Offshore Project Models

Technical Guide • Advanced • 2 min read

Audience: Energy Developers • EPC Contractors • Infrastructure Investors • Project Finance Lenders
Last Reviewed: July 2026
Updated: Version 1.0

Executive Summary

Offshore project models must account for the specific cost and risk drivers of developing hydrocarbons at sea, fixed platforms, floating production storage and offloading (FPSO) vessels, and subsea tiebacks, each with materially different capital cost and operating profiles, alongside weather-driven downtime and logistics costs that do not arise onshore. This guide sets out how offshore models are structured around these facility choices and risk factors.

Key Takeaways

✓ Offshore projects are typically developed using one of three facility types, fixed platforms, FPSO vessels, or subsea tiebacks to existing infrastructure, each with materially different capital cost and operating profiles that the model must reflect specifically.
✓ Weather-driven downtime, particularly in harsher offshore environments, should be modelled as an explicit availability reduction rather than assumed away, since it directly affects both production and the logistics schedule.
✓ Logistics costs, helicopter transport and supply vessels, are a distinct, material operating cost category in offshore models with no onshore equivalent.
✓ Offshore decommissioning cost is typically higher per unit of production than onshore, reflecting the cost of subsea infrastructure removal, and should be provisioned accordingly rather than using an onshore-based unit cost assumption.

Objective¶

This guide sets out how offshore oil and gas project models are structured, within Oil & Gas Financial Modelling.

Facility Type Choice¶

Offshore developments are typically structured around one of three facility types: a fixed platform, anchored to the seabed and generally suited to shallower water; a floating production storage and offloading (FPSO) vessel, which can be redeployed and is common in deeper water or remote locations; or a subsea tieback, connecting a subsea wellhead directly to existing nearby infrastructure without a new dedicated platform. Each carries a materially different capital cost and operating profile, and the model should reflect the specific facility type actually planned, addressed alongside the broader development planning covered in Field Development Financial Models.

Weather-Driven Downtime¶

Offshore production and logistics are exposed to weather conditions in a way onshore operations are not. The model should reflect an explicit availability reduction specific to the offshore environment's typical weather patterns, since weather affects both production uptime and the feasibility of scheduled personnel and supply transport, rather than assuming continuous availability or folding weather risk into a generic maintenance downtime allowance.

Logistics Costs¶

Helicopter transport for personnel and supply vessels for equipment and materials are a distinct, material operating cost category specific to offshore projects, with no direct onshore equivalent. These costs should be modelled explicitly rather than absorbed into a generic operating cost line, since they scale with distance from shore and can be a significant driver of an offshore asset's total operating cost.

Offshore Decommissioning¶

Offshore decommissioning, addressed further in Decommissioning Cost Models, typically carries a higher unit cost than onshore decommissioning, reflecting the complexity of removing subsea infrastructure and, where applicable, platform structures. The model's decommissioning provision should reflect this offshore-specific cost basis rather than an onshore-derived unit cost assumption.

Common Structuring Pitfalls¶

Applying a generic offshore cost assumption rather than reflecting the specific facility type, fixed platform, FPSO, or subsea tieback, actually planned.
Assuming continuous production availability without an explicit, environment-specific weather downtime allowance.
Folding helicopter and supply vessel logistics costs into a generic operating cost line rather than modelling them explicitly.
Using an onshore-based decommissioning unit cost for an offshore asset, understating the actual removal cost.

Continue Reading¶

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Frequently Asked Questions

What are the main offshore development facility types?

Fixed platforms (structures anchored to the seabed, generally used in shallower water), floating production storage and offloading (FPSO) vessels (which can be redeployed and are common in deeper water or remote locations), and subsea tiebacks (connecting a subsea wellhead directly to existing nearby infrastructure without a new dedicated platform).

How does facility type choice affect an offshore project model?

Each facility type carries a materially different capital cost and operating profile, a subsea tieback is typically the lowest capital cost option where suitable existing infrastructure exists nearby, while a new fixed platform or FPSO represents a larger, standalone capital commitment, so the model should reflect the specific facility type actually planned rather than a generic offshore cost assumption.

How should weather-driven downtime be modelled offshore?

As an explicit availability reduction reflecting the specific offshore environment's weather conditions, since weather affects both production uptime and the logistics schedule for personnel and supply transport, rather than being assumed away or represented only as a generic maintenance downtime figure.

What logistics costs are specific to offshore projects?

Helicopter transport for personnel and supply vessels for equipment and materials, a distinct, material operating cost category with no direct onshore equivalent, and one that should be modelled explicitly rather than folded into a generic operating cost line.

Why is offshore decommissioning typically more expensive than onshore?

Because it involves the removal of subsea infrastructure and, where applicable, platform structures, a materially more complex and costly undertaking than onshore well plugging and site restoration, and the model's decommissioning provision should reflect this higher offshore-specific unit cost rather than an onshore-based assumption.

References

Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers — Petroleum Resources Management System (PRMS 2018)

Oil & Gas Financial Modelling

Oil and gas financial modelling is the practice of building financial models across the four structurally distinct segments of the hydrocarbon value chain, upstream exploration and production, midstream transport and processing, downstream refining and petrochemicals, and LNG, each governed by different revenue mechanics, contract structures and risk drivers. This page is the hub for the Knowledge Centre's oil and gas financial modelling content: industry structure and segment definitions, the financial KPIs the sector is measured against, the investment lifecycle from exploration through decommissioning, and how this domain builds toward asset and project-level models, commercial and investment analysis, and governance and assurance practice as it expands.

Field Development Financial Models

Field development financial models translate a discovered, appraised field into a specific development plan: phased capital expenditure, first oil or first gas timing, plateau production rate, and the facility sizing and tie-back-versus-standalone decisions that shape the project's capital intensity. This guide sets out how a field development model is structured around these decisions and how it feeds into the Final Investment Decision that follows.

Onshore Project Models

Onshore project models are shaped by land access and surface rights, well pad-level economics across a typically larger well count than offshore developments, and the choice between pipeline and trucking takeaway for produced volumes ahead of pipeline connection. This guide sets out how onshore models are structured around these drivers, and how they differ from the facility-centric economics of offshore development.

Decommissioning Cost Models

Decommissioning cost models estimate and provision the mandatory end-of-life obligation to plug wells and remove oil and gas infrastructure, an obligation that should be funded progressively across the production life rather than treated as a single terminal-year cost. This guide sets out how decommissioning cost is estimated, the funding mechanisms, sinking funds, parent company guarantees, and letters of credit, regulators typically require, and why timing and discounting of the liability matter to how it is represented in a financial model.

What Is a Project Finance Model Audit?

A project finance model audit is a financial model audit applied to the specific class of model used to finance infrastructure, energy, and long dated capital projects: debt sculpted, multi decade, cash flow driven structures with mechanics that do not appear in a typical corporate model. It is frequently a formal condition of financial close, not an optional check, and lender requirements for it exist almost entirely inside non public bank credit policy rather than any single consolidated public source. This page defines what makes project finance models structurally distinct, why lenders require independent verification of them specifically, and what the audit process looks like in this context.