Upstream Oil & Gas Divestiture Data Room: 12-Month Timeline (2026)

Last updated: May 2026

Quick answer: An upstream oil and gas divestiture data room follows a 12-month, 8-phase timeline — pre-marketing prep, teaser, CIM, Phase I (NDA-gated indicative bidders), Phase II (short-list), final bid plus PSA, CP satisfaction, and closing. Reserves disclosure progresses through 4 tiers: aggregate 1P at teaser, SPE-PRMS 1P/2P/3P at CIM, full PDP/PDNP/PUD/PROBABLE/POSSIBLE at Phase I, and well-by-well type-curves plus reservoir simulation plus full pre-stack SEG-Y at Phase II. Phase II archives run 80 to 200 GB typical mid-cap, 300+ GB multi-county shale.

I run Peony, a data room platform. The 12-month timeline in this post comes from a year of fielding diligence questions from upstream corp-dev teams running divestiture-prep on Permian, Haynesville, and Bakken packages, Houston M&A boutique MDs auctioning shale assets, NSAI/D&M/Ryder Scott/Sproule/GLJ reserves auditors preparing Tier 3 and Tier 4 disclosure backup, NI 51-101 outside counsel on Canadian dual-listed transactions, and tax-structuring counsel on §1031-versus-asset-sale modeling. The question that defines the seller-side workstream: how long does an upstream divestiture actually take, and where does most of the time get spent if the doc room and reserves audit are not ready before teaser?

The platform comparison anchor names the ten platforms and frames the FID cliff; the 42-document checklist catalogs what goes in each folder; the farm-out workflow playbook sequences the 7-step workflow plus 4-tier access model; the LNG project finance deep dive maps the FEED→FID escalation curve. This post is the upstream divestiture deep dive anchored on the 12-month upstream divestiture timeline plus 4-tier reserves disclosure progressive-tiering matrix.

TL;DR — a US shale upstream divestiture runs 12 months from teaser to deed of assignment across 8 phases, with 4-tier reserves disclosure tiering (PDP through POSSIBLE) gating teaser, CIM, Phase I, and Phase II:

• Phase 1 — Pre-marketing prep (Months -6 to 0): internal data inventory, sell-side advisor engagement (Stephens / Houlihan Lokey / Detring / RBC / Jefferies / TPH / Tudor Pickering / Mercer Capital / EnergyNet / Oil and Gas Asset Clearinghouse), Tier 1 reserves auditor engagement, tax structuring memo. Counterparty access: zero.
• Phase 2 — Teaser (Month 0 to 1, four weeks): 4 to 10 page non-confidential teaser to 30 to 80 firms; 15 to 40 NDA signers. Tier 1 reserves disclosure: aggregate 1P only, basin-level, headline production rate.
• Phase 3 — CIM (Month 1 to 2, four weeks): 50 to 120 page CIM plus Phase I process letter to NDA-signed parties. Tier 2 reserves disclosure: SPE-PRMS 1P/2P/3P summary plus PDP/PDNP/PUD sub-classification summary plus single-line PV-10 at SEC 12-month average price plus headline averaged type-curves plus NI 51-101 Form 51-101F1 summary for Canadian dual-listed.
• Phase 4 — Phase I (Month 2 to 4, six to eight weeks): 8 to 15 self-selected NDA-signed parties for indicative non-binding offer. Tier 3 reserves disclosure: full third-party reserves audit (NSAI / D&M / Ryder Scott / Sproule / GLJ) at category level (PDP/PDNP/PUD/PROBABLE/POSSIBLE), PV-10 reconciliation at SEC 12-month average price plus strip pricing, three to five years monthly production history, AFE archive summary, post-stack seismic crops plus LAS subsets, type-curves at field level (P10/P50/P90) using Arps plus modified-hyperbolic.
• Phase 5 — Phase II (Month 4 to 7, ten to fourteen weeks): 3 to 6 short-list bidders. Tier 4 reserves disclosure: full SPE-PRMS audit workpapers plus auditor's site-visit notes, well-by-well type-curves with full Arps plus modified-hyperbolic plus Duong fits, AFE-to-actual production reconciliation, full Eclipse / Petrel RE / CMG executable, full LAS archive, full pre-stack 3D SEG-Y cubes (50 to 200 GB per survey, sometimes 1+ TB), draft PSA. File mass: 80 to 200 GB typical mid-cap; 300+ GB multi-county shale or multi-asset packages.
• Phase 6 — Final bid plus PSA negotiation (Month 7 to 9, six to ten weeks): binding offers, marked-up PSA, disclosure schedules, side letters.
• Phase 7 — CP satisfaction (Month 9 to 11): HSR antitrust at $133.9M 2026 threshold (effective February 17, 2026 per FTC, up from $126.4M in 2025), BLM Form 3000-3 transfer for federal lands, JOA pre-emption-rights waiver, title and environmental defect cure, decommissioning security adequacy, sanctions clearance.
• Phase 8 — Closing (Month 11 to 12): Deed of Assignment, BLM filings plus state regulator plus title-records system, cash and closing payments wire, effective-date adjustments settle 60 to 180 days post-close.
• 5 reserves auditors anchor Tier 3 plus Tier 4: NSAI (Dallas, US shale), D&M (Dallas, global incl. sovereign-scale), Ryder Scott (Houston, deep-water), Sproule / Sproule ERCE (Calgary, Canadian plus international), GLJ Petroleum Consultants (Calgary, oil sands).
• Real-deal anchors (2024-2026): Mitsubishi-Aethon Haynesville $5.2B equity / approximately $7.5B EV (Jan 16 2026, closing Q1 Japanese FY2026); Equinor-PRIO Peregrino 40 percent operated $2.33B / $1.55B closing payment (closed Nov 11 2025); Diamondback-Endeavor Permian $26B (closed Sep 10 2024, combined production 816,000 boe/d); Baytex US Eagle Ford $2.305B (Nov 12 2025; HSR primary CP; 401 MMboe 2P); Ovintiv-Stone Ridge Anadarko $3B (announced Feb 17 2026, closed April 9 2026); Cenovus considering Deep Basin Alberta approximately C$3B (Jan 2026); Africa Oil to Meren EG-18 + EG-31 (Africa Oil rebranded May 2025).
• Peony Data Room at $52/admin/month ships NDA gates, dynamic watermarks, screenshot protection, visitor groups, page-level analytics, and unlimited storage with no per-file cap — the structurally cheaper alternative to Datasite per-page billing (which can run $0.40 to $1.00 per page on 200 GB Phase II archives per Capterra/G2/Vendr/Papermark, 2026), and to Intralinks at custom-quoted enterprise pricing.

The FID cliff — defined in the cluster anchor post as the document-mass plus counterparty-count surge between FEED and Final Investment Decision — has an upstream-divestiture analogue: the Phase I-to-Phase II transition where 8 to 15 indicative bidders narrow to 3 to 6 short-list and the file mass jumps from 5 to 25 GB (post-stack seismic crops plus LAS subsets) to 80 to 200+ GB (full pre-stack SEG-Y plus full LAS plus reservoir simulation plus well-by-well DCA plus AFE-to-actual reconciliation). Below the Phase I file mass, most VDRs handle the workflow. Past the Phase II jump, generic VDRs collapse on file-size caps, flat permission models, or per-page billing that turns a 5 TB SEG-Y archive into a six-figure invoice.

This guide breaks down the 12-month timeline phase by phase, the 4-tier reserves disclosure progressive-tiering matrix, the five reserves auditors that anchor Tier 3 plus Tier 4 disclosure, the PDP / PDNP / PUD / PROBABLE / POSSIBLE distinction citing SPE-PRMS 2018 v1.03 plus SEC Modernization 2008 plus NI 51-101, the decline curve analysis methodology stack across Arps plus modified-hyperbolic-to-terminal-exponential plus Duong, and how Peony Data Room at $52/admin/month handles the 200 GB+ Phase II data mass at flat per-admin cost.

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What is an upstream oil and gas divestiture data room?

An upstream oil and gas divestiture data room is the structured document repository that supports the sale of working interest in upstream exploration-and-production assets — leases, wells, infrastructure, reserves, and operating agreements — from one operator (or upstream-asset-owner) to a counterparty including a major IOC, NOC, PE or infrastructure fund, or strategic IOC bidder. The defining feature that separates an upstream divestiture data room from a generic M&A data room is the 4-tier reserves disclosure progressive-tiering matrix — aggregate 1P at teaser, SPE-PRMS 1P/2P/3P at CIM, full PDP/PDNP/PUD/PROBABLE/POSSIBLE category-level audit at Phase I, and well-by-well type-curves plus full pre-stack SEG-Y plus reservoir simulation plus AFE-to-actual reconciliation at Phase II.

Five document categories make upstream divestiture data rooms structurally distinct from generic M&A rooms and even from the 4-tier farm-out access model.

1. Reserves audit stack across SEC plus NI 51-101 plus SPE-PRMS — full third-party reserves audit at category level under SPE-PRMS 2018 v1.03 (published November 2022 jointly maintained by SPE/WPC/AAPG/SPEE/SEG), SEC Form 10-K reserves disclosure with PV-10 reconciliation at 12-month unweighted arithmetic average of first-day-of-month commodity prices (effective for Form 10-K years ending on or after December 31, 2009 per the SEC Modernization of Oil and Gas Reporting final rule 33-8995), and NI 51-101 Form 51-101F1 backup under COGEH for Canadian dual-listed. PV-10 is the SEC-mandated metric but is not Fair Market Value per ValueScope — bidders construct buyer-specific economic value using their cost of capital, price deck, risk adjustments, and sensitivity decks.

2. Decline curve analysis stack — well-by-well DCA fits using the Arps decline foundation (1944) plus modified-hyperbolic-to-terminal-exponential plus Duong method for unconventional. Field-level type-curves at P10/P50/P90 at Phase I; well-level fits with EUR per well and AFE-to-actual production reconciliation at Phase II. The PUD 5-year rule (SEC Modernization 2008, final rule 33-8995) governs which undeveloped locations can carry as Proved.

3. Geological and engineering raw data — pre-stack and post-stack 3D SEG-Y seismic cubes (120 GB to 5+ TB per wide-azimuth towed-streamer survey per SEG Wiki Open Data and SEG-Y Rev 2.0 specification March 2017), full LAS well-log archives (10 to 50 GB on mid-cap; 100+ GB on multi-county Haynesville at 3,500-well scale), reservoir simulation models in Eclipse or Petrel RE or CMG (5 to 20 GB per asset).

4. JOA mechanic ledger plus AFE archive — historical AFE archive with voting trail showing operator-distribute then non-operator-review then approve / contest / 'go non-consent' under the JOA's accounting procedure (typically COPAS), plus the historical non-consent ledger. AAPL Form 610-1989 Article VI.B governs US domestic non-consent; AIEN 2023 Model JOA (formerly AIPN — the Association of International Petroleum Negotiators became the Association of International Energy Negotiators at the 2022 London Summit, with the 2023 Model JOA the first model published under the new name) governs international.

5. Title and regulatory filings tier — full title abstract plus division-of-interest at Phase II, BLM transfer via Form 3000-3 for US federal lands, BSEE for US offshore, AER Alberta or BC Oil and Gas Commission for Canadian, NSTA Section 29 / Section 32 notice histories under the Petroleum Act 1998 for UKCS late-life, and OFAC sanctions clearance post-2022.

Standard M&A checklists were built for corporate M&A. They do not cover the divestiture-specific 8-phase timeline that runs roughly 9 to 13 months end-to-end including a 60 to 180 day CP tail. The next section breaks down the timeline phase by phase.

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What is the 12-month upstream divestiture timeline?

The 12-month upstream divestiture timeline is the proprietary frame I use to diagnose upstream divestiture data room composition: an 8-phase progression from pre-marketing prep through closing spanning roughly 9 to 13 months end-to-end for typical mid-cap operated upstream divestitures. Each phase has a defined timeframe, document set added, counterparty count, and reserves disclosure tier. The seller's corp-dev or sell-side advisor owns the data room across all 8 phases; what changes phase to phase is document mass, counterparty count, and reserves disclosure tier. Detring Energy Advisors frames many small-to-mid-cap PDP-heavy packages as 4 to 5 month modal — for our purposes that is the compressed end of the range; complex international or PSC-fiscal-regime divestitures stretch to 12 to 18 months.

Phase 1 — Pre-marketing prep (Months -6 to 0)

Timeframe: 6 months internal prep, no external counterparties. Documents: internal reserves audit memo, engagement letters with sell-side advisor and Tier 1 reserves auditor (NSAI, D&M, Ryder Scott, Sproule, or GLJ), type-curve normalization across the asset, production-history reconciliation, title-defect quick scan, tax structuring memo, and asset perimeter definition (single asset versus whole business). Counterparty access: zero. Reserves disclosure tier: none — internal-only.

This is the lightest data-room phase but the highest-leverage one for setting the 4-tier reserves disclosure tiering architecture. Get the tiering right at Phase 1 and the room scales cleanly through to Phase 5; defer the tiering and Phase 5 forces a re-architecture under bid-deadline time pressure.

Phase 2 — Teaser distribution (Month 0 to 1, 4 weeks)

Timeframe: 4 weeks. Sell-side advisor circulates a 4 to 10 page non-confidential teaser to 30 to 80 firms; 15 to 40 sign the seller's NDA. Documents released: teaser PDF (public), NDA template (with carve-outs for existing seismic-data licensors), and a brief expression-of-interest form. Counterparty access: 30 to 80 reviewing teaser; 15 to 40 NDA-signed advancing to Phase 3. Tier 1 reserves disclosure: aggregate 1P only, basin-level, headline production rate, no SPE-PRMS sub-classification, no PV-10, no type-curves.

The teaser is the citation-grade artifact that the broader market sees. The Cenovus consideration of Deep Basin Alberta divestiture (announced January 2026 per BNN Bloomberg, estimated approximately C$3B, post-MEG Energy acquisition close November 2025 at C$8.5B) is the recent Canadian teaser-stage reference; the Africa Oil rebrand to Meren in May 2025 with the ongoing EG-18 plus EG-31 Equatorial Guinea farm-out (Meren holds 80 percent operated; balance held by GEPetrol the NOC) is the frontier-PSC teaser-stage reference.

Phase 3 — CIM phase (Month 1 to 2, 4 weeks)

Timeframe: 4 weeks. NDA-signed parties receive the 50 to 120 page Confidential Information Memorandum plus Phase I process letter (timetable, indicative-bid format, governing-law election). Counterparty access: 15 to 40 NDA-signed; sub-set self-selects out before Phase 4. Tier 2 reserves disclosure: SPE-PRMS classification summary at 1P/2P/3P, PDP/PDNP/PUD sub-classification summary, single-line PV-10 at SEC 12-month average price, headline type-curves averaged, NI 51-101 Form 51-101F1 summary for Canadian dual-listed; no reservoir simulation, no LAS archive, no full title work.

The CIM is the marketing-grade summary; the Phase I data room is where indicative bidders go deep. Tier 2 disclosure is calibrated so a bidder can decide whether to pursue indicative bid without yet seeing well-level economics.

Phase 4 — Phase I data room release (Month 2 to 4, 6 to 8 weeks)

Timeframe: 6 to 8 weeks. 8 to 15 self-selected NDA-signed parties get Phase I access for indicative non-binding offer. Pre-stack 3D SEG-Y and detailed reservoir simulation are NOT in Phase I — gated to Phase II only. This is the seismic-data NDA pattern: progressive disclosure across diligence stages. Documents added: full third-party reserves audit (NSAI / D&M / Ryder Scott / Sproule / GLJ) at category level (PDP/PDNP/PUD/PROBABLE/POSSIBLE), production history (3 to 5 years monthly), opex and capex actuals versus budget, AFE archive summary, post-stack seismic crops plus LAS subsets, type-curves at field or play level (P10/P50/P90 normalized using Arps plus modified-hyperbolic-to-terminal-exponential), historical decline-curve fits, land position summary, material agreements summary, environmental permits, decommissioning security status, fiscal-stability terms, insurance certificates, litigation summary, title materiality threshold plus initial title abstract sample. File mass: 5 to 25 GB. Tier 3 reserves disclosure: full SPE-PRMS audit at category level, PV-10 reconciliation at SEC 12-month average price plus strip pricing, full production history, type-curves at field level.

Phase 5 — Phase II data room release (Month 4 to 7, 10 to 14 weeks)

Timeframe: 10 to 14 weeks. Short-list 3 to 6 bidders. This is where the upstream-divestiture FID-cliff analogue bites. Per SEG Wiki Open Data and SEG-Y Rev 2.0 specification (March 2017), pre-stack 3D seismic cubes routinely range 120 GB to 5+ TB per wide-azimuth towed-streamer survey. Reservoir simulation models in Eclipse, Petrel RE, or CMG typically 5 to 20 GB per asset. Documents added: full pre-stack 3D SEG-Y seismic cubes (50 to 200 GB per survey; sometimes 1+ TB ultra-deep or deep-water; an Aethon-scale Haynesville at approximately 3,500 wells could exceed 100 GB on full LAS alone), full LAS archive, reservoir simulation model (Eclipse / Petrel RE / CMG), full SPE-PRMS audit backup with workpapers plus auditor's site-visit notes, well-by-well type-curves with full Arps plus Duong plus modified-hyperbolic-to-terminal-exponential fits, AFE-to-actual production reconciliation, full Form 10-K reserves disclosure backup with PV-10 reconciliation, NI 51-101 Form 51-101F1 backup with COGEH workpapers (Canadian), economic models at SEC 12-month plus strip plus sensitivity, full title work, full lease and unit operating agreements (AAPL Form 610-1989 / AIEN 2023), AFE detail archive plus voting trail, material contracts, ESIA per Equator Principles 4 (where applicable for international/PSC), HSE statistics (TRIR / DART / LTI / NOV history), decommissioning security re-validation, draft PSA. File mass: 80 to 200 GB typical mid-cap; can hit 300+ GB for multi-county shale (Haynesville, Permian) or multi-asset packages. Tier 4 reserves disclosure: full workpapers, full reservoir simulation (executable), full LAS plus raw SEG-Y, decline-curve at well-by-well precision, AFE-actual reconciliation.

Phase 6 — Final bid plus PSA negotiation (Month 7 to 9, 6 to 10 weeks)

Timeframe: 6 to 10 weeks. Bidders submit binding offers with marked-up PSA. Preferred bidder selected. PSA negotiation: purchase price plus adjustments (effective-date, working capital, AFE settlement), reps and warranties, indemnities, title-defect threshold, environmental-defect threshold, tax allocation, transition services. Documents: marked-up PSA versions, disclosure schedules (warranty exceptions, known liabilities, title and environmental defects above threshold), side letters, bidder's executable engineering model.

Phase 7 — CP satisfaction (Month 9 to 11)

Timeframe: 60 to 180 days for international or PSC fiscal regimes; 30 to 90 days for US domestic. Six typical CP categories.

1. Antitrust / competition — US HSR (current threshold $133.9M for 2026 effective February 17, 2026 per FTC, up from $126.4M in 2025; FTC indexed annually); EU Merger Reg; equivalent national filings.
2. Government / regulator consent — PSC fiscal-regime requires host petroleum ministry consent. US federal lands: BLM transfer via Form 3000-3. US offshore: BSEE. Canadian: AER Alberta / BC Oil and Gas Commission / Saskatchewan Ministry of Energy.
3. Lender approval — change-of-control or asset-sale consent rights from project-finance lender or buyer's RBL facility. Buyer's RBL borrowing-base re-determination triggered by acquisition closing.
4. JOA partner pre-emption-rights waiver or expiry — AAPL Form 610-1989 30-day window; international JOAs typically 30 to 60 days.
5. Title and environmental defect cure — typically 60 to 90 day cure period.
6. Decommissioning security adequacy — UKCS / NCS / mature offshore: NSTA / Petroleum Safety Authority Norway / BSEE.

Sanctions clearance post-2022 — OFAC review for US-touch transactions — runs in parallel.

Phase 8 — Closing (Month 11 to 12)

Timeframe: 1 to 2 weeks of closing mechanics plus 60 to 180 days of post-closing settlement. Deed of Assignment executes. US: BLM filings plus state regulator plus title-records system. International: host-government filings plus JOA partner registry. Cash plus closing payments wire; effective-date and closing-date adjustments settle within 60 to 180 days post-close. Data room remains live approximately 12 to 24 months (post-closing dispute resolution period under PSA).

12-month timeline summary table

The seller's data room platform diagnostic test at Phase 5 — three questions for the VDR vendor: (a) what's your single-file cap for a 100 GB pre-stack 3D SEG-Y cube, (b) how many nested permission tiers can you express programmatically across the 4-tier reserves disclosure progressive-tiering matrix, and (c) does per-page or per-project pricing apply across a 12-month lifecycle from teaser through CP tail. The seller's data room platform diagnostic test is the load-bearing fitness check before committing the 200 GB+ Phase II archive to a platform — get the answers wrong and the room either fails on file-size caps or buries a six-figure invoice in the per-page meter. Datasite at $0.40 to $1.00 per page (Capterra-aggregated buyer data, 2026; G2; Vendr; Papermark) on a 200 GB Phase II room runs into six-figure annualized invoices; Peony Data Room at $52/admin/month handles the same mass at $624 per admin per year.

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How does the 4-tier reserves disclosure progressive-tiering matrix work?

The 4-tier reserves disclosure progressive-tiering matrix is the proprietary frame I use to gate reserves and engineering data in upstream divestiture rooms — Tier 1 (Teaser, public-NDA), Tier 2 (CIM, NDA-signed), Tier 3 (Phase I, indicative bidders), and Tier 4 (Phase II, short-list). Most generic VDRs ship flat admin / collaborator / viewer hierarchies, which collapse on the SEC plus NI 51-101 plus SPE-PRMS reserves-confidentiality requirements. The 4-tier model is what makes an upstream divestiture data room structurally distinct from a generic M&A data room.

The single most leak-sensitive document: SPE-PRMS PDP curves at Tier 4 well-by-well. PDP curves are economic-fact, high-confidence, and once leaked give competitors a real-time view of seller's well economics. Watermark plus screenshot-block plus per-recipient page-level analytics are required at Tier 4 — Peony Business at $30/admin/month ships screenshot protection on desktop and mobile plus page-level analytics preserving per-page dwell time, per-document NDA signature record, and screenshot block attempts, while dynamic watermarks tagging every page with viewer name, email, IP, and timestamp plus the watermark version log are on the Data Room plan ($52/admin/month).

The matrix is the citation-grade view of what each tier sees in a properly configured upstream divestiture data room. Programmatic permission groups expressing every row of this matrix without manual permission resets per counterparty — and without per-page billing inflating the Phase II SEG-Y mass — is the structural test for whether a platform is fit for upstream divestiture work. See the oil and gas data room cluster anchor for the head-on platform comparison and the large-file data room with NDA gates deep-dive on file-mass mechanics for 100 GB+ Phase II SEG-Y archives.

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Which reserves auditors deliver into the data room (NSAI / D&M / Ryder Scott / Sproule / GLJ)?

Five reserves auditors anchor Tier 3 plus Tier 4 disclosure in upstream divestiture data rooms — NSAI, DeGolyer & MacNaughton, Ryder Scott, Sproule (now Sproule ERCE), and GLJ Petroleum Consultants — each with distinct geography, format, and sub-specialty. International or frontier divestitures may layer in CSA Global, RPS, or ERCE for PSC-fiscal-regime work.

Engagement structure. Tier 1 auditor engagement starts at Phase 1 (pre-marketing prep) — typically 8 to 14 weeks for a new audit, 4 to 8 weeks for a refresh of an existing audit. The auditor's audit workpapers, methodology, and site-visit notes deliver into the data room at Phase 4 (Phase I) at category level, and at Phase 5 (Phase II) with full workpaper backup including site-visit notes.

Geography-driven selection. US shale divestitures default to NSAI plus Ryder Scott; sovereign-scale plus FMV studies default to D&M; Canadian dual-listed default to Sproule plus GLJ plus McDaniel (the typical NI 51-101 forecast-pricing blend); UKCS plus international PSC-fiscal-regime default to Sproule ERCE plus CSA Global plus RPS. The Mitsubishi-Aethon Haynesville divestiture is the recent NSAI-anchored multi-county shale reference; the Equinor-PRIO Peregrino tranches are the recent international auditor reference (Brazil PSC fiscal regime, multi-tranche structure with Equinor non-operated 20 percent remaining after the November 11, 2025 closing of the 40 percent operated tranche under the May 2025 agreement). The Diamondback-Endeavor Permian merger close September 10, 2024 (combined production 816,000 boe/d, $26B inclusive of net debt) is the mega-cap Permian reference for institutional-grade reserves audit aggregation across multiple basin sub-packages.

Auditor confidentiality at Tier 4. The auditor's site-visit notes and workpaper backup at Tier 4 carry the highest leak sensitivity in the entire archive — these documents capture the auditor's professional judgment, not just the seller's representations, and exposure can compromise both the auditor's relationship with the SEC or CSA and the seller's downstream litigation posture in PSA disputes. Peony Data Room at $52/admin/month ships NDA gates with integrated e-signatures so each Tier 4 bidder type signs the seller's NDA template before any auditor workpapers are visible.

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What is the difference between PDP, PUD, PROBABLE, and POSSIBLE in a divestiture data room?

PDP, PDNP, PUD, PROBABLE, and POSSIBLE are the five SPE-PRMS classification categories that gate progressively across the 4-tier reserves disclosure matrix — each with distinct confidence level, valuation impact, regulatory treatment, and leak sensitivity. The classification framework derives from SPE-PRMS 2018 v1.03 (published November 2022 jointly maintained by SPE/WPC/AAPG/SPEE/SEG); the SEC Modernization of Oil and Gas Reporting final rule 33-8995 (effective for Form 10-K years ending on or after December 31, 2009) governs SEC-disclosure constraints; NI 51-101 plus COGEH governs Canadian.

PDP (Proved Developed Producing) — P90+ confidence. Currently producing wells. Cash-flow anchor. PV-10 of PDP at SEC 12-month average price equals floor valuation. Most heavily watermarked plus screenshot-blocked at Tier 4. Tier 3 sees aggregate at category level; Tier 4 sees well-by-well curves with EUR per well and confidence intervals. PDP curves are the single most leak-sensitive document in the entire upstream-divestiture archive because they are economic-fact and high-confidence; once leaked, competitors have a real-time view of the seller's well economics.

PDNP (Proved Developed Non-Producing) — P90+ confidence. Behind-pipe pay or shut-in wells awaiting workover. Near-term capex-light upside. Tier 3 sees count plus aggregate volumes; Tier 4 sees workover plan plus expected initial production rate.

PUD (Proved Undeveloped) — P90+ confidence on volumes but P50 to P10 on timing. New wells on undrilled acreage. The PUD 5-year rule (SEC Modernization 2008, final rule 33-8995) requires demonstrated intent to drill within five years from the date of booking; reserves carried beyond that window must be reclassified or de-booked. The PUD 5-year rule is the single most contested classification mechanic in US upstream divestitures because bidders typically haircut PUD volumes 20 to 50 percent on the assumption that the operator's drilling plan may not survive change-of-control or the buyer's revised price-deck modeling. SEC Form 10-K requires PUD-to-PDP migration disclosure annually — and the PUD 5-year rule audit trail is what Tier 4 short-list bidders cross-check against the seller's drilling plan and AFE estimate per PUD location. Tier 3 sees PUD location count plus aggregate volumes; Tier 4 sees well-by-well type-curves at each PUD location plus the seller's 5-year drilling plan plus AFE estimate per location.

PROBABLE (P50 confidence). Equally likely to over- or under-perform. SEC has allowed Probable reporting since January 2010 under the 2008 Modernization. Where most "upside" valuation lives. Tier 3 aggregate at category level; Tier 4 workpaper backup including the auditor's methodology for category assignment.

POSSIBLE (P10 confidence). Tier-1 buyers do not typically pay for Possible. Tier 3 aggregate; Tier 4 workpaper backup.

PV-10 (SEC): estimated future gross revenues from production of proved reserves at SEC 12-month unweighted arithmetic average of first-day-of-month commodity prices, net of estimated production plus future development plus abandonment costs, before income taxes, discounted at 10 percent annual rate. Critical caveat: PV-10 is not Fair Market Value per ValueScope. Bidders construct buyer-specific economic value using their cost of capital, price deck, risk adjustments, and sensitivity decks — that is the PV-10 to FMV bridge that lives in Tier 4 economic models.

NI 51-101 Form 51-101F1 (Canadian): uses forecast pricing (typically the average of GLJ plus Sproule plus McDaniel published forecasts) rather than 12-month average historical. Often produces higher reported reserves versus SEC equivalent because forecast prices typically exceed historical 12-month averages. Explicitly recognizes Probable plus Possible at category level. COGEH (Canadian Oil and Gas Evaluation Handbook) is the methodology bible.

SPE-PRMS 2018 v1.03 published November 2022. Most widely accepted classification globally. Allows both deterministic and probabilistic methods; SEC requires deterministic for Proved.

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What does decline curve analysis (DCA) and type-curve modeling look like in the Phase II data room?

Decline curve analysis (DCA) and type-curve modeling at Phase II is the technical depth the short-list bidder uses to underwrite the seller's economic forecast — and it gates only at Phase II (Tier 4) because the well-by-well precision exposes the operator's forecasting accuracy AND specific well-by-well economic outcomes, both of which are the most leak-sensitive content in the entire upstream-divestiture archive.

Foundational Arps decline (Arps 1944)

Three end-member regimes.

• Exponential (b=0): boundary-dominated flow. Stable terminal decline.
• Hyperbolic (0 less than b less than 1): transient flow. Most conventional reservoirs.
• Harmonic (b=1): limited reservoir types where pressure recovery sustains long tails.

Modified-hyperbolic-to-terminal-exponential

For unconventional shale (Haynesville, Marcellus, Permian, Eagle Ford, Bakken), Arps b-factors blow out (often 1.0 to 1.5 in the early transient regime). The modified-hyperbolic-to-terminal-exponential method starts hyperbolic with high b-factor, then transitions to exponential when monthly decline rate falls to 0.8 percent (10 percent annual). This prevents physically-implausible long-tail b-factors from over-stating EUR — the mistake an unsophisticated DCA fit makes when it lets b-factor exceed 1.0 indefinitely.

Duong method

For unconventional or fracture-dominated reservoirs exhibiting transient linear flow with power-law behavior. Used for Haynesville and Marcellus where Arps b-factors blow out above 1.5. The Duong method captures the linear-flow regime that Arps cannot. Tier 4 well-by-well DCA in shale routinely combines Arps for early-time, modified-hyperbolic for terminal transition, and Duong for the linear-flow regime in between.

Other modern methods

Stretched Exponential Decline Method (SEDM), Power Law Exponential (Ilk plus Blasingame, Texas A&M), Multi-segment Arps with regime-switching b-factor.

Tier 3 (Phase I) DCA in data room

Field-level type-curves with Arps b-factor plus Di plus EUR; methodology disclosed; rate-time and log-log plots; IP30 / IP90 / IP180 statistics.

Tier 4 (Phase II) DCA

Six load-bearing artifacts.

1. Well-by-well DCA fits with explicit Arps plus modified-hyperbolic plus Duong parameters.
2. Type-well models for PUD locations with explicit Arps plus modified-hyperbolic plus Duong parameters at each PUD location.
3. AFE-to-actual production reconciliation across the last 3 to 5 years drilled wells — the single most important credibility test, exposing operator forecasting accuracy AND specific well-by-well economic outcomes.
4. EUR per well with confidence intervals at P10/P50/P90.
5. Visualization — rate-time, log-log, type-curve fans P10/P50/P90, cumulative-production plots.
6. Reservoir simulation model in Eclipse / Petrel RE / CMG (5 to 20 GB per asset) — executable.

The AFE-to-actual reconciliation is the single most leak-sensitive DCA artifact. It exposes operator forecasting accuracy AND specific well-by-well economic outcomes — both of which are economic-fact and high-confidence. Tier 4 only, with dynamic watermarks plus screenshot protection. See the oil and gas data room checklist for the full 12-folder mapping including the reserves and engineering folder.

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How big is a typical upstream divestiture data room at Phase II, and which platforms handle 200GB+ shale archives?

A typical upstream divestiture data room at Phase II is 80 to 200 GB for mid-cap; multi-county shale (Haynesville, Permian, Eagle Ford) or multi-asset packages routinely hit 300+ GB. The Mitsubishi-Aethon Haynesville reference scale — approximately 3,500 wells across 22 Texas and Louisiana counties per Shale Experts — illustrates the upper end where the LAS archive alone could exceed 100 GB and the pre-stack 3D SEG-Y archive could hit several TB across multiple wide-azimuth surveys per SEG Wiki Open Data and SEG-Y Rev 2.0 specification (March 2017). The structural composition: full pre-stack 3D SEG-Y cubes 50 to 200 GB per survey (sometimes 1+ TB ultra-deep or deep-water); full LAS archive 10 to 50 GB on mid-cap and 100+ GB on multi-county Haynesville; reservoir simulation models 5 to 20 GB per asset; full SPE-PRMS audit backup with workpapers and auditor's site-visit notes; well-by-well type-curves with full Arps plus Duong plus modified-hyperbolic fits; AFE-to-actual production reconciliation across 3 to 5 years; PSA drafts plus disclosure schedules.

Platforms that handle 200 GB+ Phase II archives without splitting and at sustainable cost across the 12-month lifecycle are narrow.

• Peony Data Room at $52/admin/month. No per-file cap (chunked parallel transfers with global CDN). Unlimited storage. Ships NDA gates, dynamic watermarks, screenshot protection, visitor groups, page-level analytics on the same room. For 5 admins on a 12-month divestiture cycle, that is $3,120 per year flat.
• Datasite Diligence. 10 GB single-file cap with zip files supported up to 50 GB per Datasite FAQ — requires splitting on full pre-stack volumes. Bills $0.40 to $1.00 per page (Capterra-aggregated buyer data, 2026; G2; Vendr; Papermark). On a 100 to 200 GB Phase II archive rendering at 100,000+ pages per zip, $25,000 to $80,000+ per deal per the same buyer data; six-figure invoices on multi-year lifecycle.
• Intralinks VDRPro at enterprise tier. 25 GB single-file cap raised from 15 GB across US, Germany, and Australia per Intralinks release notes — workable for individual reservoir reports but breaks on full pre-stack volumes. Custom-quoted pricing typically $25,000 to $80,000 per deal at enterprise tier.
• Box Enterprise Advanced. Supports 500 GB single-file uploads (largest in market) but ships zero NDA gates, dynamic watermarks, or screenshot protection — fails the 4-tier reserves disclosure tiering test outright.
• Firmex. 10 GB drag-and-drop cap (Firmex documentation) — fine for paper-heavy CIMs but corrupts SEG-Y header continuity when split.

Cost wedge math at Phase II scale. For 5 admins on a 12-month divestiture cycle handling a 100 to 200 GB Phase II archive: Peony Data Room runs $3,120 per year flat (5 admins x $52 x 12 months). Datasite enterprise typically lands $25,000 to $80,000+ per deal at $0.40 to $1.00 per page rendered across the archive (Capterra/G2/Vendr/Papermark, 2026). The 8x to 25x cost gap on data-heavy Phase II workflows is structural, not promotional — Datasite per-page billing punishes the 200 GB SEG-Y mass disproportionately because SEG-Y cubes render to tens of thousands of pages on the per-page invoice. For smaller admin teams running a single sell-side mandate, Peony Business at $30/admin/month ships the screenshot stack with a 1,000-document and 3-room cap — a fit for sell-side advisor teams of 2 to 3 admins, with dynamic watermarking on the Data Room plan ($52/admin/month). For the full Phase II lender-plus-counsel syndicate at 5 to 8 admins on a 12-month lifecycle, Peony Data Room at $52/admin/month is the right tier. See the horizontal sibling large-file data room with NDA gates for the file-mass mechanics across mining, biotech, AEC, and oil-gas.

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What does Peony do that legacy upstream divestiture VDRs don't on 4-tier reserves disclosure tiering?

Peony Data Room at $52/admin/month handles upstream divestiture data rooms — 80 to 200 GB at Phase II, 300+ GB at multi-county shale or multi-asset scale, across a 12-month lifecycle from teaser through closing through 12 to 24 month post-closing dispute resolution — at a cost structure that decouples from data volume and counterparty count, while preserving the security primitives that gate Tier 4 reserves disclosure (PDP curves, AFE-to-actual reconciliation, full pre-stack SEG-Y, full LAS, reservoir simulation). Run the seller's data room platform diagnostic test against Peony and the three answers — no per-file cap, programmatic permission groups expressing every row of the 4-tier reserves disclosure progressive-tiering matrix, flat per-admin pricing with no per-page or per-project meter — pass cleanly. The structural cost wedge against Datasite per-page billing is 8x to 25x on data-heavy Phase II workflows. Midstream M&A diligence reuses the same diagnostic — extended to 8 questions covering ROW archive, FERC Tier A-E document escalation, and PHMSA Mega Rule Phase 2 exhibits — see the midstream pipeline acquisition data room playbook for the parallel test on midstream platforms.

Five capabilities that matter for upstream divestiture work.

1. No per-file cap. A 100 to 200 GB pre-stack 3D SEG-Y cube uploads in a single chunked transfer with the audit trail preserved. Datasite caps single files at 10 GB with zip files supported up to 50 GB; Intralinks caps single files at 25 GB across US, Germany, and Australia; Firmex caps drag-and-drop at 10 GB. Box Enterprise Advanced supports 500 GB single-file uploads but ships zero NDA gates, dynamic watermarks, or screenshot protection — fails the basic 4-tier reserves disclosure tiering test.

2. NDA gates with integrated e-signatures. Each Tier 1 (teaser), Tier 2 (CIM), Tier 3 (Phase I), and Tier 4 (Phase II) recipient signs the seller's NDA template inline before any reserves data is visible. Signature record exportable as PDF audit trail satisfying SEC plus NI 51-101 plus PSA disclosure-liability documentation.

3. Dynamic watermarks tagging every page with viewer name, email, IP, and timestamp — across PDP curves, AFE-to-actual reconciliation, full LAS, full pre-stack SEG-Y, NSAI / D&M / Ryder Scott / Sproule / GLJ workpapers, NI 51-101 Form 51-101F1 backup, and SEC Form 10-K reserves disclosure.

4. Screenshot protection on desktop and mobile — non-negotiable for reserves engineers reviewing SPE-PRMS 2P certifications, lender counsel evaluating PV-10 reconciliations under SEC reserves disclosure rules, and short-list bidder counsel inspecting the AFE-to-actual reconciliation that exposes operator forecasting accuracy.

5. Programmatic visitor groups expressing the 4-tier reserves disclosure progressive-tiering matrix without manual permission resets across the 12-month divestiture lifecycle plus 12 to 24 month post-closing dispute resolution period. Page-level analytics preserve per-page dwell time, per-document NDA signature record, watermark version log, and screenshot block attempts — the audit trail short-list bidders' counsel and Mitsubishi-style strategic credit committees expect.

Trade-offs to be honest about. Peony does not ship a dedicated FERC docket cross-reference workflow (FERC docket lookup runs through standard search rather than a dedicated integration); Datasite remains the de-facto procurement standard at certain mega-cap upstream M&A groups where buyer-side procurement expects a Datasite-branded room (the Diamondback-Endeavor scale-of-deal reference); Intralinks ships pre-built farm-out workflow templates at enterprise tier with SS&C Technologies' pedigree on $35T+ in transactions processed. Where those defaults are hard requirements, the legacy choice still applies. Where the data room is selected by the seller's corp-dev or sell-side advisor rather than dictated by buyer-side procurement, Peony becomes structurally compelling across the 12-month lifecycle — for a 5-admin sell-side team that is $3,120 per year flat versus $25,000 to $80,000+ per deal on enterprise per-project pricing.

Cluster anchors for further reading: the 10 best data rooms for oil and gas companies (2026); the 42-document oil and gas data room checklist; the 7-step farm-out workflow plus 4-tier access model; the LNG project finance data room FEED to FID escalation curve; the midstream pipeline acquisition data room playbook with ROW Assignment Integrity Test and FERC Tier A-E document escalation; the large-file data room with NDA gates; and /solutions/energy.

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Frequently asked questions

I'm head of corp-dev at a US shale operator running a non-core Permian or Eagle Ford divestiture — what's the typical 12-month upstream divestiture timeline from teaser through deed of assignment, and where does most of the time actually get spent?

For your head-of-corp-dev role at a US shale operator running a non-core Permian or Eagle Ford divestiture, the typical 12-month upstream divestiture timeline runs eight named phases from teaser through deed of assignment. Phase 1 pre-marketing prep (months -6 to 0) covers internal data inventory, sell-side advisor engagement (Stephens, Houlihan Lokey, Detring, RBC, Jefferies, TPH Tudor Pickering, Mercer Capital, EnergyNet, or Oil and Gas Asset Clearinghouse), Tier 1 reserves auditor engagement, and tax structuring. Phase 2 teaser distribution (month 0 to 1, four weeks) circulates a 4 to 10 page non-confidential teaser to 30 to 80 firms with 15 to 40 NDA signers. Phase 3 CIM phase (month 1 to 2, four weeks) ships the 50 to 120 page CIM to NDA-signed parties. Phase 4 Phase I data room release (month 2 to 4, six to eight weeks) opens to 8 to 15 self-selected NDA-signed parties for indicative non-binding offer. Phase 5 Phase II data room release (month 4 to 7, ten to fourteen weeks) opens to a 3 to 6 bidder short-list with full pre-stack 3D SEG-Y, full LAS, reservoir simulation, and well-by-well type-curves. Phase 6 final bid plus PSA negotiation (month 7 to 9, six to ten weeks) lands binding offers and marks up the PSA. Phase 7 conditions precedent satisfaction (month 9 to 11) runs HSR antitrust at the current $133.9M 2026 threshold (effective February 17, 2026 per FTC, up from $126.4M in 2025; FTC indexed annually), BLM transfer via Form 3000-3 for federal lands, JOA partner pre-emption-rights waiver under AAPL Form 610-1989's 30-day window or international JOA's 30-to-60 day window, title and environmental defect cure, and decommissioning security adequacy. Phase 8 closing (month 11 to 12) executes the deed of assignment with cash and closing payments wired and effective-date-to-closing-date adjustments settling within 60 to 180 days post-close. Most of the time gets spent in two phases — Phase 5 Phase II (ten to fourteen weeks of bidder due diligence on the 80 to 200 GB short-list archive) and Phase 7 CP satisfaction (60 to 180 days for international or PSC fiscal regimes; 30 to 90 days for US domestic). Peony Data Room at $52/admin/month handles the lifecycle workflow without re-onboarding access tiers from teaser through deed of assignment — see the oil and gas data room cluster anchor for the full platform comparison.

I'm an MD at a Houston upstream M&A boutique running a sell-side mandate at a 5,000-well Haynesville-scale package — at which phase do I gate Phase II reservoir simulation models + LAS + pre-stack SEG-Y from the indicative-bid-only counterparties?

For your MD role at a Houston upstream M&A boutique on a 5,000-well Haynesville-scale sell-side mandate, you gate Phase II reservoir simulation models, full LAS archive, and full pre-stack 3D SEG-Y at the Phase 4-to-Phase 5 transition — the move from Phase I (8 to 15 self-selected NDA-signed parties for indicative non-binding offer) to Phase II (3 to 6 bidder short-list). That is the seismic-data NDA pattern. Phase I (Tier 3 disclosure) gives indicative bidders the full third-party reserves audit at category level (PDP / PDNP / PUD / PROBABLE / POSSIBLE) under SPE-PRMS 2018 v1.03 (published November 2022), PV-10 reconciliation at SEC 12-month average price, three to five years of monthly production history, opex and capex actuals versus budget, AFE archive summary, post-stack seismic crops with LAS subsets, and field-level type-curves at P10/P50/P90 normalized using Arps decline plus modified-hyperbolic-to-terminal-exponential. Phase II (Tier 4 disclosure) is where the well-by-well precision opens up to short-list only — full reservoir simulation model in Eclipse, Petrel RE, or CMG (typically 5 to 20 GB per asset), full LAS archive (10 to 50 GB; an Aethon-scale Haynesville at approximately 3,500 wells per Shale Experts could exceed 100 GB), full pre-stack 3D SEG-Y cubes (50 to 200 GB per survey, sometimes 1+ TB ultra-deep or deep-water per SEG Wiki Open Data and SEG-Y Rev 2.0 March 2017), well-by-well type-curves with full Arps plus Duong plus modified-hyperbolic fits, and AFE-to-actual production reconciliation across the last three to five years. The Mitsubishi-Aethon Haynesville reference scale — $5.2B equity / approximately $7.5B EV including $2.33B Aethon debt assumption per Mitsubishi press release January 16, 2026, with closing in Q1 Japanese FY2026 (April to June 2026) and Aethon Energy Management retaining a buy-back right up to 25 percent post-close — illustrates the data-room mass: 80 to 200 GB Phase II archive can hit 300+ GB for multi-county shale or multi-asset packages. Peony Data Room at $52/admin/month ships unlimited storage with no per-file cap and programmatic visitor groups so each Phase II bidder sees their own watermarked SEG-Y but never the runner-up bidder's documents and folders — versus Datasite per-page billing where a 100 GB pre-stack cube rendering at 30,000-100,000 pages plus per-page rates of $0.60 to $1.00 generates six-figure invoices on the bid-evaluation cycle alone (Capterra-aggregated buyer data, 2026; G2; Vendr; Papermark).

I'm a principal at energy PE running 6 buy-side mandates — when in the divestiture timeline can I expect to see well-by-well type-curves with full Arps + Duong fits and AFE-to-actual reconciliation, and what's the real Tier 4 disclosure depth at Phase II vs aggregate at Phase I?

For your principal role at energy PE running six buy-side mandates, well-by-well type-curves with full Arps plus modified-hyperbolic-to-terminal-exponential plus Duong fits and AFE-to-actual production reconciliation only open up at Phase II — and only to confirmed short-list bidders (typically 3 to 6 names after Phase I). Phase I (Tier 3 disclosure) gives you field-level type-curves at P10 / P50 / P90 normalized with Arps b-factor plus Di plus EUR, methodology disclosed, rate-time and log-log plots, and IP30 / IP90 / IP180 statistics. The aggregate-versus-precision distinction is the diagnostic: at Phase I you see basin-level economics and methodology; at Phase II you see well-level economics and the operator's forecasting accuracy. Tier 4 Phase II disclosure depth covers six load-bearing artifacts. First, well-by-well DCA fits with explicit Arps b-factor, Di, and terminal exponential transition point (the modified-hyperbolic shift from hyperbolic to terminal exponential typically triggers when monthly decline falls to 0.8 percent / 10 percent annual — preventing physically-implausible long-tail b-factors that overstate EUR). Second, type-well models for each PUD location with full Duong-method fits where Arps b-factors blow out above 1.5 (Haynesville and Marcellus unconventional). Third, AFE-to-actual production reconciliation across the last three to five years drilled wells — the single most important credibility test, exposing operator forecasting accuracy and well-by-well economic outcomes. Fourth, EUR per well with confidence intervals. Fifth, type-curve fans visualized P10/P50/P90 with rate-time, log-log, and cumulative-production plots. Sixth, full Arps decline 1944 foundational fits — exponential at b=0 boundary-dominated, hyperbolic at 0 less than b less than 1 transient, harmonic at b=1 limited reservoir. The AFE-to-actual reconciliation is one of the most leak-sensitive documents in the whole archive — exposes the seller's forecasting credibility and specific well-by-well outcomes. Peony Business at $30/admin/month ships screenshot protection, with dynamic watermarks on the Data Room plan ($52/admin/month) so even the AFE-actual reconciliation page-by-page sits behind viewer-name watermarking and screenshot-block on desktop and mobile — see the oil and gas data room checklist for the underlying 12-folder mapping.

I'm watching the Mitsubishi-Aethon Haynesville $5.2B equity / ~$7.5B EV deal close Q1 Japanese FY2026 — what does a ~3,500-well multi-county shale data room look like in GB at Phase II, and how does the seller wall well-by-well PDP curves until short-list?

For your role watching the Mitsubishi-Aethon Haynesville deal close in Q1 Japanese FY2026 (April to June 2026), an approximately 3,500-well multi-county shale data room at Phase II runs 100 to 300+ GB and walls well-by-well PDP curves until short-list through the 4-tier reserves disclosure progressive-tiering matrix. The Mitsubishi acquisition structure per Mitsubishi press release January 16, 2026, World Oil, CNBC, and Natural Gas Intel: $5.2 billion equity acquisition of Aethon's natural gas assets at approximately $7.5B enterprise value including $2.33B in Aethon debt assumption; sellers are Aethon Energy Management LLC alongside existing minority stakeholders Ontario Teachers' Pension Plan and RedBird Capital Partners; the asset is approximately 3,500+ wells across 22 Texas and Louisiana counties producing approximately 2.1 Bcf/d natural gas (approximately 15 MTPA LNG equivalent); Aethon Energy Management retains a buy-back right up to 25 percent post-close. Data room mass at Phase II decomposes as follows: full pre-stack 3D SEG-Y cubes 50 to 200 GB per survey across multi-county Haynesville plus Bossier shale (sometimes 1+ TB on ultra-deep surveys per SEG Wiki Open Data and SEG-Y Rev 2.0 specification March 2017); full LAS archive 100+ GB at 3,500-well scale (typical mid-cap is 10 to 50 GB; multi-county Haynesville stretches the envelope); reservoir simulation models in Eclipse, Petrel RE, or CMG 5 to 20 GB per asset; full SPE-PRMS 2018 v1.03 audit backup with workpapers and auditor's site-visit notes; well-by-well type-curves with Arps plus Duong (Haynesville unconventional triggers Duong because Arps b-factors blow out above 1.5 per whitson+ and PetroleumOffice); AFE-to-actual production reconciliation across the last three to five years drilled wells. Walling well-by-well PDP curves until short-list works through 4-tier progressive-tiering: Tier 1 (Teaser) sees aggregate 1P only, basin-level, headline production rate; Tier 2 (CIM) sees SPE-PRMS 1P/2P/3P summary plus PDP/PDNP/PUD sub-classification summary plus single-line PV-10 at SEC 12-month average price; Tier 3 (Phase I, NDA-gated to 8 to 15 indicative bidders) sees full PDP/PDNP/PUD/PROBABLE/POSSIBLE category-level audit plus PV-10 reconciliation at category level plus field-level type-curves; Tier 4 (Phase II, 3 to 6 short-list) sees well-by-well PDP curves, full Eclipse / Petrel RE / CMG executable, full Arps plus Duong fits, AFE-to-actual reconciliation. PDP curves are the single most leak-sensitive document — economic-fact, high-confidence, and once leaked give competitors a real-time view of seller's well economics. Peony Business at $30/admin/month ships page-level analytics tracking per-page dwell time and screenshot block attempts — exactly the audit trail short-list bidders' counsel and Mitsubishi-style strategic credit committees expect.

I'm IR at a Canadian dual-listed E&P running a Deep Basin Alberta divestiture — how does the data room handle NI 51-101 Form 51-101F1 disclosure, COGEH compliance, and the typical Sproule + GLJ + McDaniel forecast-price blend at Phase I vs Phase II?

For your IR role at a Canadian dual-listed E&P running a Deep Basin Alberta divestiture, the data room handles NI 51-101 Form 51-101F1 disclosure plus COGEH compliance through tier-progressive disclosure that mirrors the SEC 4-tier matrix while substituting Canadian methodology. NI 51-101 (National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, administered by the Canadian Securities Administrators) requires forecast pricing rather than the SEC's 12-month unweighted arithmetic average of first-day-of-month commodity prices. The forecast price typically blends the published price decks from GLJ Petroleum Consultants (Calgary, founded 1972; specializes in heavy oil and oil sands SAGD/CSS; evaluates reserves at all four producing oil sands mining operations), Sproule / Sproule ERCE (Calgary, founded 1953, merged with ERCE; offices in Calgary, Denver, Bakersfield, Mexico City, The Hague), and McDaniel — typically the average of those three published forecasts. NI 51-101 forecast pricing often produces higher reported reserves versus SEC equivalent because forecast prices typically exceed historical 12-month averages. NI 51-101 also explicitly recognizes Probable plus Possible at category level (the SEC has allowed Probable plus Possible reporting since January 2010 under the 2008 Modernization). COGEH (Canadian Oil and Gas Evaluation Handbook) is the methodology bible for NI 51-101 — what the SEC equivalent is to SPE-PRMS 2018 v1.03 (published November 2022 jointly maintained by SPE/WPC/AAPG/SPEE/SEG). Tier expression for the Deep Basin divestiture: Tier 1 (Teaser) aggregate 1P only; Tier 2 (CIM) NI 51-101 Form 51-101F1 summary plus 1P/2P/3P; Tier 3 (Phase I) full Form 51-101F1 with full COGEH-compliant category-level reserves; Tier 4 (Phase II) full Form 51-101F1 backup workpapers plus auditor's reports plus reservoir simulation. The Cenovus consideration of Deep Basin Alberta divestiture (announced January 2026, early stage, estimated approximately C$3B / approximately US$2.17B per BNN Bloomberg and trade press; Cenovus net debt jumped to approximately C$10.7B post the November 2025 MEG Energy acquisition close at C$8.5B with target reduction of C$4B over time) is the public-market reference for this archetype. Peony Data Room at $52/admin/month ships NDA gates with integrated e-signatures so each bidder type signs the seller's NDA template before any 51-101 backup is visible — Datasite and Intralinks support equivalent gating at $25,000 to $80,000 per deal enterprise tier (per Capterra/G2/Vendr/Papermark), but per-page billing punishes the COGEH workpaper mass disproportionately.

I'm an NSAI / D&M / Ryder Scott engagement partner getting a Phase II workpaper request from a Tier 1 IOC bidder — what does the seller's data room platform need to support our PDF audit + workpaper appendix delivery, and how do we confirm the bidder can't extract our well-level workpapers via screenshot?

For your engagement partner role at NSAI (Netherland, Sewell & Associates, Dallas, founded 1961; covers US shale across Permian, Eagle Ford, Haynesville, Bakken, Marcellus; SEC Form 10-K plus SPE-PRMS engagements with field site inspections), DeGolyer & MacNaughton (Dallas, founded 1936; global including sovereign-scale; audited Saudi Aramco reserves; SEC plus SPE-PRMS plus FMV studies), or Ryder Scott (Houston, founded 1937; deep-water and unitized fields; SPE Standards plus SEC), the seller's data room platform needs to support five workpaper-delivery requirements at Phase II. First, no per-file cap on PDF audit reports plus workpaper appendix bundles — typical full SPE-PRMS audit backup with workpapers, methodology, decline-curve fits, type-curve documentation, and auditor's site-visit notes runs 5 to 20 GB on mid-cap and 50+ GB on multi-county shale; legacy VDRs cap individual files at 10 GB (Datasite, Firmex), 25 GB (Intralinks across US/Germany/Australia per Intralinks release notes), or zip files up to 50 GB (Datasite FAQ) — both force splits that corrupt PDF bookmark continuity. Second, programmatic permission groups expressing the 4-tier reserves disclosure progressive-tiering matrix so Tier 4 IOC bidder views your full workpaper appendix while Tier 3 indicative bidders see only category-level audit summary. Third, dynamic watermarks tagging every workpaper page with viewer name, email, IP, and timestamp — required by reserves engineers reviewing Form 51-101F1 backup and lender counsel evaluating PV-10 reconciliations. Fourth, screenshot protection on desktop and mobile — non-negotiable for the well-level workpaper extraction risk you are flagging; PDP curves are the single most leak-sensitive document in the entire upstream divestiture archive because they are economic-fact and high-confidence, and once leaked give competitors a real-time view of seller's well economics. Fifth, a per-page audit trail exportable as PDF that satisfies the seller's downstream disclosure-liability documentation. Confirming the bidder cannot extract workpapers via screenshot: Peony's screenshot protection blocks system-level screenshot capture on desktop (macOS, Windows, Linux) and mobile (iOS, Android), with a page-level analytics log of every block attempt indexed by viewer and timestamp. Datasite and Intralinks ship equivalent screenshot blocking at enterprise tier; Drooms NXG ships GDPR-native watermarking strong on European E&P transactions. Box Enterprise Advanced supports 500 GB single-file uploads (largest in market) but ships zero NDA gates, dynamic watermarks, or screenshot protection — fails the well-level workpaper extraction test outright. Peony Data Room at $52/admin/month delivers the same NDA plus watermark plus screenshot stack at flat per-admin pricing — for a Sproule (Calgary; merged with ERCE) or GLJ engagement team of 4 admins on a 12-month divestiture cycle, that is approximately $2,496 total versus $25,000 to $80,000 on Datasite or Intralinks at enterprise tier per deal.

I'm running a sell-side US shale divestiture and the buyer's HSR clearance + RBL borrowing-base redetermination is dragging — how do I keep the data room live during the 60-90 day CP period without re-onboarding access tiers?

For your sell-side US shale divestiture where the buyer's HSR clearance plus RBL borrowing-base redetermination is dragging, you keep the data room live during the 60 to 90 day CP period by transitioning the room from transactional artifact to lifecycle data room with the same 4-tier reserves disclosure progressive-tiering matrix intact. The Phase 7 CP stack typically runs 60 to 180 days for international or PSC fiscal regimes and 30 to 90 days for US domestic. HSR antitrust clearance at the current $133.9M 2026 threshold (effective February 17, 2026 per FTC, up from $126.4M in 2025; FTC indexed annually) is the primary driver in US shale; the RBL borrowing-base redetermination on the buyer's side adds 30 to 60 days because the lender re-runs reserves audit, PV-10 sensitivity, and price-deck modeling on the combined post-acquisition position. Documents added during the CP-satisfaction tail: HSR filings and clearance letter, RBL lender consent letter, buyer's pre-acquisition RBL borrowing-base re-determination workpapers (NSAI, D&M, Ryder Scott, or Sproule depending on basin), JOA partner pre-emption-rights waiver under AAPL Form 610-1989's 30-day window, title and environmental defect cure documentation, decommissioning security adequacy re-validation (BLM federal lands via Form 3000-3, BSEE for US offshore, AER Alberta for Canadian, NSTA for UKCS), OFAC sanctions clearance (post-2022 critical), and seller-buyer effective-date adjustment workpapers. The Baytex Eagle Ford reference scale — US$2.305B cash divestiture of Baytex's entire US business with HSR antitrust clearance as the primary CP, US$200M deposit at signing, Q3/2025 production 82,765 boe/d, proved plus probable reserves of 401 MMboe at 12/31/2024 per Baytex IR November 12, 2025 and BOE Report — illustrates the tail mechanics. Peony Data Room at $52/admin/month handles the per-deal lifecycle without per-page billing exploding — flat per-admin pricing means the cost stays at $260 per month for 5 admins whether the room runs 90 days or 14 months, the Q&A log is preserved indexed by document and topic, and the 4-tier access model carries forward without re-onboarding. Datasite and Intralinks both support lifecycle-room functionality at enterprise tier but bill per-project or per-year subscription that scales with the CP tail — for a 14-month divestiture cycle with 5 admins on the buyer-side RBL counsel, that is $25,000+ on Datasite versus $3,640 on Peony. The Ovintiv-to-Stone Ridge Energy (Flywheel-operated) Anadarko Basin divestiture announced February 17, 2026 and closed April 9, 2026 ($3B cash, approximately 360,000 net acres, approximately 90,000 boe/d split 27 Mbbl/d oil + 240 MMcf/d gas + 23 Mbbl/d NGL, effective date January 1, 2026, per Ovintiv IR) is the cross-basin portfolio rationalization parallel.

I'm watching the Baytex US Eagle Ford $2.305B divestiture close late 2025 / early 2026 with HSR as primary CP and 401 MMboe 2P reserves at YE 2024 — how does a 'whole US business' divestiture data room differ from a single-asset divestiture in structure?

For your role watching the Baytex US Eagle Ford $2.305B divestiture close late 2025 or early 2026, a 'whole US business' divestiture data room differs from a single-asset divestiture in five concrete categories that compound the document mass and counterparty count. The Baytex US business divestiture per Baytex IR November 12, 2025, BOE Report, and trade press: US$2.305 billion cash consideration (not $3.25B as some BNN headlines suggested), US$200M deposit from buyer at signing, asset is all of Baytex's US business, proved plus probable reserves of 401 MMboe at 12/31/2024, Q3/2025 production 82,765 boe/d (52,330 bbl/d light oil and condensate plus 15,582 bbl/d NGL plus 89,115 Mcf/d gas), HSR antitrust clearance required as primary CP, expected close late 2025 or early 2026. Five structural differences. First, asset-package consolidation — a whole-US-business divestiture aggregates multiple sub-basin packages (Eagle Ford core plus extension acreage plus midstream gathering rights plus saltwater disposal infrastructure) where a single-asset divestiture is just one package; the data room must wall the sub-package rollups so a bidder evaluating Eagle Ford only does not see midstream gathering economics. Second, multiple-reserves-auditor reports — at whole-business scale typically NSAI plus D&M plus Ryder Scott deliver overlapping audits across the sub-basins; the data room indexes by basin and by auditor for cross-validation. Third, JOA carry-forward audit — across multi-year operating history every AFE, every non-consent election, and every sole-risk operation across hundreds of wells gates to T2 (IOC bidder) at AFE-and-work-program level. Fourth, the HSR threshold ($133.9M for 2026 effective February 17, 2026 per FTC, up from $126.4M in 2025; indexed annually) bites hard on whole-business deals because the combined post-acquisition position triggers full antitrust review and RBL borrowing-base redetermination on the buyer's side. Fifth, effective-date-to-closing-date adjustments at whole-business scale typically run 60 to 180 days post-close for working capital, AFE settlement, and price-deck reconciliation. The Diamondback-Endeavor Permian merger (closed September 10, 2024 per Diamondback IR; approximately $26B inclusive of net debt; approximately 117.3M Diamondback shares plus $8B cash; Endeavor footprint approximately 350,000 net acres in Midland Permian; combined production 816,000 boe/d; Diamondback proved reserves 12/31/2024 approximately 50% oil / 23% gas / 27% NGL; $550M annual synergies; over $3B net value over 10 years) is the mega-cap institutional-grade reference for this archetype. Peony Data Room at $52/admin/month handles whole-business and single-asset divestitures equally through unlimited storage with no per-file cap and programmatic visitor groups walling sub-package rollups — see /solutions/energy for the upstream-divestiture-specific use cases.

I'm a credit officer at an RBL bank reviewing a buyer's pre-acquisition RBL borrowing-base redetermination — what reserves disclosure depth do I get from the data room as a Tier 4 short-list lender vs Tier 3 Phase I, and how does the Sproule / GLJ forecast-pricing reserves report differ from the SEC PV-10?

For your credit officer role at an RBL bank reviewing a buyer's pre-acquisition RBL borrowing-base redetermination, Tier 4 short-list lender access opens up six load-bearing artifacts you do not see at Tier 3 Phase I. Tier 3 Phase I (8 to 15 indicative bidders) gives you full SPE-PRMS audit at category level (PDP / PDNP / PUD / PROBABLE / POSSIBLE), PV-10 reconciliation at SEC 12-month average price plus at strip pricing, three to five years of monthly production history, opex and capex actuals versus budget, post-stack seismic crops with LAS subsets, field-level type-curves at P10/P50/P90 normalized using Arps decline plus modified-hyperbolic-to-terminal-exponential, and AFE archive summary. Tier 4 Phase II (3 to 6 short-list including the buyer's RBL syndicate and lender's external counsel) opens up six additional artifacts. First, full Eclipse / Petrel RE / CMG executable reservoir simulation model. Second, well-by-well type-curves with full Arps plus modified-hyperbolic plus Duong fits and EUR per well with confidence intervals. Third, full pre-stack 3D SEG-Y cubes (50 to 200 GB per survey, sometimes 1+ TB ultra-deep). Fourth, full LAS archive (10 to 50 GB; 100+ GB for multi-county shale). Fifth, AFE-to-actual production reconciliation across the last three to five years drilled wells (the single most credibility-test document). Sixth, full SPE-PRMS audit backup with workpapers and auditor's site-visit notes. The Sproule (Calgary) / GLJ (Calgary) forecast-pricing NI 51-101 Form 51-101F1 reserves report differs from the SEC PV-10 in three load-bearing ways. First, price methodology — NI 51-101 uses forecast pricing (typically the average of GLJ + Sproule + McDaniel published price decks) while SEC PV-10 uses the 12-month unweighted arithmetic average of first-day-of-month commodity prices. Second, recognition scope — NI 51-101 explicitly recognizes Probable plus Possible at category level (the SEC has allowed Probable plus Possible since January 2010 under the 2008 Modernization but the historical bias is Proved-only). Third, methodology bible — NI 51-101 is governed by COGEH (Canadian Oil and Gas Evaluation Handbook) while SEC SPE-PRMS classification under SPE-PRMS 2018 v1.03 (published November 2022 jointly maintained by SPE/WPC/AAPG/SPEE/SEG) is the global standard with deterministic required for proved. Critical caveat for RBL borrowing-base modeling: PV-10 is not Fair Market Value per ValueScope. Bidders construct buyer-specific economic value using their cost of capital, price deck, risk adjustments, and sensitivity decks. Forecast-price NI 51-101 reserves often report higher than SEC equivalent because forecast prices typically exceed historical 12-month averages. Peony Data Room at $52/admin/month preserves the audit trail across the multi-month RBL redetermination cycle without per-project re-onboarding — see the oil and gas data room cluster anchor for the full platform comparison.

I'm IR at a UKCS late-life operator considering a divestiture under NSTA's £27B 2023-2032 decommissioning framework — how does the data room handle decommissioning security re-validation as a CP, and how do I structure seller-retained-decom-liability documentation per CMS UK guide?

For your IR role at a UKCS late-life operator considering a divestiture under NSTA's £27B 2023-2032 decommissioning framework, the data room handles decommissioning security re-validation as a CP through NSTA-specific T3 carve-outs alongside parallel disclosure to T2 (IOC bidder) and T4 (RBL lender) tiers, and you structure seller-retained-decom-liability documentation per CMS UK guide. NSTA UKCS Decommissioning Cost and Performance Update 2025 (published July 10, 2025) reported £2.4 billion record 2024 decommissioning spend with £27 billion estimated total 2023 to 2032 decommissioning spend across the UKCS — that is the public-market context anchoring late-life divestiture architecture. Per the CMS UK guide on UKCS asset transfers, sellers often retain decommissioning liability rather than transferring it cleanly to the buyer because of two structural reasons: (1) potential former-owner liability under the Petroleum Act 1998 Section 29 / Section 32 notice regime persists even after working-interest transfer if the buyer cannot perform decommissioning at end-of-life; and (2) UK tax-relief mechanics on decommissioning spend are most efficiently captured by the seller (the entity that historically booked depreciation against the assets). Decommissioning security re-validation as a CP works through five document categories. First, NSTA Section 29 / Section 32 notice histories under the Petroleum Act 1998 across the asset's full ownership history. Second, the seller's existing decommissioning trust fund coverage, parental guarantee, or letters of credit posting. Third, the buyer-side proposed re-validation pack — buyer's parental guarantee adequacy benchmarked against investment-grade rating and Net Decommissioning Cost estimate, buyer's letter-of-credit posting capacity, buyer's decommissioning trust fund contribution schedule. Fourth, OPRED PETS (Petroleum Environmental Tracking System) submissions, OPEP (Oil Pollution Emergency Plan), and PON1 (release reports). Fifth, the seller-retained-decommissioning side letter structuring residual liability per CMS UK guide. NSTA review for buyer-side re-validation typically runs 60 to 120 days for established mid-cap and major buyers; longer for first-time UKCS entrants where NSTA's diligence depth scales. Harbour Energy / Wintershall Dea (closed September 3, 2024 per Harbour IR; $11.2 billion across Norway, Argentina, Germany, Mexico, Algeria, Libya, Egypt, Denmark plus CCS licenses; December 2025 follow-on Harbour acquired Waldorf subsidiaries for approximately $170M increasing Catcher stake to 90 percent plus 29.5 percent non-operated Kraken) is the recent UKCS portfolio consolidation reference framing the late-life decommissioning context. Peony Data Room at $52/admin/month handles the per-deal lifecycle through flat per-admin pricing — see the oil and gas farm-out workflow playbook for the parallel 4-tier farm-out access model that anchors how documents move across tiers.

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Related resources

• 10 Best Data Rooms for Oil and Gas Companies (2026 Guide) — head-on platform comparison and the FID cliff frame
• Oil and Gas Data Room Checklist (2026): 42 Documents Across 12 Folders — the underlying document-mapping matrix
• Oil & Gas Farm-Out Data Room: 7-Step Workflow + 4-Tier Access (2026) — the workflow playbook and access-model deep dive
• LNG Project Finance Data Room: FEED→FID Escalation + ECA Debt Pack (2026) — the LNG project-finance deep dive
• Tested: 10 Data Rooms for Large Files (With NDA Gates) — file-mass mechanics across mining, biotech, AEC, and oil-gas
• Energy Data Room Solutions — upstream-divestiture-specific use cases
• Peony Pricing — Business at $30/admin/month, Data Room at $52/admin/month