5-Day A&D Diligence Screen

A&D diligence guide

What 5-day A&D diligence actually covers

A 5-day A&D diligence screen is not a full reserve audit, not a fairness opinion, and not a replacement for title, environmental, land, or legal work. It is a technical screen that tells a buyer whether the package is worth the next increment of attention. In a competitive process, that matters. The buyer may have a teaser, a short reserve summary, a seller deck, a production file, a lease operating statement, and a partial VDR index. The question is not whether every uncertainty has been closed. The question is whether the uncertainty is ordinary, priceable, and manageable before the LOI.

The practical scope is narrow: production quality, reserve reasonableness, PV10 sensitivity, ARO exposure, and price-deck downside. Those five questions are enough to find most early bid-risk problems. They expose whether PDP cash flow is doing the work or whether the story depends on undeveloped inventory. They show whether reported PV10 collapses under a bank deck or moderate commodity stress. They reveal whether plugging and abandonment obligations are a small tail item or a material net value deduction. They also organize the VDR request list so the buyer does not waste the first management call asking generic questions.

The Petropt screen wraps six existing tools around that decision. The reserve audit checklist tests the report. The RBL calculator converts reserve categories into a credit-style borrowing base. The price-deck workbook compares SEC, strip, bank, and management assumptions. The well abandonment calculator sizes ARO exposure. The valuation tools create a range using PV10, NPV, per-flowing-barrel, and Monte Carlo cases. The VDR pre-flight module turns missing support into concrete document requests. The output is a short memo that can sit beside an IC note, lender call script, or bid model.

The 12 lender-grade questions every buyer should ask

The first question is whether proved undeveloped locations are scheduled inside the five-year development expectation and whether any exceptions are documented. The second is whether the PUD development plan is tied to capital, rig timing, working interest, and net revenue interest. The third is whether PDP decline assumptions reconcile to actual production history rather than a smooth curve copied from management guidance. The fourth is whether the price deck is explicitly identified as SEC, strip, management, bank, or some blended case. A reserve report that hides price assumptions should not drive a bid without a sensitivity run.

The fifth question is whether economic limits are disclosed and applied at the well level. The sixth is whether LOE is tied to actual invoices, lease operating statements, or a credible field-level data source. The seventh is whether severance, ad valorem, marketing, gathering, and transportation costs are separated well enough to stress them. The eighth is whether ownership assumptions reconcile to title, division orders, lease schedules, or at least the VDR index. The ninth is whether ARO is disclosed by well or by a traceable package-level method. The tenth is whether non-producing reserves depend on workovers, recompletions, behind-pipe intervals, or facility repairs that are not budgeted. The eleventh is whether forecast capital is consistent with current service costs. The twelfth is whether prior-period reserve revisions are explained. A buyer does not need perfect answers on day five, but silence on several of these questions is a bid-risk signal.

How to read a third-party reserve report skeptically

A reserve report is an engineering opinion, not a cash receipt. Start with the reserve category split. A package with high PDP value is easier to underwrite because production exists, decline can be checked, and operating costs can be traced. A package with high PUD or PDNP value may still be attractive, but the bid should carry execution risk. The first skeptical read is therefore a bridge from total PV10 to PDP PV10, then from PDP PV10 to the last twelve months of actual production and expenses.

Next, isolate the assumptions that create value. If a material share of PV comes from late-life wells with low operating margin, small changes in LOE or abandonment timing can move net value. If value depends on gas prices, compare Henry Hub assumptions to strip and to the buyer's bank deck. If the report uses flat differentials, ask whether gathering, processing, and transportation charges are embedded somewhere else. If the reserve report includes undeveloped locations, check the schedule, capital, spacing assumptions, and operator control. A buyer should be most skeptical when the report is internally polished but externally unsupported: clean tables, large PV, and too few source documents.

PV10 vs PV9 vs PV15 — when each one matters

PV10 is the common reserve-report shorthand because it discounts future net cash flow at 10 percent before income taxes. It is useful for comparing reserve cases, but it is not the same as market value, borrowing-base value, or standardized measure. PV9 appears when a buyer wants a slightly lower discount rate for more stable PDP cash flow, infrastructure-backed assets, minerals, or low-risk operated production. PV15 appears when the package carries higher execution risk, higher decline uncertainty, higher abandonment burden, or limited data support. The number is not magic. The discount rate is a way to express risk and capital preference.

In A&D screening, the important move is to compare the same cash flow under several discount rates rather than argue over a single headline. If PV10 is strong but PV15 falls below the expected bid, the buyer should understand which years are carrying the value. If PV9 and PV10 are close, the asset may be front-loaded and less sensitive to long-dated assumptions. If PV10 depends on production years beyond credible lease life or facility life, the buyer should discount that value more heavily or demand support. Lenders tend to focus on repayment capacity under stress, so a bank-style borrowing base will often feel more conservative than management PV10.

Why bank decks differ from management decks

Management decks are built for planning, capital allocation, and investor communication. Bank decks are built for collateral protection. A management deck may follow strip, a board-approved planning case, or a blended long-term commodity view. A bank deck usually applies a more conservative price path and may cap upside because the lender cares more about downside repayment than upside participation. That difference is not a moral judgment; it is a different claim on the same asset. Equity can own upside. Debt needs protection when prices fall.

This is why a buyer should run the seller deck against SEC pricing, strip pricing, and a bank stress deck before the LOI. A deal that clears on a management deck but fails on a bank deck may still be worth buying with more equity, a lower price, seller financing, hedges, or a reduced leverage plan. It should not be presented as if leverage will be easy. The price-deck workbook is designed to show that bridge: year-by-year WTI and Henry Hub deltas, PV10 impact per deck, and a downloadable XLSX that can be dropped into the IC file.

When to walk vs when to retrade vs when to bid hard

Walking is appropriate when the screen finds a defect that is both material and not readily priceable. Examples include missing ownership support on wells that carry most of the value, PUD value without a credible development path, PDP decline that is materially worse than forecast, regulatory exposure that cannot be bounded, or ARO that consumes the net value of mature wells. In those cases, spending more process time may only create a false sense of precision.

Retrading is appropriate when the problem is material but priceable. If ARO is higher than disclosed, reduce the bid by the net present value of the obligation or require a seller-funded reserve. If the bank deck reduces PV10 enough to constrain leverage, lower the bid or reduce debt assumptions. If LOE is under-supported, hold back value until invoices and joint interest billings arrive. Bidding hard is appropriate when the report support is adequate, PDP performance reconciles, price downside is tolerable, and VDR gaps are explainable rather than structural. A hard bid does not mean ignoring risk; it means the risk has been named and sized.

VDR red flags that should slow a bid

A VDR should contain enough source material to test the reserve report. Missing production by well, missing lease operating statements, missing title or NRI support, missing JIB detail, missing price differential support, and missing ARO schedules should slow the process. A buyer should also look for signs that the VDR was assembled as a sales package rather than a diligence package: polished management slides but no raw files, reserve tables without assumptions, ownership summaries without source documents, and environmental summaries without regulatory backup.

The VDR pre-flight checklist is intentionally procedural. It asks what documents should exist before the buyer opens a full dataroom review. It also separates missing documents from negative findings. A missing P&A cost schedule is not proof of a hidden liability, but it is a reason to withhold value until the exposure can be measured. A missing decline support file is not proof that PDP is overstated, but it is a reason to test actual production history before relying on the curve.

ARO exposure — the buyer's silent liability

Asset retirement obligations are easy to underweight in early A&D work because they sit after the production story. They should be moved forward. A mature asset with dozens of low-rate wells can look attractive on gross revenue and weak on net value once plugging, abandonment, surface restoration, and bonding exposure are considered. The buyer inherits those obligations unless the purchase agreement, state rules, bonding structure, or seller arrangements shift the risk. Even then, the economic burden usually belongs in the bid model.

The screen should estimate ARO per well, timing, discount rate, state defaults, federal or state formula references, and any disclosed plugging trust or escrow arrangement. BLM Instruction Memorandum 2021-039 is useful for federal-well bonding and reclamation context. Texas Railroad Commission formulas and state-level defaults can help frame onshore plugging assumptions. The right answer is not a single public default; it is a documented case that can be adjusted as the buyer receives well status, depth, casing, surface equipment, and operator history.

Worked example: a 5-day A&D screen on a synthetic Mid-Continent non-op package

Assume a synthetic Mid-Continent non-op package with 38 wells, 24 active producers, 8 shut-in wells, 6 PUD locations, net production of 420 BOE/d, and a seller-provided PV10 of $41 million. The teaser says the package has stable PDP cash flow and low capital needs. On day one, the buyer runs the reserve report audit and finds three major gaps: PUD timing is shown in aggregate but not by location, NRI support is summarized but not tied to title files, and ARO is disclosed only as a package-level number. None of those findings kills the deal, but all three move into the document request list.

On day two, the buyer runs the borrowing-base screen. PDP PV10 supports a preliminary base, but the non-producing cap limits PDNP and PUD contribution. The seller's implied leverage is higher than the bank-style case supports. That does not mean the asset is overpriced. It means the buyer should not assume the lender will underwrite the same value as the seller's reserve report. On day three, the price-deck workbook shows that the management deck carries $6 million more PV10 than the bank deck and $4 million more than the strip case. The buyer now has a price-deck bridge rather than a vague concern.

On day four, the ARO screen estimates a higher plugging burden for the shut-in wells than the seller's package-level disclosure. The difference is not enormous, but it offsets much of the value assigned to marginal late-life production. On day five, the valuation range shows a bid band: a low case using bank deck, higher ARO, and PV15; a base case using strip, adjusted ARO, and PV10; and an upside case using management development timing. The go / no-go memo recommends a bid, but with a lower leverage assumption, a targeted ARO holdback, and a short list of documents required before exclusivity. That is the purpose of a five-day screen: not certainty, but a disciplined bid posture.

Public references used in this diligence frame

The screen relies on public sources and buyer-controlled assumptions. Key references include SEC Final Rule 33-8995, Regulation S-K Item 1202, Regulation S-K Item 1203, Regulation S-K Item 1204, the OCC Comptroller's Handbook for Oil and Gas Exploration and Production Lending, Texas Bankers Association borrowing-base guidance, Haynes Boone Energy Bank Price Deck Survey materials, and BLM Instruction Memorandum 2021-039. Public references keep the screen auditable and avoid basin-specific operator calibration.