Offshore Energy Thematic Methods

This Circular provides methodological guidance for accounting for offshore energy activities within ocean accounts, extending TG-3.10 Offshore Energy Accounts with thematic methods for cumulative impacts, decommissioning, and energy transition.

1.1 Decision Use Cases and Policy Links

Offshore wind site selection and spatial planning. Marine spatial planning authorities require spatial footprint data, exclusion zone mapping, and ecosystem condition baselines to evaluate competing offshore wind proposals, feeding into TG-1.2 Marine Spatial Planning.

Oil and gas decommissioning accounting. Asset accounts for offshore energy infrastructure (Section 3.5.1) enable tracking of decommissioning liabilities. The rigs-to-reefs framework (Section 3.5.2) provides accounting treatment for partial decommissioning. Asset valuations also support TG-1.8 OA and Project-Level Finance.

Energy transition and climate policy. The energy transition accounting framework (Section 3.6) supports reporting on the shift from offshore oil and gas to marine renewables, including NDC progress and avoided-emissions tracking. Climate indicators feed into TG-2.8 Climate Indicators. Section 3.6.3 provides the accounting linkage.

Renewable energy target monitoring. Physical energy accounts (Section 3.2) record installed capacity and generation by technology type. These data support comparison against policy targets and link to TG-2.5 Ocean Economy Structure.

Asset accounts integration. Treatment of renewable energy resources and terminal costs for offshore infrastructure is governed by TG-3.1 Asset Accounts.

1.2 Emerging Methodological Issues

Methods for offshore renewable energy accounting and cumulative impact assessment are not yet standardised within the SEEA framework. Specific areas of emerging methodology are summarised below.

Reclassification to Applied may be considered once international guidance on these topics is formally adopted through the UN Statistical Commission process or the UNCEEA work programme. The spatial scope covers offshore energy activities within the Exclusive Economic Zone and on the continental shelf as defined by UNCLOS, including both fixed and floating installations. Activities within areas beyond national jurisdiction are addressed in TG-6.6 Deep Sea and Seabed Accounting. TG-6.11 Coastal Infrastructure addresses cable landfall infrastructure and onshore grid connections.

• SEEA Central Framework (2012) for mineral and energy resource treatment and decommissioning costs
• SEEA-Energy (2019), for physical and monetary supply and use tables and fossil fuel asset accounts
• 2025 SNA for renewable energy resource classification and terminal cost treatment
• UNCLOS (1982) for the offshore installation legal framework

Data quality should be assessed following TG-0.7 Quality Assurance, with particular attention to temporal consistency, spatial coverage, and measurement uncertainty.

Readiness and sequencing. Whether a country is positioned to compile this account at all — mandate, data architecture, capacity and the order in which to build — is assessed under TG-0.8 Implementation Readiness Assessment, and is not restated here.

3.1 Energy Type Classification

3.1.1 Fossil fuel extraction (oil and gas)

Offshore oil and gas platforms extract mineral and energy resources classified within ISIC Division 06 (Extraction of crude petroleum and natural gas). ISIC Division 06 does not distinguish onshore from offshore extraction at the four-digit level, so compilers should use location-based coding or national satellite industry codes where available. See TG-3.3 Economic Activity Relevant to the Ocean.

Physical asset accounts record stocks using the United Nations Framework Classification for Fossil Energy and Mineral Reserves and Resources (UNFC-2009):

Monetary asset accounts record the net present value of commercially recoverable resources, with revaluations reflecting changes in commodity prices, extraction costs, and discount rates. For foundational supply-use and asset-account structures, see TG-3.10 Offshore Energy Accounts.

Transboundary reservoirs. Where offshore reservoirs straddle maritime boundaries, the SEEA Central Framework requires that “only the country’s share of the resource should be recorded in its asset accounts” (SEEA CF para. 5.93). Share allocation rules:

• The primary basis is a unitisation agreement specifying production shares. Where one is in force, compilers should use its production share for national asset account entries.
• Where no unitisation agreement exists, use the most recent bilateral production data sharing arrangement, or IEA World Energy Balances as an interim basis.
• UNFC classification should be applied independently in each jurisdiction using that jurisdiction’s economic parameters. Where the sum of national reserves exceeds an independently assessed reservoir total, document this divergence in a cross-boundary consistency footnote.

Transboundary reservoir methodology has been flagged as a candidate issue for future UNSD guidance development.

3.1.2 Offshore wind energy

• Mineral and energy resources (offshore oil and gas) — Class A (commercially recoverable), Class B (potentially commercial), and Class C (non-commercial)
• Renewable energy resources (wind, wave, tidal) — classified separately from mineral resources following 2025 SNA treatment

Physical accounts record stocks in natural units (barrels, cubic metres, MW installed capacity, MWh generation). Monetary accounts record net present value of expected resource rents (for oil and gas) or income streams attributed to seabed assets (for renewable installations).

Step 3: Physical supply and use table compilation

Physical energy supply and use tables (PSUT) follow SEEA-Energy Chapter 3.

Supply table records: (1) production from offshore oil and gas fields (by spatial unit and field), (2) production from offshore renewable installations (by technology and location), and (3) imports of offshore-produced energy where relevant for transboundary accounting.

Use table records: (1) intermediate consumption within offshore operations (platform electricity, flaring losses), (2) exports of offshore-produced oil, gas, and electricity, and (3) final consumption of offshore renewable electricity by domestic users.

The balanced PSUT provides the foundation for deriving energy self-sufficiency indicators, emission intensity by fuel type, and renewable energy share indicators feeding into TG-2.8 Climate Indicators.

Step 4: Monetary supply and use table compilation

Monetary supply and use tables enable calculation of gross value added, compensation of employees, and gross operating surplus for offshore energy industries. These measures feed into TG-2.5 Ocean Economy Structure.

Key valuation considerations:

• Oil and gas production is valued at wellhead prices (excluding transport and processing margins)
• Offshore renewable electricity is valued at wholesale market prices or feed-in tariff rates
• Gross value added is calculated as output minus intermediate consumption
• For non-renewable resources, resource rent should be calculated separately from consumption of fixed capital on produced assets, using the net price or user cost method per SEEA-Energy Chapter 6. See Section 3.7 for a worked example.

Step 5: Asset account compilation

Asset accounts track opening stocks, additions, reductions, reappraisals, and closing stocks. For offshore oil and gas, depletion of the mineral resource is recorded separately from consumption of fixed capital on produced assets. Conflating the two is a methodological error that SEEA-Energy Chapter 6 explicitly cautions against. For offshore renewable resources, there is no depletion, and asset value derives from the stream of future income attributed to the seabed lease or licence.

Step 6: Integration with national accounts and balance sheets

Integration ensures that:

• Depletion entries in asset accounts correspond to depletion costs in production accounts and adjustments to net domestic product (see TG-1.1 National Ocean Budgets)
• Extraction entries correspond to natural resource inputs in physical supply-use tables
• Investment in offshore infrastructure is recorded as gross fixed capital formation in produced assets
• Environmental impact entries in ecosystem condition accounts are consistent with offshore energy spatial footprints

3.3 Spatial Footprint Accounting

Spatial accounts should record:

Direct footprint — The physical area occupied by: (1) platform jackets and foundations (oil/gas), (2) monopile, jacket, or floating foundations (wind), (3) anchoring systems and mooring lines, and (4) subsea infrastructure (wellheads, manifolds, templates).

Cable corridors — Export cables require seabed rights-of-way. UNCLOS Article 79 establishes that all States are entitled to lay submarine cables on the continental shelf, subject to coastal State jurisdiction over cables connected to installations. Cable landfall and onshore substation accounting are addressed in TG-6.11 Coastal Infrastructure.

3.3.2 Exclusion and safety zones

UNCLOS Article 60 permits coastal States to establish safety zones extending up to 500 metres from each point of the outer edge of offshore installations. These zones effectively exclude commercial fishing, navigation, anchoring, and other seabed development.

Spatial accounts should record both the statutory exclusion area (defined by regulatory designation) and the effective exclusion area (observed through AIS vessel tracking data showing actual avoidance patterns). For guidance on using AIS and satellite data to delineate effective exclusion zones, see TG-4.1 Remote Sensing Data.

Tier 1 fallback (no AIS processing capacity). Compilers may estimate the effective exclusion area by applying an empirical multiplier to the statutory 500 m safety zone area. The AIS-derived method remains preferred. Compilers must document in account metadata which method has been used and, where the multiplier is applied, the assumed value.

3.3.3 Integration with marine spatial planning

Offshore energy spatial data should be compiled as georeferenced polygon layers showing lease/licence boundaries, infrastructure locations, cable routes, safety/exclusion zones, and planned development areas, consistent with formats in TG-1.2 Marine Spatial Planning.

3.4 Environmental Impact Recording

The quantitative treatment below links physical impact measurements to the condition variables defined in SEEA Ecosystem Accounting, so cumulative impacts flow through to ecosystem condition assessments. For general ecosystem condition accounting methodology, see TG-3.1 Asset Accounts.

Table 3.2: Offshore energy environmental impact comparison

Offshore energy activities generate underwater noise during construction (pile driving), operation (machinery, vessel traffic), and decommissioning.

Source characterisation — Record noise source levels, frequencies, and temporal patterns by activity type and location as supplementary physical data tables linked to the relevant spatial unit and time period.

Receptor mapping — Identify noise-sensitive marine species, particularly marine mammals and fish. UNCLOS Article 65 requires States to cooperate for the conservation of marine mammals, with cetaceans receiving particular attention.

Impact pathways — Link noise exposure to ecological outcomes including behavioural disturbance, masking, temporary or permanent hearing threshold shifts, and physical injury. Document as condition indicators within ecosystem condition accounts.

Data sources. Use regulatory monitoring data (where available under national marine noise management frameworks) or published acoustic modelling results from environmental impact assessments. For European jurisdictions, EU Marine Strategy Framework Directive descriptor D11 (Commission Decision (EU) 2017/848) provides the regulatory baseline.

TNFD metrics for noise pollution are designed for corporate site-level disclosure and should not be aggregated directly across operators to derive national-level indicators, for three reasons:

• measurement methodologies are not standardised across companies
• “noisiest part of day” is a peak rather than period-average metric
• TNFD disclosures are voluntary and incomplete

3.4.2 Electromagnetic fields (EMF)

Subsea power cables generate electromagnetic fields that may affect electroreceptive marine species (sharks, rays, some crustaceans). Research remains limited. Current accounting practice should:

• Record cable specifications (voltage, current, burial depth, shielding) as supplementary physical data
• Map cable routes in relation to sensitive habitats using georeferenced data
• Monitor and report any observed behavioural effects as condition indicators where monitoring data are available

Substrate introduction — Hard structures create artificial reef habitat in otherwise soft-sediment environments. The IUCN Global Ecosystem Typology classifies “Submerged artificial structures” (M4.1) as a distinct ecosystem type. Compilers should record the introduction of hard substrate as a change in ecosystem type within extent accounts (from soft-sediment benthic to M4.1), whilst noting that the ecological value of artificial habitat may differ substantially from natural reef. For general guidance on ecosystem extent accounting, see TG-3.1 Asset Accounts. For coral reef regions, see TG-6.1 Coral Reef Accounts.

Sediment disturbance — Installation and cable burial activities disturb seabed sediments, potentially releasing contaminants and altering benthic communities. Record as condition changes in affected spatial units.

Hydrodynamic changes — Large arrays of offshore structures may alter local currents, wave patterns, and sediment transport. Compilers should record observed hydrodynamic changes in the minimum supplementary table below, drawing on satellite altimetry, HF radar, and in situ monitoring described in TG-4.1 Remote Sensing Data.

Table 3.3: Minimum supplementary table for offshore wind hydrodynamic impact recording

Seabirds — Offshore wind turbines present collision risk for migratory and foraging seabirds. Empirical evidence suggests mortality rates for offshore installations are generally lower than for onshore wind, though considerable uncertainty remains in population-level estimates. Impact assessment should adopt precautionary approaches, clearly distinguishing observed mortality from modelled estimates.

Marine mammals — Vessel traffic associated with offshore energy operations increases collision risk for cetaceans and pinnipeds. Record as pressure indicators in ecosystem condition accounts.

Fish and invertebrates — Entrainment in cooling water intakes may impact fish populations. Tidal stream devices present potential collision risk for marine mammals and large fish species.

3.5.1 Asset retirement framework

The SEEA Central Framework distinguishes between terminal costs and remedial costs for fixed asset disposal:

Terminal costs are anticipated during production periods and should be provisioned through consumption of fixed capital allowances over the asset’s life. Examples include removal of platform topsides and jackets, plugging and abandonment of wells, cable removal or burial, and site clearance surveys.

Remedial costs are incurred after operations cease, often by parties other than the original operator: cleanup of contaminated seabed sediments, long-term monitoring of residual structures, and rehabilitation of impacted habitats.

The 2025 SNA glossary defines terminal costs as “costs incurred on the disposal of an asset or at the end of its service life” covering “de-installation and decommissioning costs (in case of oil rigs or nuclear power stations) or rehabilitation costs of land sites”.

Orphaned infrastructure. For account purposes, an installation is classified as orphaned where:

(a) the registered operator or licence holder no longer exists as a legal entity; or (b) the operator exists but has formally disclaimed decommissioning responsibility, and a court or regulatory determination has assigned liability to the state; or (c) the installation has been abandoned without regulatory notification and the operator cannot be located.

Orphaned installations should be identified separately in supplementary tables and recorded as government-held contingent liabilities, consistent with the 2025 SNA treatment of contingent liabilities. Where the liability is probable and the remediation cost can be reliably estimated, the estimated cost should be recorded as a government provision. Where the government subsequently incurs remediation expenditure, record as gross fixed capital formation (land improvement asset) or intermediate consumption (ongoing environmental protection), as applicable.

This Section owns the treatment of submerged artificial structures for the publication. The rule below is written for rigs-to-reefs conversions but applies to any placed structure that acquires confirmed ecological function, wherever it sits: breakwaters, groynes and artificial reefs inside the territorial sea are recorded the same way (TG-6.11 Coastal Infrastructure Accounting Section 3.4.1), and a structure colonised by reef-building corals is still M4.1 and not an addition to M1.3 photic reef extent (TG-6.1 Coral Reef Accounting Section 3.1).

Accounting treatment follows a three-step recording sequence consistent with SEEA EA extent account transition rules:

If reef designation is subsequently revoked or the structure fails to develop confirmed ecological function, the M4.1 extent entry should be reversed as an other change in volume of ecosystem assets in the period of revocation.

In addition, compilers should:

• record the reduction in decommissioning liability (terminal cost avoided)
• track any payments to or from regulatory authorities
• account for any ongoing maintenance or monitoring obligations

Note that oil and gas infrastructure left as artificial reefs “is more exposed to light/noise/chemical pollution associated with operations as well the spread of invasive species” compared to purpose-built artificial reefs. This pollution legacy should be reflected in the condition assessment of converted structures.

Where decommissioning reveals contamination or environmental damage, remediation expenditure should be recorded as:

• Gross fixed capital formation when creating a land improvement asset (remediated site)
• Intermediate consumption when representing ongoing environmental protection activities

SEEA-Energy notes that expenditures on decommissioning represent one area where economic response to environmental issues can be highlighted. The same principle applies to offshore oil and gas decommissioning, which may be recorded as environmental protection expenditure within thematic and extended accounts.

3.6 Energy Transition Accounting

3.6.1 Fossil to renewable transition

Asset revaluation — Declining demand for fossil fuels may reduce the economic value of oil and gas reserves, recorded as downward reappraisals in physical asset accounts and revaluations in monetary accounts.

Infrastructure repurposing — Some offshore oil and gas infrastructure may be converted for renewable energy use (platforms as wind turbine bases, pipelines for hydrogen transport, wellbore infrastructure for geothermal extraction). Record the reclassification as other changes in volume of assets, noting both the write-down of the original asset and the acquisition of the repurposed asset.

Workforce transition — Employment shifts from fossil fuel to renewable sectors should be tracked through labour accounts linked to ISIC industry classifications. See TG-3.5 Social Accounts.

3.6.2 Stranded asset treatment

The IFRS S2 Climate-related Disclosures standard requires disclosure of “the amount and percentage of assets or business activities vulnerable to transition risks”. In SEEA terms, stranded assets are recorded as:

• Downward reappraisals (Class A to Class B/C) for resource reclassification
• Other changes in volume of assets for unexpected retirements
• Write-offs for exploration expenditure on abandoned projects

Recognition timing. The SEEA Central Framework requires that revaluations be recorded “when the event causing the change is recognized” (para. 5.94). Table 3.4 sets out recognition criteria by trigger type.

Table 3.4: Stranded asset recognition criteria by trigger type

Documentation should follow TG-0.7 Quality Assurance standards.

3.6.3 Carbon and climate accounting

Emissions — Fossil fuel extraction generates direct emissions (flaring, venting, fugitive methane) and enables downstream emissions from combustion. For recording these flows, see TG-3.4 Flows from Economy to Environment.

Carbon storage (CCS) — Some depleted offshore reservoirs may be repurposed for carbon capture and storage. CCS accounting remains an open methodological question awaiting UNSD resolution, including whether stored carbon represents negative extraction, a new asset type, or an environmental protection service. Compilers in jurisdictions with operating offshore CCS projects (notably Norway, the UK, and Australia) should populate the provisional supplementary table below, drawing on the OSPAR CCS reporting framework and IEA CCUS Projects Database.

Table 3.5: Provisional supplementary table for offshore CCS recording (pending standardisation)

Resource rent calculation (net price method, central case USD 85/barrel)

Table 3.7: Resource rent supplementary calculation, oil field 2025 (central case USD 85/barrel)

At the central case price, resource rent is negative, as the mature field’s development cost is high relative to current gross output. Where resource rent is non-positive, depletion is recorded as zero and the field’s monetary asset value is held under review for downward reappraisal.

Monetary account for oil field (values in million USD, annual; central case USD 85/barrel)

Table 3.8: Production account for offshore oil field, 2025 (central case USD 85/barrel)

Price sensitivity for net value added

Decommissioning provision: Terminal costs of USD 2,000 million are provisioned over the 10-year production life at USD 200 million per year, recorded as part of consumption of fixed capital. If actual decommissioning costs in Year 11 exceed the provision (e.g., USD 2,500 million due to unexpected contamination), the excess USD 500 million is recorded as remedial costs in the period incurred.

Physical supply account for offshore wind (energy in MWh)

Table 3.10: Physical supply account for offshore wind, 2025

Monetary account for offshore wind (values in million USD, annual)

Table 3.11: Production account for offshore wind, 2025

Any subsidies received (feed-in tariffs, renewable energy certificates) should be recorded as current transfers in the distribution of income account.

Wind wholesale price sensitivity. The USD 80/MWh central case sits at the lower end of European 2024—25 offshore wind strike prices (USD 90—130/MWh typical). Benchmark prices should be sourced from IRENA LCOE data or published Contracts for Difference (CfD) strike prices for the relevant jurisdiction.

Table 3.11a: Price sensitivity — net value added, offshore wind farm 2025 (USD million)

At USD 90/MWh or above the wind farm reports positive net value added, and compilers should document the price source in account metadata.

Table 3.12: Spatial footprint account for offshore energy installations, 2025. Safety-zone derivation: wind farm ~80 turbines × π × (0.5 km)² ≈ 62.8 km²; oil field 1 platform × π × (0.5 km)² ≈ 0.79 km².

Table 3.13: Environmental impact account for offshore energy installations, 2025

These impact indicators feed into the ecosystem condition accounts described in Section 3.4, and support cumulative impact assessment across multiple installations within a spatial unit.

Integration and upward connections

Upward linkages to policy:

Cross-account consistency:

• Oil extraction of 20 million barrels corresponds to extraction recorded in physical supply-use tables
• Monetary depletion of oil reserves corresponds to adjustments in monetary asset accounts
• Offshore wind generation of 1.84 TWh flows into national energy balance tables
• Spatial footprints are consistent with marine spatial planning databases

4. Worked Example Cross-References

Cross-references for the worked example (Section 3.7) and integration with upstream and downstream circulars are provided in the relevant subsections of Section 3 and Section 1.2. The compilation procedure (Section 3.2) and the data sources (Section 2.3) define the practical workflow for compiling offshore energy accounts.