Oil and Gas Reserve Reports as Verifiable Investor Data

By Commertize Desk · Published 30 October 2026

Take one package: 38 producing horizontal wells in a single Permian county, operated by one company, with a 72% net revenue interest to the seller. The reserve report dated 1 July 2026 shows proved developed producing reserves of 4.1 million barrels of oil equivalent net to that interest, current net production of about 1,150 barrels of oil equivalent per day, a first-year decline of 19%, and a PV-10 of $41 million. The seller wants to bring a minority share of that interest to a wider investor base at a minimum well below the usual seven-figure private ticket. Every one of those numbers came from the reserve report, and every one of them can be checked. That is why the report, not the pitch deck, is the asset's real disclosure document.

The figures above are illustrative, but the structure is the one every producing-well transaction uses. US proved reserves of crude oil and lease condensate stood at about 46 billion barrels at year-end 2024, down 1% on the year, with natural gas at 584 trillion cubic feet, according to the US Energy Information Administration's year-end 2024 proved reserves report published 29 April 2026. That national total is built the same way the package above is: operator by operator, well by well, under a shared set of definitions.

What the report is and who signs it

A reserve report is an engineering estimate of how much oil and gas a set of wells will produce, when, and what that production is worth under stated prices and costs. For a sale or a securities offering, it is prepared or audited by an independent petroleum engineering firm, not the operator. The engineer's signature is the first thing an investor should look for, along with the effective date, because reserves are a snapshot that moves every month as wells produce and prices change.

The definitions are standardized. The SEC's Rule 4-10 of Regulation S-X defines proved reserves as volumes that geological and engineering data demonstrate with reasonable certainty are economically producible under existing conditions. The industry's technical framework, the Society of Petroleum Engineers' Petroleum Resources Management System, revised in 2018, sorts reserves into proved, probable and possible, and further into developed and undeveloped. Our package is entirely proved developed producing, written PDP in every report: wells that exist, are flowing and are already connected to sales.

That distinction decides what an investor is buying. PDP cash flow depends on decline, price and operating cost. Proved undeveloped reserves, or PUDs, add drilling risk, capital calls and timing. A package that is 100% PDP is a cash-flow asset. A package that is 40% PUD is partly a development project, and the two should never be priced the same way.

Reading the four numbers that matter

Net reserves. The 4.1 million barrels of oil equivalent is net to the 72% net revenue interest after royalties and burdens. Gross wellhead volumes are larger and irrelevant to the investor. Checking that the report's ownership decks match the title opinion and division orders is the single most common diligence failure in these deals.

Current production and decline. The 1,150 barrels per day figure is a trailing average, not a promise. Horizontal shale wells decline steeply early and flatten later. A 19% first-year decline on an established package is moderate; a package of wells less than two years old might show 35% or more. The report gives the forecast curve. The operator's monthly production statements, filed with the state regulator and visible in public well records, let any investor compare forecast against actual every month.

Price deck. Under the SEC's reporting rules, adopted in the Commission's Modernization of Oil and Gas Reporting release of December 2008 and effective for fiscal years ending after 31 December 2009, proved reserves are valued at the unweighted average of first-day-of-the-month prices over the prior twelve months. The investor needs to know which deck was used and should ask for a sensitivity at a lower one.

PV-10. The $41 million is the present value of forecast future net revenue from proved reserves, discounted at 10% a year, before income tax. It is a standardized comparison tool, not a market price. The audited financial statements of public producers report a related after-tax figure, the standardized measure, under ASC 932. For a private package the pre-tax PV-10 is usually what is disclosed, and an investor should treat the gap to an after-tax number as real.

From report to monthly distribution

Here is how the package's economics flow to a holder in a given month. Gross production is sold under the operator's marketing contracts at a realized price, which sits below the benchmark by a basis differential and transport cost. Royalties and overriding royalties come off first. Severance and ad valorem taxes come next. Lease operating expenses, which for mature horizontal wells in this basin can run in the range of $8 to $14 per barrel of oil equivalent, are deducted. What remains is net operating cash flow to the working interest, and the seller's 72% net revenue interest share of that is what funds distributions.

On the illustrative numbers, 1,150 barrels per day at a $62 realized price yields roughly $2.1 million of gross monthly revenue to the interest, and after burdens, taxes and operating cost, net cash available might be in the range of $1.3 to $1.5 million before any hedging. That number falls every month as the wells decline unless production is added, which is why a distribution figure quoted without a decline curve is not information.

The point is not the arithmetic. It is that every input has a source document: the reserve report for volumes and decline, the operator's check stubs and run tickets for realized prices, the state regulator's production filings for volumes, the division orders for ownership. An offering that puts those documents in front of investors, with their dates, is verifiable. An offering that quotes a yield is not.

Why verifiable data changes who can own the asset

Producing well interests have historically been bought by operators, private equity funds and a small set of high-net-worth drilling-fund investors, with minimums set by the cost of diligence rather than by the asset. If each buyer has to commission their own engineering review, a small ticket makes no sense.

A digital record changes the economics of that diligence. When the reserve report, the ownership decks and the monthly production statements are published once, dated, and attached to the offering record, every holder reads the same evidence. Monthly distributions can be reconciled against the operator's statements rather than taken on trust. A secondary buyer in month 18 can see 18 months of forecast-versus-actual before bidding. That is what makes a smaller minimum sensible and a secondary market possible, and it is the same discipline described in Commertize's guide to tokenization for energy and digital infrastructure. How the digital record, investor onboarding and distributions fit together is set out in how Commertize's digital capital markets work.

Diligence questions the report alone does not answer

A reserve report is necessary and not sufficient. Before any producing interest is brought to a wider investor base, the sponsor should be able to answer, with documents:

1. Operator quality. Who operates, what is their lease operating expense history on comparable wells, and what are the terms of the joint operating agreement, including the non-operator's audit rights?
2. Hedging. Is any production hedged, at what price, for how long, and does the hedge counterparty have a claim on the interest?
3. Plugging liabilities. What asset retirement obligations attach to the wells, who bears them, and are they funded?
4. Title. Does a current title opinion support the net revenue interest shown in the report?
5. Report currency. How old is the effective date, and has anything material, such as a shut-in, a workover or a price move, happened since?

None of these is new. What is new is that the answers can be recorded alongside the interest, updated monthly, and read by every holder and every prospective buyer at the same time.

What to do next

If you have a producing oil and gas interest you are considering bringing to market, start at Commertize's energy infrastructure tokenization page.

Prefer email? Send the offering memo or a short asset summary to deals@commertize.com. We reply within one business day, with no obligation to engage us.