified prospective investors in the portal.

A CFA-charterholder Chief Investment Officer, a Chief Legal Officer who is Board Certified in Oil, Gas & Mineral Law by the Texas Board of Legal Specialization, and two Petroleum Engineers (PEs) on the technical underwriting side. Most retail non-op funds are sales organizations with an investment team attached. We’re the inverse.

Most retail non-op funds are built around a manager-friendly fee stack: acquisition fees on every asset, affiliate operator markups, “cost-plus” margins on drilling and completion, turnkey activity fees that pay regardless of well outcome, and a hefty profit split from day one. Shalehaven’s fee load is intentionally and meaningfully below that industry standard. The structural reasons are deliberate: All assets are acquired at cost - no acquisition fees, no markups, no “cost-plus.” We don’t own affiliated drilling, service, or operating companies that quietly extract margin elsewhere in the deal. And manager incentives align with productivity, not activity. Why? Because it’s hard to provide attractive investor returns when management is siphoning them off first. The complete fee schedule and offering economics are clearly outlined in the offering materials, available in the investor portal.

If you think you found us through a paid social media ad, we’re not the fund you're thinking of. We don't run ads. We don’t run mass emails. Almost every investor came through a referral from another investor, friend, family member, or colleague, which is exactly how we want it.

The funds running aggressive social media campaigns are running them for a reason: the fee structure underneath has to support a paid acquisition channel and a sales team working leads. Somebody is paying for the impression you saw, and it’s the investors in the fund every time. Those funds are something that is being “sold” to investors. Shalehaven is a fund investors are “buying.”

Look at the offering documents — acquisition fees, organizational fees, ongoing management fees on committed capital, affiliated drilling-cost markups, turnkey activity fees that get paid whether the well produces or not, and day one profit splits. Shalehaven charges none of that. Two consecutive 90.7% first-year deductions. 76% reinvestment from 2024 to 2025. 120+ wells across three vintages. 40%+ annualized cash distribution: We don’t need to advertise.

Broker-dealer-distributed oil and gas funds carry a fee load that has very little to do with the wells and a great deal to do with the distribution chain. The typical structure: a selling concession of 6–8% paid to the registered rep, a wholesaler markup of another 1–2%, an offering and organizational expense reimbursement, an acquisition fee paid to an affiliate of the sponsor, an ongoing management fee, and frequently a “cost-plus” arrangement on drilling that pays the sponsor’s affiliated operator a margin on every dollar deployed. By the time your capital reaches an actual wellbore, a meaningful percentage of it has already been consumed by the apparatus that delivered it to you.

Most of the time, none of that is your advisor’s fault. They sell what’s “available” on their platform, and they earn what the platform pays them to sell. But, the math is what it is. Still, a large upfront load means the well has to produce that much above its underwriting just to get you back to par on cash returns.

Shalehaven works with a small number of carefully selected, low-fee broker-dealers — relationships built on alignment with our fee philosophy rather than on the standard distribution economics — and that channel represents a small portion of our overall capital raise. The vast majority of our investors come in directly.

The principal benefit is the deduction of Intangible Drilling Costs (IDCs) under IRC §263(c). 100% of IDCs are deductible in the year incurred — that's what produces the 90%+ first-year deduction we've delivered across two consecutive vintages. Producing wells then generate ongoing depletion allowances.

Under IRC §469(c)(3)(A), a working interest in an oil or gas property held in a form that does not limit liability is specifically excluded from the passive activity loss rules. Investors enter as General Partners to qualify, which lets IDC deductions offset active income — W-2 wages, self-employment income, business income — not just passive. Talk to your tax advisor about how this applies to your situation.

Investors come in as GPs to qualify for the §469(c)(3)(A) working interest exception during the deduction year. Once the fund's capital is fully deployed and the deductions are taken, investors automatically convert to Limited Partners for liability-cap purposes. The conversion mechanism, timing, and governance changes are spelled out in the LPA and PPM. A third-party legal memorandum analyzing GP-period liability exposure and the specific structural mitigants Shalehaven uses during that window is also available in the investor portal alongside the deck, redacted K-1s, and third-party engineering reserves report.

A direct working interest opportunity is a structure where the investor (not a fund) takes a direct fractional ownership interest in one specific well or a small package of a few wells normally in the same area with the same operator. Because the working interest is held in the investor's own name, the investor typically signs a Joint Operating Agreement directly with the operator, is responsible for receiving, reviewing, any paying Joint Interest Billings, monitoring production, etc. The structural problems are significant: concentration risk, where a single well that comes in mechanically compromised, encounters faulting, has a casing failure, or simply underperforms its decline curve can wipe out the position with no diversification cushion underneath; single-operator counterparty risk, where the investor is exposed to one operator's execution, balance sheet, and solvency without recourse if things go sideways mid-drilling; basin and commodity concentration, since direct deals are typically marketed within whatever basin the sponsor happens to be active in that quarter, leaving the investor with all-Permian or all-Haynesville exposure and no mix across oil, gas, or regional pricing dynamics; meaningful operational and administrative burden, because direct working interest holders receive JIBs in their own name, sign AFEs in their own name, and are personally responsible for capital calls, plugging and abandonment liability, and ongoing operating costs that most first-time investors don't anticipate; misaligned sponsor incentives, where the sponsor's economics are built around marking up the deal, taking a carry, and moving on to the next one — meaning the sponsor gets paid at closing regardless of how the well performs, and if the project underperforms or fails, the sponsor simply points to the operator, the geology, or commodity prices and walks; and often weaker underwriting protection, because most direct deal investors lack the technical resources to evaluate AFE economics, type curve assumptions, offset well performance, title chains, or lease burden stacks.

A non-operated working interest is a fractional ownership stake in an oil or gas project. The holder participates in production revenue and capital costs proportional to their share but doesn't run day-to-day operations. The designated operator handles drilling and production; non-operators receive Joint Interest Billings and revenue distributions.

Two instruments: swaps (fixed-for-floating contracts that lock in a per-barrel or per-Mcf price for a defined volume and tenor) and collars (a floor put paired with a ceiling call, often zero-cost). Hedging decisions come from two inputs — the average underwritten price of a project relative to current futures, and the shape of the futures curve. The objective is downside protection on the underwritten return profile. We're not speculators on commodity direction.

Realized prices vary basin-by-basin based on takeaway, processing, and pipeline capacity. We track basis differentials — Waha for West Texas gas, Midland for Permian crude, Henry Hub for Haynesville — and factor them into underwriting and operator selection. East Texas gas, for instance, has been a focus area given LNG export takeaway and stronger realized pricing relative to Waha-exposed gas.

Roughly one-third of a horizontal well's lifetime cash flow is generated in the first two years. That's the steep initial decline curve characteristic of unconventional wells. It's also why front-end deployment timing within a vintage materially moves investor returns.

For verified prospective and current investors: the current vintage Investor Deck and PPM, redacted Schedule K-1s from the 2024 and 2025 vintages, third-party engineering reserves reports, a third-party legal memorandum on GP-period liability and structural mitigants, recorded acquisition documents (assignments, mineral deeds, JOAs as applicable), monthly Spectator updates, quarterly distribution detail, annual PCAOB-registered audit results, and subscription documents for the active vintage. Portal access requires accredited investor verification and an executed NDA.

Our investor reporting is built on the principle that sophisticated capital deserves sophisticated transparency, delivered consistently and without prompting.

Monthly: The Spectator — a substantive update covering every project in the portfolio (well-by-well production status, drilling and completion progress, hedging activity), market commentary, and a deep-dive on a relevant industry topic. Not a marketing newsletter.

Quarterly: Cash distributions plus the supporting distribution detail report.

Annually: Schedule K-1s delivered in March, ahead of most retail funds. PCAOB-registered audit results shared with investors on completion (typically May for the prior fund year).

Always: Direct access to the Co-Founders. Initial diligence calls are typically with one or both of the Co-Founders. After you invest, that access continues - investors call us, we answer. We host in-person investor events across the country throughout the year, plus an annual Shalehaven Golf Invitational and Dinner. These are not pitch events. They’re for our investors.