Enter an API number or RRC lease ID. Mineral Flow AI pulls the full TRRC production history, verifies seller claims against public records, runs Arps decline curve analysis, assesses title and mineral ownership risk, and returns a gated offer range — blocked until production, division orders, and LOE are each sourced and verified.
Full TRRC history · Seller claim verification · Title & ownership risk · Arps DCA · Gated offer range · Evidence-tracked per field
A complete working interest evaluation means pulling TRRC production, fitting a decline curve, modeling NPV across price scenarios, verifying LOE against basin benchmarks, and checking compliance — all before you write an LOI. Most teams do this in a spreadsheet, by hand, one deal at a time.
Every layer of a working interest due diligence — from raw TRRC production through a signed offer recommendation — in a single platform.
Pulls the complete monthly production record from the Texas Railroad Commission by API number or RRC lease ID — not just the trailing 36 months. Every month is classified: active, downtime, restart, flush, or incomplete, with calendar gaps preserved so the decline model sees the true time axis. Multi-lease assets are aggregated before DCA fitting.
Fits exponential, hyperbolic, and harmonic models. Selects best by SSE with b-factor penalty for over-fitting. Applies industry-standard terminal decline switch to prevent hyperbolic tails from projecting unrealistic economic lives. Returns EUR, R², and 60-month forward projections.
Stress / Base / Strip / Upside price decks anchored to live EIA WTI and Henry Hub, with basin-specific differentials applied. Computes NPV10, NPV15, IRR, payout months, offer range (low/mid/high), and breakeven oil price — including severance tax, ad valorem, workover reserve, and SWD disposal costs.
Scores production risk, financial risk, compliance, plugging liability, operator quality, and data completeness on a 1–10 scale where 1 is lowest risk. Returns a pursue / review / pass recommendation with specific red, yellow, and green flags — not a number without reasoning.
Processes LOE statements, run tickets, division orders, joint interest billings, workover AFEs, W-1/W-2 completion reports, and equipment lists. Extracts monthly production, line-item costs, NRI/WI, water cut, formation depth, and completion data — with physical bounds validation before any number reaches the model.
Every diligence field shows its data source: TRRC structured data, TRRC imaged record, seller document, or assumption. An offer gate blocks the recommendation until Production, Division Orders, LOE, and Workover History are verified — preventing a number from being mistaken for a fact.
The platform runs the full evaluation automatically. You provide the identifiers and documents; it does the rest — and tells you exactly what's still missing before the offer is written.
Enter the API number, RRC lease ID, or operator name. No manual TRRC searching required.
36 months of TRRC production fetched, classified, and analyzed for downtime, restarts, and TRRC reporting lag.
LOE statements, division orders, workover records, run tickets. AI extracts every structured field with bounds validation.
Seller claim verification, title risk, decline curve, NPV model, and a gated offer range — unlocked only after production, ownership, and LOE are each sourced. Missing items generate a specific document request list.
The economics model runs the same math a petroleum engineer would — including the parts most acquisition spreadsheets skip.
Trailing average of active months only — excludes downtime, restart transition, and potentially incomplete TRRC reports.
For hyperbolic wells, uses D(t) = Di/(1+b·Di·t) rather than the historical t=0 rate — prevents overstating future decline speed for mature wells.
Severance tax, ad valorem, workover reserve, SWD disposal (when water cut is known), and LOE cross-checked against EIA basin benchmarks.
Sellers routinely overstate production. The platform pulls the public TRRC record, compares it to whatever rate the seller claimed, and flags discrepancies — automatically, on every deal.
Before a dollar moves, the platform cross-checks seven title signals against the documents you have — and tells you exactly which ones require a licensed title attorney to resolve.
No division order on file means decimal interest is unconfirmed. The platform flags this as critical and blocks NRI-dependent economics until an executed division order is uploaded.
NRI is cross-checked against typical working interest structures. An NRI above the WI or outside the plausible range for the lease type is flagged for investigation before closing.
Overriding royalty interests reduce net revenue. The platform detects ORRI language in uploaded documents and flags the implied lease burden so it flows into the NPV model correctly.
The stated operator is compared to the TRRC record. A mismatch may indicate an unreported operator change or an acquisition that hasn't been reflected in the public record.
Production confirms HBP status, but HBP doesn't eliminate lease review — pugh clauses, depth limitations, and primary term provisions still require the underlying lease document.
No automated analysis substitutes for a formal title examination. The platform generates a specific document checklist and flags when a licensed title attorney must be engaged before closing.
Every Texas underwriting pulls the full regulatory picture from the Railroad Commission automatically, in parallel, in minutes.
A deal report is only as useful as the data behind it. Every diligence field carries its evidence source — and the platform tells you exactly what documents to request to upgrade a weak source to a verified one.
Production, formation, compliance, and inspection data pulled directly from the Railroad Commission. Highest-quality public record source for Texas wells.
W-1 / W-2 scanned records, field inspection forms, and permit filings. Extracted from imaged documents where structured data is unavailable.
LOE statements, run tickets, division orders, and workover AFEs uploaded by the operator. AI-extracted with physical bounds validation and cross-checked against basin benchmarks.
LOE is cross-checked against the expected range for the basin. Decline rate is compared to the typical rate for the play. If the numbers don't match, the platform flags it before the offer is written.
Midland and Delaware sub-basins. LOE $7.50–$20/BOE. Typical decline 2.5–3.0%/mo. Oil differential –$3.50 to –$4.00/BBL.
Oil window and gas/condensate window. LOE $6–$16/BOE. Typical decline 4.5–5.0%/mo. Faster decline, lower disposal costs.
Spraberry / Wolfcamp conventional. LOE $12–$32/BOE. Typical decline 1.2%/mo. Long-lived stripper wells with higher per-unit operating costs.
Cotton Valley and Haynesville formations. LOE $10–$25/BOE. High salt water disposal costs. Strong Midcontinent gas infrastructure.
Mature shale play. LOE $14–$30/BOE driven by compression and well age. Typical decline 2.0%/mo.
Frio / Yegua / Austin Chalk and six additional Texas basins. Each with EIA 2022-sourced LOE, differential, and decline benchmarks.
The same rigor as a 25-year veteran petroleum engineer — without the 8-hour turnaround or the single-point dependency.
Run a complete underwriting in minutes instead of a day. Evaluate the full opportunity set, not just the deals that fit the queue.
Every number is source-tagged. LOE is benchmarked. Decline rates are sanity-checked against basin typical. The platform flags what a veteran would flag — before you sign anything.
The same DCA model, cost structure, and evidence standards on every deal — whether it's your first this week or your fifteenth. No more spreadsheet drift.
Want to see the full output on a real Texas well before committing? Send an API number or RRC lease ID and we'll walk through the production analysis, DCA fit, NPV model, and offer range together.