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.
Projected annual distributions (bars) and cumulative cash (line) per $200,000 unit over the first 10 years, base case. Modeled estimates based on stated assumptions; actual distributions will vary materially with production, prices, costs and operator timing.
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 reserves are proven, the wells are 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.
Over 152,000 barrels of oil and 3.6 Bcf of gas produced as of August 30, 2026, while still choked back. Investors are not taking drilling and completion risk, cash flow is current, and the wells are being opened toward the operator's projected full-open rate as surface constraints clear.
The 4.75% interest is acquired for $1.65 million against about $4.3 million of estimated present value (PV15) and roughly $6.7 million of projected 10-year cash — about 62% below our estimated present value.
The base case models the wells to a peak of ~26 MMcf/d (~620 BOPD), below the operator's projected full-open of ~30 MMcf/d (~850 BOPD), on a blended decline at strip pricing — banking on neither a price recovery nor full-open rates.
The wells are choked back today. The base case holds the current restricted rate for about three months, then opens toward the operator's projected full-open — but is modeled to a peak of ~620 BOPD around month 12, below the operator's ~850 BOPD, and declines from there. Today's rate is a floor, not the wells' deliverability.
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.
“Oil has exceeded rate expectations; the wells are flowing and building as facilities come online.”
— Trigo Exploration
Cumulative production is operator-reported as of August 30, 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.
"Present value" is the wells' projected future cash brought back into today's dollars — a modeled estimate rather than an appraisal. Against the $1.65 million purchase price, that is roughly $2.7 million of estimated value above what the partnership pays. Present value and the projected returns come from the same production model, so they are not two independent tests of the deal — the discount describes what the partnership pays for the reserves, not a second source of return.
Upside case: about $6.1M of estimated present value and $10.0M of projected 10-year cash.
Present-value and projected-cash figures are modeled estimates discounted from projected cash flow — not appraisals or guarantees; actual results will vary materially. See the Private Placement Memorandum.
74.5% of every unit acquires producing reserves. Fee load mirrors the original Legacy Gus-EFG, LP structure.
| Acquire producing working interest | 74.5% | $149,093 |
| Prospect origination fee | 13.1% | $26,170 |
| Management & supervisory fee | 6.5% | $12,935 |
| Offering / legal / filing | 3.5% | $7,081 |
| Working capital reserve | 2.4% | $4,721 |
| Total per unit | 100% | $200,000 |
All three cases are modeled to the same conservative peak, below the operator's projected full-open. Each case tests a different lever: the downside stresses the decline, the upside reflects a commodity-price recovery.
Per unit, before investor-level taxes. All three cases are modeled to a conservative peak of ~26 MMcf/d (~620 BOPD), below the operator's projected full-open of ~30 MMcf/d (~850 BOPD). The base runs a blended decline at strip pricing, banking on neither price recovery nor full-open rates; the downside stresses the decline using the full pre-drill type curve, the steepest case; the upside reflects a commodity-price recovery. Figures are illustrative projections, not guarantees, and actual results will vary materially. Returns are shown over 10 years; the wells are projected to produce beyond that. See the risk factors and the Private Placement Memorandum.
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 from day one, 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 proven reserves, 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 is installing high-pressure separators and a lay-flat line to open the wells toward full choke. Today's rate is a restricted floor, not the wells' deliverability.
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 acquired below our estimated value.
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.
The ramp depends on the operator installing facilities on schedule; delays push out cash flow.
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.