Find the next opportunity in the basin.

Meridian is a basin-intelligence platform for Western Canadian oil and gas. It maps every well, play, and disclosed deal in the Western Canadian Sedimentary Basin — play-level breakevens, operator netbacks, M&A comps, and ownership lineage — and pairs each of the basin's 684,158 well sites with a satellite-verified recovery score and a dynamic asset-retirement-obligation (ARO) estimate, so acquisition, drilling, and lending decisions get made with the liability priced in.

Traditional platforms hand you layers — a production database, a land system, a filings archive — and leave the joining, the modeling, and the liability math to you. Meridian ships the finished decision surface: one reconciled per-well spine where play breakevens, operator netbacks, deal comps, ownership lineage, and a satellite-verified ARO already agree with each other. The liability number in particular is one no data terminal offers — it's measured from orbit, not taken from the seller's data room. The screening-and-underwriting loop that otherwise takes a data subscription, three spreadsheets, and weeks of analyst time runs in one screen, in hours.

Meridian screens the basin on the numbers that decide a deal: play-level breakevens repriced live against the commodity strip, the gap between an operator's reported netback and what the strip implies, comparable-transaction multiples from every disclosed WCSB deal, and an ARO-adjusted view of value. Because every lens reads from the same per-well data spine, a target that looks cheap on headline metrics but carries heavy closure liability shows up as exactly that.

An asset retirement obligation (ARO) is the estimated future cost to abandon a well, decommission its facilities, and reclaim the land back to a regulated standard. It has become a first-order input to acquisition pricing, borrowing bases, and regulatory transfer approvals — and historically one of the most disputed lines in a model. Meridian produces a per-site ARO estimate that updates as ground conditions and cost drivers change.

Meridian derives a 0–100 recovery score from 10-metre multispectral satellite imagery (Sentinel-2) using a documented, rules-based composite of vegetation, moisture, and bare-soil indices. The method is interpretable by design: every score traces back to an observation and a rule, so it can be defended in a diligence process or a redetermination and reconciled with a regulator's numbers — not a black-box machine-learning output.

Every ARO estimate is rules-based and fully documented: it starts from a satellite-derived recovery score, applies explicit cost drivers, and carries P10–P90 uncertainty bands rather than a false-precision point estimate. Each number traces to observations and rules a reviewer can inspect, and the framework is built to reconcile against the regulatory measures a deal actually turns on — Alberta's Directive 011 deemed liabilities and LMR among them. Our design-partner program is structured to tighten the cost bands against realized closure costs as the basin reports them.

Meridian classifies every disclosed WCSB A&D transaction — extracting $/boe/d, $/well, PV10 and reserves multiples from the source announcements and reconciling announced deals to actual licence transfers — and reads operator netbacks and financials directly from public SEDAR+ filings, joined to production data and the well registry.

Liability Management Rating (LMR) is a regulatory ratio comparing a licensee's deemed assets to its deemed liabilities; in Alberta it is administered by the regulator and can constrain licence transfers and trigger security demands — which makes it deal-relevant, not just compliance-relevant. Meridian tracks LMR and decommissioning-reserve positions so a constraint is visible before it stalls a close.

Each source updates automatically on its own clock: satellite imagery on a roughly 5-day revisit across the basin, newly issued well licences daily, the well registries and SEDAR+ filings weekly, and facility, liability-rating, and commodity-benchmark data monthly. Numbers on the platform carry their observation dates, so you always know what vintage you're underwriting on.

Yes. Screens, comps tables, netback series, and per-site ARO cost bands export in spreadsheet-ready formats, and diligence packs render to PDF. Meridian is built to feed your underwriting model, your IC memo, and your data room — not to trap your work inside a dashboard.

Client workspaces are strictly isolated. The areas of interest, portfolios, and screens you build are visible only to your organization — never shared with, or used to inform, any other client's view. Access is role-controlled, data is encrypted in transit, and the platform is hosted in Canada, so client data never leaves the country. The public-record data underneath Meridian is open to everyone; what you do with it stays yours.

Meridian is built for the desks that move capital in the basin: private-equity and corp-dev teams screening acquisitions, A&D and business-development groups at operators, reserve-based lenders monitoring borrowing bases and covenants, and the advisors and technical evaluators supporting them.

Meridian is priced as an annual subscription per organization, scoped to your team and mandate — there's no per-well, per-screen, or per-report metering, so your team can work the whole basin without watching a meter. We're currently onboarding a limited number of design partners on founding terms; request access and we'll share specifics in one short call.

Meridian covers Western Canada today — Alberta, British Columbia, Saskatchewan, and Manitoba — across more than 684,000 well sites, with expansion to additional North American energy basins planned.