Offshore Energy Thematic Methods

TG-6.9 Section 6: Thematic Methodologies Emerging Draft

Circular ID	TG-6.9
Version	7.0
Badge	Emerging
Status	Draft
Last Updated	May 2026

1. Outcome

1This 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

1Offshore 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.

2Oil 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.

3Energy 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.

4Renewable 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.

5Asset 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

1Methods 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.

Methodological area	Description
Income attribution for floating offshore wind installations	Methods for valuing artificial reef ecosystem services created by offshore structures. See Section 3.1.2.
Carbon capture and storage (CCS) accounting	Frameworks for assessing when combined impacts exceed ecosystem carrying capacity. See Section 3.6.3.
Infrastructure repurposing accounting	Treatment of offshore installations in shared maritime zones or areas beyond national jurisdiction. See Section 3.6.1.
Electromagnetic field (EMF) impact accounting	Accounting treatment for mobile offshore installations (floating production units, floating wind turbines). See Section 3.4.2.
Ecosystem service valuation	Valuation of artificial reef ecosystem services created by offshore structures. See Section 3.4.3.
Cumulative impact thresholds	Frameworks for assessing when combined impacts exceed ecosystem carrying capacity. See Section 3.4.1.
Cross-border accounting	Treatment of offshore installations in shared maritime zones or areas beyond national jurisdiction. See Section 3.1.1.
Emerging offshore activities	Offshore hydrogen production, offshore desalination, and marine data centres represent emerging ocean uses. Record pilot installations in supplementary tables where they occur.

2Reclassification 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.

2. Requirements

1This Circular requires familiarity with:

• 2

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

• 3

  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

• 1

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

• 2

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

• 3

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

• 4

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

• 5

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

• 6

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

2.2 International Standards Alignment

1This guidance aligns with four standards:

• 2SEEA Central Framework (2012)¹ for mineral and energy resource treatment and decommissioning costs
• 3SEEA-Energy (2019)² for physical and monetary supply and use tables and fossil fuel asset accounts
• 42025 SNA³ for renewable energy resource classification and terminal cost treatment
• 5UNCLOS (1982)⁴ for the offshore installation legal framework⁵

2.3 Data Sources

Source	Data provided
National petroleum and energy regulatory authorities	Licence areas, production data, reserves estimates, and decommissioning schedules for offshore oil and gas fields.
Environmental agencies	Impact assessments, monitoring data for ecosystem condition variables, and discharge permits.
Maritime authorities	Infrastructure locations, safety zone coordinates, and vessel tracking data (AIS).
Energy companies	Financial reports, sustainability disclosures (following IFRS S2 and TNFD frameworks), and operational data.
Research institutions	Ecological studies, technology assessments, and condition monitoring results.
International sources	IEA World Energy Balances6 for bilateral production data; IRENA for renewable energy capacity and cost data; 4C Offshore and Global Wind Energy Council for offshore wind farm registries.

1Data 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)

1Offshore 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, so compilers should use location-based coding or national satellite industry codes where available. See TG-3.3 Economic Activity Relevant to the Ocean.

2Physical asset accounts record stocks using the United Nations Framework Classification for Fossil Energy and Mineral Reserves and Resources (UNFC-2009)⁸:

Class	Description
Class A: Commercially Recoverable Resources	Deposits where extraction and sale has been confirmed economically viable (UNFC categories E1, F1, G1-G3).
Class B: Potentially Commercially Recoverable Resources	Deposits expected to become economically viable in the foreseeable future (UNFC categories E2, F2.1/F2.2, G1-G3).
Class C: Non-Commercial and Other Known Deposits	Resources not expected to become economically viable with current technology and prices.

3Monetary asset accounts record the net present value of commercially recoverable resources, with revaluations reflecting changes in commodity prices, extraction costs, and discount rates⁹. For foundational supply-use and asset-account structures, see TG-3.10 Offshore Energy Accounts.

4Transboundary 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:

• 5The 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.
• 6Where no unitisation agreement exists, use the most recent bilateral production data sharing arrangement, or IEA World Energy Balances⁶ as an interim basis.
• 7UNFC 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.

8Transboundary reservoir methodology has been flagged as a candidate issue for future UNSD guidance development.

3.1.2 Offshore wind energy

1The 2025 SNA and SEEA-Energy classify wind energy resources as a type of renewable energy resource distinct from mineral and energy resources¹¹.

2Key accounting considerations:

• 3

  Income attribution — floating wind installations. By convention, income streams from offshore renewable energy capture are attributed to the value of underlying seabed assets¹². For floating installations without fixed seabed attachment, this convention is methodologically problematic.

  Compilers should distinguish two treatments:

  • 4Provisional 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.
  • 5Preferred 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 standardised.

  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.

• 6

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

• 7

  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%.

• 8

  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 parameters³,¹³.

  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)

1The FDES defines renewable energy sources to include “tidal action, wave action, marine (non-tidal currents, temperature differences and salinity gradients)”¹⁴.

2Two distinct tidal energy technologies should be distinguished. Tidal range (barrages and lagoons) creates large spatial footprints and significant estuarine ecosystem impacts. Tidal stream (underwater turbines) has 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.

3Accounting for emerging marine energy technologies should:

• 4Track pilot and demonstration installations separately from commercial operations
• 5Record research and development expenditure as gross fixed capital formation per SEEA-Energy guidance
• 6Monitor installed capacity growth to inform energy transition scenarios

3.2 Compilation Procedure for Offshore Energy Accounts

Step 1: Data collection and source identification

1Assemble 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

1Map source data to SEEA CF asset categories:

• 2Mineral and energy resources (offshore oil and gas) — Class A (commercially recoverable), Class B (potentially commercial), and Class C (non-commercial)
• 3Renewable energy resources (wind, wave, tidal) — classified separately from mineral resources following 2025 SNA treatment

4Physical 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

1Physical energy supply and use tables (PSUT) follow SEEA-Energy Chapter 3².

2Supply 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.

3Use 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.

4The 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

1Monetary 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.

2Key valuation considerations:

• 3Oil and gas production is valued at wellhead prices (excluding transport and processing margins)
• 4Offshore renewable electricity is valued at wholesale market prices or feed-in tariff rates
• 5Gross value added is calculated as output minus intermediate consumption
• 6For 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 6⁹. See Section 3.7 for a worked example.

Step 5: Asset account compilation

1Asset 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 against⁹. 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

1Integration ensures that:

• 2Depletion entries in asset accounts correspond to depletion costs in production accounts and adjustments to net domestic product (see TG-1.1 National Ocean Budgets)
• 3Extraction entries correspond to natural resource inputs in physical supply-use tables
• 4Investment in offshore infrastructure is recorded as gross fixed capital formation in produced assets
• 5Environmental impact entries in ecosystem condition accounts are consistent with offshore energy spatial footprints

3.3 Spatial Footprint Accounting

3.3.1 Seabed occupation

1Spatial accounts should record:

2Direct 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).

3Cable 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 installations¹⁵. Cable landfall and onshore substation accounting are addressed in TG-6.11 Coastal Infrastructure.

3.3.2 Exclusion and safety zones

1UNCLOS Article 60 permits coastal States to establish safety zones extending up to 500 metres from each point of the outer edge of offshore installations¹⁶. These zones effectively exclude commercial fishing, navigation, anchoring, and other seabed development.

2Spatial 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.

3Tier 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

1Offshore 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

1The 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.

2Table 3.2: Offshore energy environmental impact comparison

Impact Type	Oil & Gas	Offshore Wind	Tidal/Wave
Seabed disturbance	Platform footprint	Foundation footprint	Device anchoring
Underwater noise	Drilling, operation	Construction (piling)	Operation (low)
Collision risk	Low (platforms visible)	Bird/bat collision	Marine mammal
Pollution risk	Spills, discharges	Low (no fuel)	Low
Decommissioning	Complex, costly	Simpler	Emerging
Account treatment	Depletion of minerals	No depletion	No depletion

3.4.1 Underwater noise

1Offshore energy activities generate underwater noise during construction (pile driving), operation (machinery, vessel traffic), and decommissioning¹⁷.

2Source 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.

3Receptor 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 attention¹⁸.

4Impact 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.

5Data 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) 2017/848¹⁹) provides the regulatory baseline.

6TNFD metrics for noise pollution²⁰ are designed for corporate site-level disclosure and should not be aggregated directly across operators to derive national-level indicators, for three reasons:

• 7measurement methodologies are not standardised across companies
• 8“noisiest part of day” is a peak rather than period-average metric
• 9TNFD disclosures are voluntary and incomplete

3.4.2 Electromagnetic fields (EMF)

1Subsea power cables generate electromagnetic fields that may affect electroreceptive marine species (sharks, rays, some crustaceans). Research remains limited. Current accounting practice should:

• 2Record cable specifications (voltage, current, burial depth, shielding) as supplementary physical data
• 3Map cable routes in relation to sensitive habitats using georeferenced data
• 4Monitor and report any observed behavioural effects as condition indicators where monitoring data are available

3.4.3 Habitat modification

1Substrate 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 type²¹. 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.

2Sediment disturbance — Installation and cable burial activities disturb seabed sediments, potentially releasing contaminants and altering benthic communities. Record as condition changes in affected spatial units.

3Hydrodynamic changes — Large arrays of offshore structures may alter local currents, wave patterns, and sediment transport²². 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.

4Table 3.3: Minimum supplementary table for offshore wind hydrodynamic impact recording

Field	Description
Installation ID	Unique identifier for the wind array
Monitoring period	Reporting year and reference baseline period
Current velocity change	% change from baseline at specified depth
Wave height reduction	% change in lease area
Sediment transport indicator	Qualitative: increased / reduced / unchanged
Source	Model output or in situ observation
Uncertainty rating	Low / medium / high

3.4.4 Collision risk

1Seabirds — 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.

2Marine mammals — Vessel traffic associated with offshore energy operations increases collision risk for cetaceans and pinnipeds. Record as pressure indicators in ecosystem condition accounts.

3Fish 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

1The SEEA Central Framework distinguishes between terminal costs and remedial costs for fixed asset disposal²³:

2Terminal 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.

3Remedial 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.

4The 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.

5Orphaned infrastructure. For account purposes, an installation is classified as orphaned where:

6(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.

7Orphaned installations should be identified separately in supplementary tables and recorded as government-held contingent liabilities, consistent with the 2025 SNA treatment of contingent liabilities²⁵. 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

1Some 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 reefing²⁶.

2Accounting treatment for rigs-to-reefs conversions follows a three-step recording sequence consistent with SEEA EA extent account transition rules²⁷:

1. 3On 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. 4On 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. 5In 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.

6If 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.

7In addition, compilers should:

• 8record the reduction in decommissioning liability (terminal cost avoided)
• 9track any payments to or from regulatory authorities
• 10account for any ongoing maintenance or monitoring obligations

11Note 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 reefs²⁸. This pollution legacy should be reflected in the condition assessment of converted structures.

3.5.3 Remediation expenditure

1Where decommissioning reveals contamination or environmental damage, remediation expenditure should be recorded as:

• 2Gross fixed capital formation when creating a land improvement asset (remediated site)
• 3Intermediate consumption when representing ongoing environmental protection activities

4SEEA-Energy notes that expenditures on decommissioning represent one area where economic response to environmental issues can be highlighted²⁹. 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

1Asset 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.

2Infrastructure 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.

3Workforce 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

1The 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:

• 2Downward reappraisals (Class A to Class B/C) for resource reclassification
• 3Other changes in volume of assets for unexpected retirements
• 4Write-offs for exploration expenditure on abandoned projects

5Recognition 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.

6Table 3.4: Stranded asset recognition criteria by trigger type

Trigger type	Period of recording	Supporting documentation
Policy announcement	Period in which binding legislation or regulation is enacted (not at consultation or political announcement stage)32	Citation of enacted legislative or regulatory instrument
Market signal	Period after the commodity price has been below the cost of extraction for two consecutive annual average periods and no recovery is expected33,34	Annual average price series and extraction cost reference
Physical event	Period of the physical event35	Incident report and reference to asset condition assessment

7Documentation should follow TG-0.7 Quality Assurance standards.

3.6.3 Carbon and climate accounting

1Emissions — 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.

2Carbon 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 framework³⁶ and IEA CCUS Projects Database³⁷.

3Table 3.5: Provisional supplementary table for offshore CCS recording (pending standardisation)

Field	Unit / format
Reservoir ID	Unique identifier
Location (BSU)	Basic Spatial Unit reference
Storage capacity	Mt CO₂
Cumulative injections to period start	Mt CO₂
Injections during period	Mt CO₂
Monitoring / verification expenditure	USD
Ownership structure	Operator, equity shares, public/private

4Avoided 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 Indicators³⁸.

3.7 Worked Example: Synthetic Offshore Energy Account

Scenario description

1The 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.

2Offshore oil field parameters:

• 3Total recoverable reserves (Class A): 200 million barrels
• 4Development cost (GFCF): $15,000 million
• 5Annual extraction rate: 20 million barrels
• 6Expected production life: 10 years
• 7Oil price (central case): $85/barrel; sensitivity range $70—$100/barrel
• 8Annual operating expenditure: $800 million
• 9Estimated decommissioning cost: $2,000 million

10Offshore wind farm parameters:

• 11Installed capacity: 500 MW
• 12Capacity factor: 0.42
• 13Annual generation: 1,839,600 MWh
• 14Design life: 25 years
• 15Construction cost (GFCF): $2,500 million
• 16Annual O&M expenditure: $50 million
• 17Wholesale electricity price: $80/MWh

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

Accounting entry	Value
Opening stock (1 Jan 2025)	200
Additions to stock
Discoveries	0
Upward reappraisals	0
Total additions	0
Reductions in stock
Extraction	20
Downward reappraisals	0
Total reductions	20
Closing stock (31 Dec 2025)	180
Derived measures
Depletion (extraction for non-renewable resource)	20

1Table 3.6: Physical asset account for offshore oil field, 2025

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

Item	Value (USD million)
Gross output (20M bbl × $85)	1,700
less: Intermediate consumption (operating costs)	800
less: CFC on development infrastructure ($15,000M / 10 yr)	1,500
less: Return to produced capital (assumed 4% of net capital stock, indicative)	300
Resource rent (net price method)	-900
Memo: Unit resource rent per barrel	-45.0

1Table 3.7: Resource rent supplementary calculation, oil field 2025 (central case $85/barrel)

2At 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 $85/barrel)

Monetary flow	Annual value
Gross output (20M bbl × $85)	1,700
Intermediate consumption (operating costs)	800
Gross value added	900
Consumption of fixed capital and depletion
of which: CFC on development infrastructure ($15,000M / 10 yr)	1,500
of which: Decommissioning provision ($2,000M / 10 yr)	200
of which: Mineral resource depletion (per resource rent, Table 3.7)	0
Total CFC and depletion	1,700
Net value added	-800

1Table 3.8: Production account for offshore oil field, 2025 (central case $85/barrel)

Price sensitivity for net value added

1Table 3.9: Price sensitivity — net value added, oil field 2025 (USD million)

Oil price (USD/bbl)	Gross output	GVA	CFC + depletion	Net value added
70	1,400	600	1,700	-1,100
85 (central)	1,700	900	1,700	-800
100	2,000	1,200	1,700	-500

2Mature offshore fields with high development cost may report negative net value added across a wide range of price assumptions. This reflects 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.

3Decommissioning 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)

Physical flow	Year 1	Year 2	…	Year 25
Installed capacity (MW)	500	500	…	500
Actual generation (MWh)	1,839,600	1,839,600	…	1,839,600
Capacity factor	0.42	0.42	…	0.42

1Table 3.10: Physical supply account for offshore wind, 2025

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

Monetary flow	Annual value
Gross output (1,839,600 MWh × $80)	$147.2
Intermediate consumption (O&M)	$50.0
Gross value added	$97.2
Consumption of fixed capital ($2,500M / 25 yr)	$100.0
Net value added	-$2.8

1Table 3.11: Production account for offshore wind, 2025

2Any subsidies received (feed-in tariffs, renewable energy certificates) should be recorded as current transfers in the distribution of income account.

3Wind 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 jurisdiction³⁹.

4Table 3.11a: Price sensitivity — net value added, offshore wind farm 2025 (USD million)

Wholesale price (USD/MWh)	Gross output	GVA	CFC	Net value added
70	128.8	78.8	100.0	-21.2
80 (central)	147.2	97.2	100.0	-2.8
90	165.6	115.6	100.0	15.6
110	202.4	152.4	100.0	52.4

5At $90/MWh or above the wind farm reports positive net value added, and compilers should document the price source in account metadata.

Spatial footprint summary

Spatial measure	Oil field	Wind farm
Lease area	25 km²	120 km²
Direct seabed footprint	0.15 km²	0.25 km²
Statutory safety zones (500m)	0.79 km²	62.8 km²
Export cable corridor	0 km² (subsea pipeline)	20.0 km²
Effective exclusion area (from AIS)	1.2 km²	140.0 km²

1Table 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

Impact category	Oil field	Wind farm
Seabed disturbance	0.15 km²	0.25 km²
Underwater noise (construction)	180 dB re 1 µPa @ 1m (drilling)	190 dB re 1 µPa @ 1m (piling)
Pollution risk	2.5 million m³ produced water	Low
Exclusion zone	0.79 km²	62.8 km²
GHG emissions (direct)	450,000 tonnes CO₂-eq	<5,000 tonnes CO₂-eq

1Table 3.13: Environmental impact account for offshore energy installations, 2025

2These 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

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

• 2TG-1.1 National Ocean Budgets: The $200 million decommissioning provision represents a 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.
• 3TG-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).
• 4TG-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.

5Cross-account consistency:

• 6Oil extraction of 20 million barrels corresponds to extraction recorded in physical supply-use tables
• 7Monetary depletion of oil reserves corresponds to adjustments in monetary asset accounts
• 8Offshore wind generation of 1.84 TWh flows into national energy balance tables
• 9Spatial footprints are consistent with marine spatial planning databases

4. Worked Example Cross-References

1Cross-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

1Effective 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).

Figure 6.9.1 Five-stage offshore decommissioning sequence linking each stage to produced-asset exit, liability recognition, or artificial-reef reclassification. Source: TG-6.9 draft, decommissioning treatment (stages, account entries, and liability provisions); 2025 SNA Glossary (definition of terminal costs); SEEA CF (2012) §4.194--4.209 (terminal vs remedial costs); IMO Resolution A.672(16) (guidelines for abandonment of offshore installations); OSPAR Decision 98/3 (disposal of disused offshore installations in the OSPAR maritime area); SEEA EA (2021) Ch. 4 (ecosystem extent transitions) and condition accounts (restoration).

6. Acknowledgements

1This Circular has been approved for public circulation and comment by the GOAP Technical Experts Group in accordance with the Circular Publication Procedure.

2Authors: [To be confirmed]

3Reviewers: [To be confirmed]

7. References

Footnotes

1. 1

   SEEA Central Framework (2012), paragraphs 4.194—4.209. Detailed guidance on terminal and remedial costs for fixed asset disposal. ↩

2. 2

   SEEA-Energy (2019), Chapters 3—6. Physical and monetary accounts for energy flows and stocks. ↩ ↩²

3. 3

   2025 SNA, paragraphs 11.199—11.202 (renewable energy resource classification) and paragraph 11.85 (other structures including offshore installations). Paragraph numbers to be verified against the final published 2025 SNA text. ↩ ↩²

4. 4

   UNCLOS (1982), Articles 56, 60, 76—79. Sovereign rights over continental shelf resources and regulation of offshore installations. ↩

5. 5

   Additional regulatory context is provided by: IMO MARPOL Convention and London Protocol (discharge accounting and decommissioning at sea); OSPAR Convention (North-East Atlantic offshore installation management); IFRS S2 and TNFD frameworks (corporate sustainability disclosures); and IEA, IRENA, and UNSD/UNCEEA work programmes. ↩

6. 6

   IEA (2024). World Energy Balances. IEA World Energy Statistics and Balances (database). doi:10.1787/data-00512-en. Standard IEA reference for bilateral production data used in national accounts compilation, covering energy production, transformation, and consumption for over 150 countries and regions. ↩ ↩²

7. 7

   ISIC Rev. 4, Division 06. “Extraction of crude petroleum and natural gas.” ↩

8. 8

   SEEA Central Framework (2012), paragraphs 5.170—5.185 (application of UNFC-2009 for categorizing mineral and energy resources) and paras 5.170—5.195 on monetary valuation of mineral and energy resources. Upper bound of paragraph range to be verified against the published SEEA CF PDF. ↩

9. 9

   SEEA-Energy (2019), Chapter 6. Monetary asset accounts for mineral and energy resources using net present value approaches; net price and user cost methods for resource rent; distinction between consumption of fixed capital on produced development infrastructure and depletion of the mineral resource. ↩ ↩² ↩³

10. 10

    SEEA Central Framework (2012), paragraph 5.93. Treatment of shared mineral and energy resources in national asset accounts. ↩

11. 11

    2025 SNA, paragraph 11.202. “For renewable energy resources, the following breakdown is recommended: (i) wind energy resources; (ii) solar energy resources; (iii) water energy resources; (iv) geothermal energy resources; and (v) other renewable energy resources.” ↩

12. 12

    SEEA Central Framework (2012), paragraph 5.231. “By convention, the value of income streams from these sources are attributed to the value of land.” Paragraph number to be verified against the published SEEA CF PDF. ↩

13. 13

    IRENA offshore wind asset-life data. Document title and section/annex reference to be confirmed — IRENA (2023) “Offshore Wind Energy: Technology Overview” was not verified by websearch; correct IRENA source to be identified before final publication. ↩

14. 14

    FDES (2013), paragraph 3.95. “Renewable energy includes solar, hydroelectric, geothermal, tidal action, wave action, marine (non-tidal currents, temperature differences and salinity gradients), wind and biomass energy.” ↩

15. 15

    UNCLOS (1982), Article 79. “Submarine cables and pipelines on the continental shelf.” ↩

16. 16

    UNCLOS (1982), Article 60. Safety zones “shall not exceed a distance of 500 metres around them, measured from each point of their outer edge.” ↩

17. 17

    FDES (2013), paragraph 3.73. “Noise pollution exists not only in the most populated or busiest cities, but also wherever human activities are conducted.” ↩

18. 18

    UNCLOS (1982), Article 65. States shall “in the case of cetaceans shall in particular work through the appropriate international organizations for their conservation, management and study.” ↩

19. 19

    Commission Decision (EU) 2017/848 of 17 May 2017 laying down criteria and methodological standards on good environmental status of marine waters and specifications and standardised methods for monitoring and assessment, and repealing Decision 2010/477/EU, Descriptor D11 (energy, including impulsive and continuous underwater noise). See also parent instrument Directive 2008/56/EC (Marine Strategy Framework Directive). ↩

20. 20

    TNFD Recommendations (2023), metric A2.3 (light and noise pollution metrics; intended scope: corporate site-level disclosure, not national accounting). ↩

21. 21

    IUCN Global Ecosystem Typology, M4.1 Submerged artificial structures. Classification of artificial reef ecosystems. ↩

22. 22

    Carpenter, J.R., Merckelbach, L., Callies, U., Clark, S., Gaslikova, L. and Baschek, B. (2016). Potential impacts of offshore wind farms on North Sea stratification. PLOS ONE, 11(8), e0160830. doi:10.1371/journal.pone.0160830. ↩

23. 23

    SEEA Central Framework (2012), paragraphs 4.194—4.206. Terminal costs versus remedial costs in decommissioning. ↩

24. 24

    2025 SNA Glossary. Definition of terminal costs. ↩

25. 25

    2025 SNA. Treatment of contingent liabilities and provisions in government accounts. ↩

26. 26

    IUCN GET, Scarborough Bull & Love (2020). “Worldwide oil and gas platform decommissioning: A review of practices and reefing options.” ↩

27. 27

    SEEA EA (2021), Chapter 4. Ecosystem extent accounts — recording rules for transitions, including additions and reductions in ecosystem type. ↩

28. 28

    IUCN Global Ecosystem Typology, M4.1. Pollution exposure of oil and gas infrastructure compared to artificial reefs. ↩

29. 29

    SEEA-Energy (2019), paragraph 2.55. Economic response information including decommissioning expenditures. ↩

30. 30

    IFRS S2 Climate-related Disclosures (2023), paragraph 29. Transition risk disclosure requirements. ↩

31. 31

    SEEA Central Framework (2012), paragraph 5.94. Recognition timing for revaluations and other changes in volume of assets. ↩

32. 32

    Al Khourdajie, A. et al. (2022). IPCC AR6 Annex II: Definitions, Units and Conventions. doi:10.2172/1973107. Methodological definitions for mitigation pathways and economic shifts underpinning policy-announcement triggers for stranded asset recognition. ↩

33. 33

    Hoffart, F.M. and Holz, F. (2024). Energy asset stranding in resource-rich developing countries and the just transition. Frontiers in Environmental Economics, 3. doi:10.3389/frevc.2024.1273315. ↩

34. 34

    Jaffe, A.M. (2020). Stranded assets and sovereign states. National Institute Economic Review, 251, R25—R36. doi:10.1017/nie.2020.4. ↩

35. 35

    Monasterolo, I., Nieto, M.J. and Schets, E. (2022). The good, the bad and the hot house world: conceptual underpinnings of the NGFS scenarios and suggestions for improvement. SSRN Electronic Journal. doi:10.2139/ssrn.4211384. ↩

36. 36

    OSPAR Decision 2007/2 on the Storage of Carbon Dioxide Streams in Geological Formations. Principal OSPAR instrument permitting sub-seabed geological CCS storage. ↩

37. 37

    IEA. CCUS Projects Database (also accessible as the CCUS Projects Explorer). International Energy Agency. Cite most recent edition year at point of compilation. ↩

38. 38

    SDG Indicator 12.c.1. “Amount of fossil-fuel subsidies per unit of GDP (production and consumption) and as a proportion of total national expenditure on fossil fuels.” ↩

39. 39

    IRENA (2024). Renewable Power Generation Costs in 2023. International Renewable Energy Agency, Abu Dhabi. Offshore wind LCOE benchmarks by region. See also national CfD auction results (e.g., UK Low Carbon Contracts Company strike price registers) for jurisdiction-specific wholesale price references. ↩