Existing Wells vs. Future Locations in a DCF Model

Direct answer

In a mineral-rights DCF, model existing wells and future locations as separate cash-flow groups. Existing wells begin with matched production and royalty evidence, then apply a stated forecast. Future locations require separate support for ownership, location identity, development status, timing, production assumptions, and uncertainty. Do not count a mapped location or permit as guaranteed drilling, and do not combine the groups until each scenario can be audited independently.

Key takeaways

• Existing producing wells have observable history, but their future cash flow still depends on decline, price, downtime, ownership, deductions, and other stated assumptions.
• A future location has no property-specific production history. Its DCF treatment needs separate evidence for location identity, development status, timing, type-curve support, ownership exposure, and uncertainty.
• A permit, nearby well, mapped spacing pattern, or operator position can add context without proving that a particular location will be drilled, completed, paid to the owner, or economically successful.
• Keep the two cash-flow groups separate through sensitivity testing, then show how much of the combined range comes from producing evidence versus future-location assumptions.

Educational scope. This guide explains how to separate producing-well evidence from future-location assumptions in a directional mineral-rights DCF. It does not determine title, interpret a deed or lease, classify reserves, forecast a specific well, predict drilling, value an owner’s property, select a transaction, or provide legal, tax, accounting, engineering, investment, surveying, or professional appraisal advice. MRX may have an economic interest in a mineral transaction. Owner-specific conclusions require controlling records and qualified professional review.

The practical rule is simple: do not place existing wells and future locations into one undifferentiated cash-flow stream. Build the producing-well case from matched historical evidence. Build each future-location case from separately identified development, timing, production, ownership, and uncertainty assumptions. Combine them only after a reviewer can see what each group contributes.

That separation matters because the two groups begin with different evidence. An existing well can have reported production, royalty statements, a completion history, and months or years of performance. A future location may be permitted, proposed, inferred from spacing, described by an operator, or merely possible. It has no property-specific production history until it is drilled, completed, and producing.

What “existing” and “future” should mean in the model

Define the groups before entering a number.

An existing producing well is a specifically identified well with observable production and a supported connection to the mineral interest being reviewed. A shut-in, temporarily inactive, recently completed, or drilled-but-not-producing well may need its own status rather than being silently mixed into the producing group.

A future location is an undrilled or not-yet-producing development scenario tied to an identified tract, unit, formation, or spacing concept. The phrase does not tell you whether the location is permitted, funded, scheduled, technically supported, commercially attractive, or attributable to the owner.

Use a status ladder instead of a yes-or-no future bucket:

1. producing well with matched production and payment evidence;
2. drilled or completed well not yet supported by producing history;
3. specifically identified approved permit;
4. operator-disclosed or documented development location;
5. technically inferred location based on a stated spacing or analog method; and
6. conceptual acreage potential without a sufficiently identified location.

The labels are not reserve classifications and do not imply value. They stop evidence of one kind from being presented as evidence of another.

Build the existing-well DCF from reconciled evidence

For each producing well, start with a stable identity: API number, operator, lease or unit, well number, county, field, formation where supported, and the owner records that connect the well to the reviewed interest.

The Railroad Commission of Texas provides production and wellbore research tools. Its production guidance says the information is compiled from operator reports. Its Production Data Query FAQ also explains important limits: oil can be reported at the lease level rather than by individual well, online data has a reporting lag, and results can change when corrected, revised, or delinquent reports arrive.

That means regulatory production is evidence, not a complete owner cash flow. Reconcile it to royalty statements and preserve differences in scope and timing.

For the existing-well line, document:

• the months of production history used and any missing or revised periods;
• whether volumes are well-level, lease-level, allocated, or commingled;
• the owner’s working decimal and the record supporting it;
• realized prices, taxes, deductions, adjustments, and net payments from the owner statements;
• downtime, shut-in periods, workovers, curtailment, or other material discontinuities that the records show;
• the forecast method and decline segments;
• the price path and any differential between a benchmark and owner realization;
• the valuation date, cash-flow timing convention, and discount rate; and
• the economic-limit or terminal assumption, if used.

An existing well is not risk-free. Historical production can be revised, operational conditions can change, prices and deductions can move, and title or payment issues can remain unresolved. The distinction is that the model begins with observable property evidence rather than a hypothetical first month.

Build every future-location case as a separate scenario

A future-location DCF needs a different input stack because there is no reviewed-location production history. At minimum, identify:

• the tract, unit, formation, depth interval, and proposed location as precisely as the evidence allows;
• whether the owner’s claimed interest reaches that location and depth;
• the development-status source and its date;
• the expected drilling, completion, and first-production dates;
• the production-profile source, analog set, adjustments, and limitations;
• the royalty or other economic-interest assumption;
• the price, differential, tax, and deduction assumptions;
• the probability or scenario treatment and what it represents; and
• the evidence that would advance, delay, remove, or reclassify the location.

Do not create precision by copying the same type curve and date across every blank point on a map. Each future cash-flow line should have a traceable location identity or be grouped under an explicitly described portfolio assumption.

What a permit proves and what it does not

The RRC Drilling Permit query can identify permit records using fields such as permit or status number, API number, county, operator, lease, field, filing purpose, well profile, approved date, and status. The Wellbore Query can help connect API, permit, lease, operator, field, and current or historical records.

Those tools can improve identity and status evidence. They do not prove:

• that the operator will drill on the assumed schedule;
• that a drilled well will be completed or commercially productive;
• that the owner holds the modeled tract, depths, or payment interest;
• that the well path or unit participation matches the model assumption;
• that capital remains allocated to the location; or
• that the owner will receive the forecast cash flow.

A permitted location may deserve a different scenario from a conceptual location, but “permitted” is not a synonym for “certain.” Preserve the query date and recheck status when the decision is updated.

Use maps for context without turning them into title evidence

The RRC Public GIS Viewer can show wells, permits, surveys, leases, pipelines, and related map context. The Commission states that its GIS datasets are informational, may be approximate, are not necessarily suitable for legal, engineering, or surveying use, and are not authoritative records of a geographic location.

Use the map to ask better questions: Which API number corresponds to the point? Which formation or field is involved? Is the permit on the same tract or only nearby? What record identifies the unit? Does the owner’s deed or lease cover the modeled depths?

Do not use a screen position or visual spacing pattern as proof of ownership, unit participation, legal boundaries, or a drill schedule.

Choose analogs and type curves transparently

An analog can help frame a future-production scenario, but it does not become the future location’s history. Record why the analog set was selected and how it differs from the modeled location.

Relevant comparison dimensions can include formation, depth, reservoir area, lateral length, completion design, vintage, operator practices, nearby development density, downtime treatment, production measurement, and the period over which performance is observed.

Avoid selecting only the strongest nearby wells. Show the data-screening rule, excluded records, aggregation method, and adjustments. If the public data is lease-level or commingled, state that limitation before presenting a well-level-looking curve.

The output should be a scenario range, not a promise that a future well will match an average, median, or selected analog.

Keep probability and timing as separate controls

Two questions are often collapsed into one:

1. What is the chance that development represented by the scenario occurs?
2. If it occurs, when does first production begin?

Keep them separate. A location with the same conditional production profile can have different present values if development moves by a year or several years. A probability haircut does not explain timing, and a later start date does not explain the chance that development never occurs.

Use dated cases such as earlier, base, later, and no-development only when those cases are supported and clearly labeled. Apply the same valuation date and timing convention across cases.

If a probability is used, define what event it measures. It might represent the chance of drilling, the chance of completion, the chance of commercial production, or a combined scenario. One unexplained percentage can hide several different risks.

Do not import public-company reserve labels casually

SEC oil-and-gas guidance is written for public-company disclosure and financial-reporting contexts. It can illustrate useful discipline: an adopted development plan requires more than mere intent, technical evidence matters, and undeveloped classifications involve stated standards and timing expectations.

That framework does not automatically classify a private mineral owner’s acreage, turn a DCF location into proved reserves, or substitute for a qualified reserve report. If an offer, engineering report, or model uses terms such as proved developed, proved undeveloped, probable, or possible, identify the governing standard, preparer, effective date, ownership basis, and report scope before relying on the label.

Keep price evidence consistent across both groups

The U.S. Energy Information Administration publishes dated spot-price series, including WTI and other petroleum benchmarks. A benchmark is not necessarily the realized price on an owner’s royalty statement.

For existing wells, compare the benchmark to actual statement prices and preserve location, quality, transportation, contract, processing, and timing differences. For future locations, state the assumed differential rather than copying a benchmark directly into owner revenue.

Use the same price-case definitions across existing and future groups when the purpose is comparison. Otherwise, a model can appear to compare development risk while actually comparing two unrelated price assumptions.

Show the bridge from separate cases to the combined DCF

The summary should display at least four components:

• present value attributed to existing producing wells;
• present value attributed to drilled, completed, or transitional wells;
• present value attributed to future-location scenarios;
• value excluded or shown only as an unmodeled possibility because evidence is insufficient.

For each component, show the main assumptions and a sensitivity range. Do not let a large future-location subtotal disappear inside one headline number.

A useful contribution table answers:

• What percentage of the combined directional range comes from observed producing assets?
• What percentage depends on undrilled scenarios?
• Which timing, probability, type-curve, ownership, price, or discount assumption changes the result most?
• What happens if future development is delayed or does not occur?
• Which new record would materially change the classification or range?

This bridge makes the model auditable. It also helps an owner compare a written offer to what the model actually assumes is being conveyed.

Stop rules for an evidence-first DCF

Pause rather than force a combined number when:

• the well, permit, tract, unit, formation, or depth identity cannot be matched;
• the owner’s claimed interest cannot be connected to the modeled location;
• lease-level production is being presented as individual-well history without a supportable allocation;
• future locations are counted from a map pattern without a documented method;
• a permit or operator statement is being treated as guaranteed development;
• type-curve selection or adjustments cannot be explained;
• timing and probability are hidden inside one unsupported factor;
• reserve labels are used without a governing standard and qualified source; or
• the model cannot show how much of the result comes from existing wells versus future locations.

The right response is to identify the missing evidence, keep the groups separate, and obtain the appropriate title, legal, engineering, reserve, tax, accounting, or appraisal review.

Bottom line

An existing wells future locations DCF is most useful when it reveals the difference between what is observed and what is assumed. Existing wells begin with reconciled production and owner-payment evidence, then require a stated forecast. Future locations begin with identity, status, analog, timing, ownership, and uncertainty questions before a conditional cash flow can be modeled.

Keep those cash-flow groups separate, test delay and no-development cases, preserve regulatory-data boundaries, and show the contribution of each group before presenting a combined directional range. That structure does not remove uncertainty. It makes the uncertainty visible enough for an owner and qualified reviewer to challenge responsibly.

Frequently asked questions

Should existing wells and future locations use the same DCF assumptions?

No. Existing wells can begin with matched production and payment history, while an undrilled location has no property-specific production history. Both groups need price, timing, and discount assumptions, but future locations also require separate support for development status, start timing, production shape, ownership exposure, and uncertainty. Keep the groups separate until those inputs are visible.

Does an approved drilling permit mean a future well is certain?

No. A permit is evidence of a regulatory filing or approval status, not a guarantee that the operator will drill, complete, produce, or pay the reviewed owner. Confirm the permit identity and status, but keep operator scheduling, capital allocation, title, completion, commerciality, and first-production timing as separate questions.

Can nearby well results be used for a future-location forecast?

Nearby results may provide analog context when geology, formation, lateral design, completion, timing, and data quality are sufficiently comparable. They do not become the reviewed property’s production history. State the analog selection, adjustments, and limitations, and avoid presenting an analog curve as a promised outcome.

How should future-location timing be tested?

Use more than one dated scenario, such as an earlier, base, later, and no-development case when the evidence supports that structure. Keep the same valuation date and timing convention across cases. A delay can materially reduce present value even when the assumed production profile is unchanged.

When does a DCF need professional review?

Seek appropriate qualified review when title, lease interpretation, reserve classification, engineering forecasts, tax basis, accounting standards, appraisal standards, or legal rights could affect the decision. This educational framework can expose assumptions, but it is not a title opinion, reserve report, engineering study, legal opinion, tax opinion, or professional appraisal.

Sources

• Railroad Commission of Texas, Oil and Gas Production Data (accessed 2026-08-11)
• Railroad Commission of Texas, Production Data Query System FAQs (accessed 2026-08-11)
• Railroad Commission of Texas, Wellbore Query (accessed 2026-08-11)
• Railroad Commission of Texas, Drilling Permit W-1 Query (accessed 2026-08-11)
• Railroad Commission of Texas, Public GIS Viewer (accessed 2026-08-11)
• U.S. Securities and Exchange Commission, Oil and Gas Rules (accessed 2026-08-11)
• U.S. Energy Information Administration, Spot Prices for Crude Oil and Petroleum Products (accessed 2026-08-11)