Reserves Estimation
A clear, defensible estimate of what a well or property will produce, and what that production is worth, built the same way acquisitions get underwritten.
Every reserves estimate starts with production history. Decline curve analysis fits a model, typically an exponential, hyperbolic, or harmonic decline, to a well's actual monthly oil and gas volumes and projects how that well will behave going forward. For newer wells with limited history, or for undeveloped locations that haven't been drilled yet, a type curve built from comparable offset wells fills the gap. Getting this step right matters more than any other, because everything downstream, the reserves number, the cash flow, the value, is built on top of it.
The output of a decline analysis is an estimated ultimate recovery (EUR): the total oil and gas a well is expected to produce over its life. EURs then get sorted into reserve categories that reflect how certain that recovery actually is. Proved developed producing (PDP) reserves come from wells already online. Proved undeveloped (PUD) reserves come from locations reasonably certain to be drilled but not yet producing. Probable and possible reserves sit further out on the risk curve. A property's value depends not just on the total reserves but on the mix across these categories, since a barrel from a producing well and a barrel from an undrilled location carry very different risk.
Reserves are a volume. Economics turn that volume into a number. That means applying a price deck for oil, gas, and NGLs, netting out differentials, taxes, and operating costs, laying out capital for any undeveloped locations, and discounting the resulting cash flow to arrive at a net present value. A good economic model also shows sensitivities: what happens to value if prices move, if type curves underperform, or if development gets delayed. Anyone relying on a single-point number without seeing how it moves under different assumptions is missing half the picture.
Public companies and many lenders require reserves estimates that follow SEC definitions and pricing conventions, including the trailing 12-month average price used for proved reserves. Even for private operators and non-operated owners, reporting to that standard creates a number that holds up to outside scrutiny, whether that's a bank, an auditor, or a counterparty on the other side of a deal. I build estimates and reports that follow those conventions when that level of rigor is what's needed.
This work serves a few different audiences with overlapping needs. Operators use it to plan development and support borrowing base redeterminations. Non-operated and working interest owners use it to check operator projections and understand what their position is actually worth, a question that comes up in many of the same situations covered on the mineral rights valuation page. Investors and lenders use it to underwrite acquisitions or evaluate collateral before committing capital. In every case, the goal is the same: a reserves and economic picture you can trust because you understand how it was built.
I'm a petroleum engineer, a Colorado School of Mines graduate, and a former reservoir engineer at Pioneer Natural Resources with more than ten years in the industry. I'm currently EVP of Engineering at Tilden Capital, where I use ComboCurve daily to underwrite mineral and royalty acquisitions. That's the same platform and the same methods behind every estimate built here, whether the deliverable is a quick sanity check on a single well or a full reserves report on a multi-well package. If you're weighing an acquisition, a valuation on the seller side of a deal like the one described on the mineral rights valuation page, or just want a second opinion on someone else's numbers, the process is the same: build the decline, apply the economics, and show you the assumptions behind the answer.
Common Questions
Decline curve analysis fits a mathematical model to a well's historical production to project how it will produce going forward. It's the foundation of most reserves estimates because it turns a pattern of actual monthly volumes into a defensible forecast of remaining oil and gas, which is what ultimately drives value.
PDP (proved developed producing) reserves come from wells already online and producing. PUD (proved undeveloped) reserves come from locations that are reasonably certain to be drilled but aren't producing yet. Other categories, such as probable and possible reserves, carry progressively more uncertainty. Each category is estimated and risked differently, and the mix matters as much as the total number.
A reserves estimate answers how much oil and gas is likely to be recovered. An economic evaluation takes that volume and applies prices, costs, and timing to answer what it's worth today. You typically need the reserves estimate first, since it's the input the cash flow model runs on.
Yes. I can build reserves estimates and reports that follow SEC definitions and pricing conventions, including the required 12-month average pricing and standard reserve category definitions, for operators and investors who need reporting that holds up to outside review.
Send over what you have, whether well history, an offset type curve, or a full property package, and I'll put together an estimate and economics you can act on.
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