Offshore Energy Thematic Methods

1. Outcome

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 3.4.2) enable tracking of decommissioning liabilities; the rigs-to-reefs framework (Section 3.4.3) 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 3.5) 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 3.5.3 provides the accounting linkage.

Renewable energy target monitoring. Physical energy accounts (Section 3.2) record installed capacity and generation by technology type, enabling comparison against policy targets and feeding into 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.

1.3 Emerging Methodological Issues

Methods for offshore renewable energy accounting and cumulative impact assessment are not yet standardized 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. Cable landfall infrastructure and onshore grid connections are addressed in TG-6.11 Coastal Infrastructure.

2. Requirements

This Circular requires familiarity with:

• TG-0.1 General Introduction to Ocean Accounts—conceptual framework for ocean accounting, including the Basic Spatial Unit framework for georeferencing offshore activities.

• TG-3.10 Offshore Energy Accounts—foundational accounting structure for offshore energy, including supply and use tables, asset accounts for mineral and energy resources, and activity classification.

2.1 Related Circulars

• TG-3.1 Asset Accounts—general methodology for environmental asset accounts applicable to seabed mineral resources and ecosystem condition accounting.

• TG-3.3 Economic Activity Relevant to the Ocean—industry classification guidance for distinguishing offshore from onshore energy extraction.

• TG-4.1 Remote Sensing Data—methods for mapping offshore energy infrastructure using satellite imagery and AIS data.

• TG-6.5 Pelagic and Open Ocean—accounting for offshore renewable installations in pelagic environments.

• TG-6.6 Deep Sea and Seabed Accounting—relevant for deep-water energy developments and activities beyond national jurisdiction.

• TG-6.11 Coastal Infrastructure—export cable landfall, onshore substations, and grid connection infrastructure.

2.2 International Standards Alignment

This guidance aligns with: SEEA Central Framework (2012)^[1] for mineral and energy resource treatment and decommissioning costs; SEEA-Energy (2019)^[2] for physical and monetary supply and use tables and fossil fuel asset accounts; 2025 SNA^[3] for renewable energy resource classification and terminal cost treatment; and UNCLOS (1982)^[4] for offshore installation legal framework.^[5]

2.3 Data Sources

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

3. Guidance Material

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)^[7]. ISIC Division 06 does not distinguish onshore from offshore extraction at the four-digit level; 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)^[8]:

Monetary asset accounts record the net present value of commercially recoverable resources, with revaluations reflecting changes in commodity prices, extraction costs, and discount rates^[9]. 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)^[10]. 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^[6:1] 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

The 2025 SNA and SEEA-Energy classify wind energy resources as a type of renewable energy resource distinct from mineral and energy resources^[11].

Key accounting considerations:

• Income attribution—floating wind installations. By convention, income streams from offshore renewable energy capture are attributed to the value of underlying seabed assets^[12]. For floating installations without fixed seabed attachment, this convention is methodologically problematic.

  Compilers should distinguish two treatments:

  • Provisional recording convention (workaround): Record floating installations in the spatial unit corresponding to the licence or lease area, and attribute income streams to seabed assets within that area. This is explicitly a workaround, not a settled method.
  • Preferred future treatment: Attribute floating wind income to a distinct "offshore wind resource" asset class reflecting the wind resource and licence. This treatment is not yet standardized.

  Compilers must document in account metadata which treatment has been applied. A formal issue has been submitted to the UNSD SEEA expert group; compilers should monitor outcomes through UNSD and UNCEEA.

• Fixed asset accounts—Wind turbines, foundations, and transmission infrastructure are recorded as produced fixed assets with depreciation over their operational life.

• Capacity factors—Physical accounts should record both installed capacity (MW) and actual generation (MWh), as capacity factors for offshore wind typically range from 35--50%.

• Cable infrastructure and indicative useful lives—Array cables and export cables have different asset lives and ownership structures and should be recorded as separate asset classes where data permit. Table 3.1 provides indicative useful life parameters^[3:1],^[13].

  Table 3.1: Indicative useful life parameters for offshore wind asset classes

  Asset class	Indicative useful life (years)
  Wind turbine and tower	20--25
  Monopile / jacket foundation	25--30
  Array cable	20--25 (aligned with turbine life)
  Export cable	30--40 (may serve multiple wind farm generations)
  Offshore substation	25--30

  (References to be confirmed—see Section 5.)

3.1.3 Wave and tidal energy (emerging)

The FDES defines renewable energy sources to include "tidal action, wave action, marine (non-tidal currents, temperature differences and salinity gradients)"^[14].

Two distinct tidal energy technologies should be distinguished: tidal range (barrages and lagoons), which create large spatial footprints and significant estuarine ecosystem impacts; and tidal stream (underwater turbines), which have smaller spatial footprints but potential collision and noise impacts on marine fauna. These technologies differ substantially in their spatial, ecological, and economic characteristics and should be recorded separately.

Accounting for emerging marine energy technologies should:

• Track pilot and demonstration installations separately from commercial operations
• Record research and development expenditure as gross fixed capital formation per SEEA-Energy guidance
• Monitor installed capacity growth to inform energy transition scenarios

3.2 Compilation Procedure for Offshore Energy Accounts

Step 1: Data collection and source identification

Assemble the data sources catalogued in Section 2.3 to measure opening stocks, production flows, additions, reductions, and closing stocks for each energy type. Data quality should be assessed following TG-0.7 Quality Assurance, with particular attention to temporal consistency, spatial coverage, and measurement uncertainty.

Step 2: Classification and mapping to asset categories

Map source data to SEEA CF asset categories:

• 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^[2:1].

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

Use table records: intermediate consumption within offshore operations (platform electricity, flaring losses); exports of offshore-produced oil, gas, and electricity; 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, feeding 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^[9:1]. 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^[9:2]. For offshore renewable resources, there is no depletion; 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

3.3.1 Seabed occupation

Spatial accounts should record:

Direct footprint—The physical area occupied by: platform jackets and foundations (oil/gas); monopile, jacket, or floating foundations (wind); anchoring systems and mooring lines; 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^[15]. 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^[16]. 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, enabling cumulative impacts to 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

3.4.1 Underwater noise

Offshore energy activities generate underwater noise during construction (pile driving), operation (machinery, vessel traffic), and decommissioning^[17].

Source characterization—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^[18].

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^[19]) provides the regulatory baseline.

TNFD metrics for noise pollution^[20] are designed for corporate site-level disclosure and should not be aggregated directly across operators to derive national-level indicators: measurement methodologies are not standardized across companies; "noisiest part of day" is a peak rather than period-average metric; and 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

3.4.3 Habitat modification

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^[21]. Compilers should record the introduction of hard substrate as a change in ecosystem type within extent accounts (from soft-sediment benthic to M4.1), while 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^[22]. 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

3.4.4 Collision risk

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 Decommissioning Accounting

3.5.1 Asset retirement framework

The SEEA Central Framework distinguishes between terminal costs and remedial costs for fixed asset disposal^[23]:

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"^[24].

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^[25]. 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.

3.5.2 Rigs-to-reefs programmes

Some jurisdictions permit partial decommissioning where platform structures are left in place as artificial reefs. Research indicates that "more than 500 oil and gas platforms were decommissioned and left as artificial reefs in US waters since 1940" with "more than 600 in the Asia-Pacific alone" as candidates for reefing^[26].

Accounting treatment for rigs-to-reefs conversions follows a three-step recording sequence consistent with SEEA EA extent account transition rules^[27]:

1. On legal decommissioning: Record write-down of the oil and gas infrastructure asset as an other change in volume of produced assets, removing the platform from the produced asset stock.
2. On regulatory confirmation of reef designation: Record introduction of an IUCN GET M4.1 ecosystem extent entry, with area equal to the structure footprint plus a defined ecological halo (typically 50--100 m radius from the structure). The statutory 500 m exclusion zone must not be used as the M4.1 extent area, as it substantially overstates the area of active ecological function.
3. In subsequent periods: Update ecosystem condition variables (species diversity, biomass density, structural integrity) as monitoring data become available. See TG-6.1 Coral Reef Accounts for condition monitoring standards applicable to artificial reef ecosystems.

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; and 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^[28]. This pollution legacy should be reflected in the condition assessment of converted structures.

3.5.3 Remediation expenditure

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^[29]. 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"^[30]. 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)^[31]. 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—including whether stored carbon represents negative extraction, a new asset type, or an environmental protection service—remains an open methodological question awaiting UNSD resolution. 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^[36] and IEA CCUS Projects Database^[37].

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

Avoided emissions—Offshore renewable energy displaces fossil fuel generation, contributing to emission reductions counted in national inventories. For SDG indicator 12.c.1 compilation from offshore energy accounts, see TG-2.10 MEA Indicators^[38].

3.7 Worked Example: Synthetic Offshore Energy Account

Scenario description

The accounting area is a coastal State's EEZ containing one mature offshore oil field and one operational offshore wind farm. The accounting period is calendar year 2025.

Offshore oil field parameters:

• Total recoverable reserves (Class A): 200 million barrels
• Development cost (GFCF): $15,000 million
• Annual extraction rate: 20 million barrels
• Expected production life: 10 years
• Oil price (central case): $85/barrel; sensitivity range $70--$100/barrel
• Annual operating expenditure: $800 million
• Estimated decommissioning cost: $2,000 million

Offshore wind farm parameters:

• Installed capacity: 500 MW
• Capacity factor: 0.42
• Annual generation: 1,839,600 MWh
• Design life: 25 years
• Construction cost (GFCF): $2,500 million
• Annual O&M expenditure: $50 million
• Wholesale electricity price: $80/MWh

Physical asset account for oil field (stock in million barrels)

Table 3.6: Physical asset account for offshore oil field, 2025

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

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

At the central case price, resource rent is negative, reflecting the high development cost of this mature field 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 $85/barrel)

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

Price sensitivity for net value added

Table 3.9: Price sensitivity—net value added, oil field 2025 (USD million)

Mature offshore fields with high development cost may report negative net value added across a wide range of price assumptions, reflecting depreciation of large past development capital, decommissioning provisioning, and a mature-life production profile. Compilers should report results alongside the resource rent calculation and price-sensitivity range.

Decommissioning provision: Terminal costs of $2,000 million are provisioned over the 10-year production life at $200 million per year, recorded as part of consumption of fixed capital. If actual decommissioning costs in Year 11 exceed the provision (e.g., $2,500 million due to unexpected contamination), the excess $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 $80/MWh central case sits at the lower end of European 2024--25 offshore wind strike prices ($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^[39].

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

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

Spatial footprint summary

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.

Environmental impact summary

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, enabling cumulative impact assessment across multiple installations within a spatial unit.

Integration and upward connections

Upward linkages to policy (TG-1.x and TG-2.x):

• TG-1.1 National Ocean Budgets: The $200 million decommissioning provision represents a significant fiscal liability. Monetary depletion of oil reserves (calculated via resource rent applied to the 20 million barrels extracted) represents natural capital drawdown deducted from gross income to calculate environmentally adjusted net domestic product.
• TG-2.8 Climate Indicators: Direct emissions of 450,000 tonnes CO₂-eq from the oil field contribute to national greenhouse gas inventories. The 1.84 TWh of offshore wind generation displaces approximately 900,000 tonnes CO₂-eq of fossil generation (assuming grid emission factor of 0.5 kg CO₂/kWh).
• TG-1.8 Project Finance: Total investment of $2,500 million against annual revenue of $147 million illustrates project finance challenges where long payback periods and policy support requirements create financing gaps addressable through blue bonds or sustainability-linked loans.

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.

5. Coordination Considerations

Effective offshore energy accounting requires coordination between national statistical offices, energy ministries, environment ministries, maritime authorities, industry associations, and regional bodies (including bilateral coordination on unitisation of transboundary reservoirs as set out in Section 3.1.1).

6. Acknowledgements

This Circular has been approved for public circulation and comment by the GOAP Technical Experts Group in accordance with the Circular Publication Procedure.

Authors: [To be confirmed]

Reviewers: [To be confirmed]

7. References