Phoenician Royalties · Sample report
What is behind this mineral offer?
An illustrative Offer Check for Example Unit A.
The value depends on what gets developed.
Present value under the base assumptions.
Conditional on one assumed well starting in Year 4.
6.1% above the producing-only case.
The offer is $3,715 above the existing-production model. Future development could change the comparison, but there is no real permit, operator plan, or drilling commitment behind this example.
The difference between an offer and modeled value is a question to investigate. It does not establish whether an offer is fair. An achievable sale price also depends on actual bids, the interest being sold, terms, transaction costs, and the owner’s needs. No comparable-sale evidence is supplied here.
1. The assumed ownership
10 net mineral acres in a 1,000-acre unit, a 25% lease royalty, and uniform allocation across the unit:
10 ÷ 1,000 × 25% = 0.0025 revenue interest
That is 0.25% of unit sales. The synthetic division order and statements are assumed to use the same decimal. No real deed, lease, allocation agreement, or title opinion has been reviewed. Matching payment decimals does not establish title.
This assumed royalty bears no drilling capital or lease operating expense in the model. Taxes and post-production deductions are included below. A working interest needs a separate analysis of costs and capital obligations.
2. Producing income and the assumptions
| Input | Assumption |
|---|---|
| Year 1 gross oil sales | 100,000 barrels across existing unit wells |
| Annual volume decline | 15% effective decline in annual volumes |
| Oil price and differential | $70/bbl reference less $3/bbl differential = $67/bbl realized; flat nominal prices |
| Revenue interest | 0.0025 |
| Taxes and post-production deductions | Combined 8% of gross owner royalty revenue; synthetic assumption, not an applicable tax-rate claim |
| Discount and timing | 10% annually, payments at each year-end |
| Horizon | 20 years; no terminal value or well-level economic-limit test |
| Excluded | Gas/NGL revenue, personal income taxes, and sale expenses |
Year 1 owner cash flow is 100,000 × $67 × 0.0025 × 92% = $15,410. Each following year is 85% of the previous year. Present value is the sum of each year’s cash flow divided by 1.10 raised to that year.
Undiscounted annual owner cash flows; development is not probability-weighted in this chart.
| Year | Existing production | New well, only if developed |
|---|---|---|
| 1 | $15,410 | $0 |
| 2 | $13,099 | $0 |
| 3 | $11,134 | $0 |
| 4 | $9,464 | $18,492 |
| 5 | $8,044 | $13,869 |
| 10 | $3,569 | $3,291 |
| 15 | $1,584 | $781 |
| 20 | $703 | $185 |
3. Keep future development separate
The example assumes one new well starts at the beginning of Year 4, sells 120,000 barrels that year, then declines 25% annually. Ownership, realized price, and deductions are unchanged. Only Years 4–20 contribute to its $39,636 conditional value.
If no development occurs within the modeled period, that added cash flow is zero. Changing the first-production date changes the result.
Optional illustration: what a 50% development weighting would mean
A purely hypothetical 50% weight on the specified development schedule and 50% on no development gives $19,818 of additional modeled value, or $81,103 combined.
This is not an assessed probability of drilling. An actual report would need evidence to justify a probability and timing distribution. With insufficient evidence, development should remain a separate scenario.
Where engineering changes the answer
4. The analog group matters
In this invented example, a group of stand-alone wells suggests 150,000 barrels in the first production year. The hypothetical location is next to depleted production. A synthetic comparison group with similar spacing, landing zone, lateral length, and depletion exposure instead supports 120,000 barrels.
That is a $9,909 difference under otherwise identical assumptions. The 20% production adjustment is specific to this fictional example—not a universal depletion factor.
An actual assessment would identify the wells, source data, selection criteria, and limitations supporting that judgment.
5. How sensitive is producing value?
| Scenario | Realized oil price | Annual decline | Discount | Producing value |
|---|---|---|---|---|
| Lower cash flow / higher discount | $52/bbl | 20% | 15% | $34,147 |
| Base example | $67/bbl | 15% | 10% | $61,285 |
| Higher cash flow / lower discount | $82/bbl | 10% | 8% | $102,045 |
Ownership, first-year gross volume, deductions, and horizon are held constant. These scenarios illustrate sensitivity; they do not establish confidence intervals.
6. Questions to resolve in an actual review
- Do the documents, tract allocation, and payment decimal support the interest being sold?
- Are recent payments affected by adjustments, downtime, product mix, prices, or deductions?
- Which analogs support the forecast, and how do spacing and depletion affect the comparison?
- What evidence supports development, its timing, and any probability weighting?
- What does the offer include or exclude, and how do effective dates and transaction costs affect proceeds?
Sources for this sample: synthetic example data and the explicit assumptions above. There are no actual third-party well records or comparable transactions behind the figures.