Legacy Gus-EFG II, LP is acquiring a 4.75% interest in four Wolfcamp horizontals in Reeves County, Texas — online since December 2025 and generating cash today. Investors hold 80% of the interest and receive monthly distributions, net of costs.
Illustrative projections, not guarantees. Open only to verified accredited investors; any offer is made solely by the confidential Private Placement Memorandum.
Each $200,000 unit is a proportional share of a producing 4.75% working interest — paid out monthly, net of costs, and reported to you on a Schedule K-1. Detailed per-unit cash projections — base, downside, and upside — are provided to verified accredited investors on request.
Operated by Trigo Exploration and producing since December 2025, the pad sits in the Delaware Basin, the western and more prolific half of the Permian. Oil carries the economics, with NGLs adding and gas recovering as takeaway improves.
This is not a drilling bet. The wells are producing and flowing, and the partnership's economics are effective July 1, 2026, so net revenue between the effective date and closing is credited to investors at close.
Approximately 170,000 barrels of oil and 4.3 Bcf of gas produced to date (operator-reported, October 2026). Investors are not taking drilling and completion risk, and cash flow is current.
The base case is underwritten to the wells' current, observed production at strip pricing. It assumes no commodity-price recovery and no production increase from here — any operational upside is treated separately and is not required for the investment to perform.
Core Delaware Basin acreage in Reeves County, Texas. Two surface pads, four horizontal laterals landed in the same Wolfcamp interval, flowing today.
The western and more prolific half of the Permian — oil-weighted, stacked-pay Wolfcamp.
Illustrative regional map. State line accurate; basin extents and county outline approximate. Marker shows the county, not the precise surface location.
EFG Gus State 3H / 4H and EFG State 5H / 6H, operated by Trigo Exploration.
Cumulative production is operator-reported, October 2026. Flow shown is illustrative; the wells are currently choked back pending surface work. Forward-looking statements are subject to risks and uncertainties; actual results may differ materially.
Reeves County sits in the Delaware Basin, the western and more prolific half of the Permian, the basin that alone produces 44% of all U.S. oil. This is not the fringe. It is the core of the most productive oil region in America, and it draws the largest operators in the business.
Stacked pay. Multiple productive benches, the Bone Spring and Wolfcamp A through D, stacked beneath the same surface acreage.
Overpressured rock. High reservoir pressure drives strong early production. This rock is demanding, and it rewards operators who can drill it.
A real barrier to entry. Deep, high-pressure, capital-intensive wells are why the basin is dominated by majors, not marginal operators.
Operators active across the Delaware Basin. In Reeves County itself, public filings show Chevron, BP and Permian Resources among the top producers.
Basin and county statistics are from public sources (U.S. EIA, December 2025; Texas Railroad Commission lease filings via third-party aggregation) and describe the region, not this partnership’s wells. Operators named are active in the area per public records; they are not affiliated with, and do not endorse, this offering.
Nearly three-quarters of every dollar goes directly into acquiring producing working interest — a fraction of the fee load carried by a typical new-drill program, and none of the dry-hole risk.
| Use of proceeds | Share of each unit |
|---|---|
| Acquire producing working interest | 74.5% |
| Prospect origination fee | 13.1% |
| Management & supervisory fee | 6.5% |
| Offering / legal / filing | 3.5% |
| Working-capital reserve | 2.4% |
| Total | 100% |
Per-unit returns are modeled in three cases — a base underwritten to current, observed production at strip pricing; a downside that stresses a steeper decline; and an upside in which currently-constrained production recovers as gathering-system backpressure is relieved. The base and downside hold production flat from today's levels; the upside reflects that recovery. Figures are illustrative projections, not guarantees. Detailed per-unit figures are shared with verified accredited investors on request.
Terms are a summary only and are qualified in their entirety by the definitive offering documents; the Private Placement Memorandum governs. Tax treatment depends on final structure and each investor's situation.
Direct participation, reported to each investor on a Schedule K‑1. Tax treatment depends on final structure and each investor's own situation — the PPM governs and your CPA should confirm.
Percentage depletion under IRC §613A shields 15% of gross production income from federal tax — not once, but every year the wells produce. Because this partnership distributes monthly once the wells are in pay status, the shield applies to income investors are actually receiving. Subject to the statutory limits, and cost depletion applies where it yields more.
The portion of the purchase price allocated to tangible equipment — wellheads, casing, tanks, separators, flowlines — is eligible for 100% first-year bonus depreciation under IRC §168(k), made permanent by the One Big Beautiful Bill Act. Acquired equipment qualifies. The deduction is sized to the equipment allocation set in the purchase price allocation.
Lease operating expense, workovers and field costs flow through on the K-1 and are generally deductible as ordinary business expenses in the year incurred, reducing taxable income against the same distributions they support.
Investors hold a proportional share of an actual working interest and receive their own K-1 — the economics and the deductions arrive together. Severance tax is already netted at the property level, and Texas imposes no personal income tax on the production income.
Programs that advertise a Year 1 write-off of nearly the entire investment are funding wells that have not been drilled yet. That deduction is intangible drilling cost, and it is the tax code's compensation for taking drilling risk: the money is spent before anyone knows whether the well produces.
These four wells are already drilled, completed and producing. There is no IDC to deduct because the drilling risk has already been taken and paid for by someone else. What investors get instead is producing wells, cash flow from the first distribution, and an ongoing depletion shield on that cash — rather than a large deduction against a well that may or may not perform.
Because the partnership is acquiring existing producing wells, investors should not expect first-year intangible drilling cost (IDC) deductions. Anticipated tax benefits arise primarily from percentage or cost depletion, bonus depreciation on the equipment allocation, and operating-expense pass-through, and depend on the final structure of the offering and each investor's circumstances. Offering and syndication costs are not deductible. Percentage depletion is subject to statutory limitations, including limits based on net income from the property and on the investor's overall taxable income. Nothing here is tax advice; prospective investors should consult their own tax advisors and rely on the Private Placement Memorandum.
Waha ran deeply negative earlier in 2026, but the operator's forward strip is positive across the board and strengthens into winter, with GCX and Hugh Brinson takeaway already flowing and Blackcomb still to come. The base case prices gas on that strip, net of the midstream fee. A recovery beyond it is upside we have not priced in.
Saltwater disposal is connected, and the operator continues to optimize surface facilities and midstream flow.
LegacyCrest has held and monitored this exact four-well pad since first production — same wells, same operator, same reservoir. This is an increased position in an asset we know first-hand, at a price set before the recovery fully arrives, rather than something bought off a data room.
Waha gas settled deeply negative earlier in 2026, but the operator’s current forward strip is positive across the board and strengthens through winter, with GCX and Hugh Brinson takeaway already flowing and Blackcomb still to come. We book gas at the net residue realization — the strip less the midstream fee — and gas is a minority of revenue on this oil-weighted asset. A recovery beyond the strip is upside we have not priced in.
Forward strip reflects operator-provided Waha pricing as of the date shown; it is an estimate, not a guarantee, and realized prices will differ. Gas is a minority of projected revenue for this oil-weighted asset.
Because we have watched these wells produce since day one, we are underwriting from our own operating history rather than a seller's summary — the production anchor, the decline shape and the surface constraints all come from data we have been tracking month by month.
LegacyCrest Capital is a Plano, Texas–based firm that has specialized in Permian Basin non-operated working interests and saltwater-disposal infrastructure since 2016. Founder and Managing General Partner Jason Pickard sources deals directly, underwrites at the well level, manages each asset hands-on through the operator, reports to investors monthly, and co-invests alongside his partners where he can.
Legacy Gus-EFG II, LP applies the same disciplined structure LegacyCrest used on Legacy Gus-EFG, LP, now extended to a producing, cash-flowing interest.
Securities counsel: Whitaker Chalk Swindle & Schwartz, PLLC · John Fahy, former SEC and Texas State Securities Board enforcement attorney. Counsel represents the Partnership and its General Partner, not prospective investors.
Portfolio figures reflect all LegacyCrest Capital programs since 2016 across multiple assets and are not specific to this offering; realized results have varied across programs. Past performance is not indicative of future results.
Investments in oil and gas working interests are speculative and involve substantial risk, including possible loss of the entire investment. The PPM governs; key considerations include:
Oil, gas and NGL prices are volatile; realized gas at Waha may stay weak or decline.
Cash flow depends on the operator sustaining production and completing facility work on schedule; delays push out distributions.
Actual production, decline and recoveries may differ materially from projections.
Units are illiquid, long-term holdings with no public market and transfer restrictions.
The partnership holds a single four-well asset with one operator.
Tax treatment depends on final structure and each investor's situation. Investors should not expect first-year intangible drilling cost deductions on an acquisition of producing wells.
Schedule a brief call to walk through the asset, or send us your details and we will follow up. Offering documents are released once accredited status is verified.
A member of the LegacyCrest team will call you directly. Offering documents are released only after we've spoken and your accredited status has been verified. All fields required.
By submitting, you agree to be contacted by phone and email about this offering. This is not an offer to sell a security. Any offering is made solely to accredited investors whose status has been independently verified, pursuant to the confidential Private Placement Memorandum.
A member of the LegacyCrest team will call you directly. Offering documents are released only after we've spoken and your accredited status has been verified. All fields required.
By submitting, you agree to be contacted by phone and email about this offering. This is not an offer to sell a security. Any offering is made solely to accredited investors whose status has been independently verified, pursuant to the confidential Private Placement Memorandum.