Annex 1: Guide to Figures, Methodologies and Infrastructure Terminology

This annex serves as a reference for readers of the main report. It is in two parts. Part 2.1 defines technical terms used in the figures and analysis. Part 2.2 documents the methodologies and data sources behind the quantitative figures in the report. Readers may consult entries directly without reading the annex in order.

A1.1 Terminology

A1.1.1 Electricity: capacity, output and dispatchability

Unless otherwise stated, electricity figures in the report refer to actual generation output (e.g. TWh) rather than installed generation capacity (e.g. GW). The two terms are often used interchangeably in speech, but they measure different things.

Generation output. The amount of electricity generated in a reference period, typically a calendar year. For example, Denmark produced 35 terawatt-hours (TWh) of electricity in 2024.

Generation capacity. The amount of installed capacity available to produce electricity. For example, Denmark’s installed wind capacity in 2024 was 7.5 gigawatts (GW). Reported capacity may be nameplate (theoretical maximum if all units operated at their designed capacity) or operational (currently available for production). With rapid deployment of wind and solar, total capacity can change notably within a single calendar year, so the reporting convention should be confirmed when using capacity data.

Utilisation rate (capacity factor). The ratio of actual generation output over the theoretical maximum in the same period. It is an important indicator of generation performance.

Weather-dependent capacity. Generation capacity whose output depends directly on prevailing weather conditions. Low wind speeds or low solar irradiation can drop output close to zero regardless of installed capacity. The term usually excludes hydro, whose output is also weather-dependent but with a seasonal lag.

Dispatchable capacity. Generation capacity whose output can be controlled on demand and scheduled by system operators or market participants. Dispatchability matters because the grid must be balanced at all times: generation and consumption must always match. Typical dispatchable technologies are hydro reservoirs and gas turbines, and battery storage will increasingly contribute. Definitions are not always clear-cut. Run-of-river hydro provides less flexibility than reservoir hydro. Nuclear power is technically adjustable, but ramping is not instantaneous; in the Nordics it has traditionally been operated as must-run baseload, while in France (where nuclear supplies 64% of electricity) it has long been designed to follow load, increasingly so to accommodate the daytime solar peak.

A1.1.2 Electricity markets and grid geography

Several terms refer to different geographical units used in electricity markets and system operation. Some overlap, but they are conceptually distinct.

Bidding zone. The largest geographical area in which bids and offers from market participants can be matched without attributing cross-zonal capacity. Cross-zonal capacity is the maximum amount of electricity that can be physically transmitted between two bidding zones without overloading the grid, and is a key input to the price calculation algorithm. One country may form a single bidding zone (e.g. Finland, FI) or consist of several (e.g. Sweden, SE1–SE4). Sweden originally operated as a single price zone and was split into four in 2011 due to internal transmission constraints between the surplus north and deficit south. See ACER: bidding-zone review.

“Bidding zone”, “price area” and “market zone” are often used interchangeably but are not identical:

Bidding zone	Price area	Market zone
The official term in EU electricity market regulation; used by ENTSO-E and ACER.	Market-oriented term commonly used by Nord Pool. Refers to the same geographical boundary as bidding zone.	A generic term that may also refer to balancing areas, reserve procurement zones or capacity calculation regions consisting of several bidding zones.

Single Day-Ahead Coupling (SDAC). A pan-European day-ahead electricity market mechanism covering most of Europe, including the continental Nordic countries. It allocates scarce cross-border transmission capacity through a common algorithm that simultaneously accounts for transmission constraints, increasing liquidity and the efficient use of generation across Europe. SDAC transitioned from hourly to 15-minute bidding periods in 2025. See ENTSO-E: SDAC implementation.

Control area. A territory operated by a single transmission system operator (TSO), physically demarcated by metering points at the interfaces with the rest of the interconnected network. All physical loads and controllable generation within the area are connected to the TSO’s system. See ENTSO-E Operation Handbook glossary.

Synchronous area. A group of countries whose power systems are physically connected and share a synchronous system frequency (50 Hz in Europe, with minor deviations). A disturbance at any single point in the area is registered across the entire zone. Synchronous areas are interconnected through direct-current interconnectors. Notably, eastern and western Denmark belong to different synchronous areas.

Capacity calculation region (CCR). Defined by the EU Capacity Allocation and Congestion Management (CACM) Regulation 2015/1222 as a geographic area in which a coordinated capacity calculation is applied. CCRs are the set of bidding-zone borders for which TSOs coordinate capacity calculation. They are regularly reviewed to reflect new interconnectors, new bidding zones or new countries, and may overlap: Finland (FI) and southern Sweden (SE4) are part of both the Nordic and Baltic CCRs. Current CCRs are available in the ENTSO-E CCR map.

Regional group (RG). Bodies within ENTSO-E whose purpose is the reliable and efficient operation of the synchronous areas. RGs provide a framework for regional cooperation among ENTSO-E member TSOs. Up-to-date country lists for each RG are available at ENTSO-E system operations.

A1.1.3 Electricity system operators

Transmission system operator (TSO). The organisation responsible for transporting electricity at national or regional level using fixed infrastructure. The TSO is responsible for operational security within its control area, real-time operation and operational planning, prevention and remediation of disturbances, and procurement of services from third parties (redispatching, countertrading, congestion management, generation reserves and other ancillary services). The TSO also monitors and improves the tools needed to maintain operational security.

Distribution system operator (DSO). The organisation responsible for low-, medium- and high-voltage distribution networks and supply to lower-level distribution systems and directly connected customers. DSOs are typically natural monopolies overseen by national energy regulators. Their role has grown as more activity moves to the local distribution level, including active customers, self-generation, small-scale renewables, energy storage, power-to-heat and electric vehicles. The EU Clean Energy Package (2019) gave DSOs new responsibilities, including acting as neutral market facilitators in procuring energy to cover system losses, procuring non-frequency ancillary services, cooperating with TSOs to integrate connected market participants, publishing a transparent network development plan, and including demand response, energy efficiency and storage as alternatives to network expansion. See ACER: Clean Energy Package.

Significant grid user (SGU). A generation or demand facility deemed significant by the TSO because of its impact on the transmission system, including in terms of security of supply and ancillary services. SGUs must inform their connecting TSO or DSO of planned changes, tests and operational disturbances that could affect the grid, and must carry out compliance tests on request. Users providing demand response or reserves directly to the TSO must ensure compliance with the relevant regulations. See EU System Operation Guideline.

A1.1.4 Electricity interconnector infrastructure

The terms “cable”, “link” and “interconnector” are often used interchangeably. At a technical level they are not synonymous:

Cable	Link	Interconnector
The physical conductor that carries electricity (overhead or subsea). For example: “subsea cable”.	The functional connection between two nodes. A link may consist of one or several cables, converter stations and substations. For example: “HVDC link”.	A transmission connection between two separate electricity systems, bidding zones or countries (a strategic link). Typically includes cables, converter stations, grid interfaces and control systems.

Two interconnector technologies are in use: high-voltage alternating current (HVAC) and high-voltage direct current (HVDC). Both can be deployed as overhead or subsea cables. The main difference is that HVDC is independent of the frequency and phase angle of the AC system on either side.

HVAC. HVAC transmission has been used for decades and is efficient at reducing system losses at shorter distances. With the rise in weather-dependent generation, however, HVAC faces challenges including reduced transmission capacity, limited transmission distance, increased reactive power losses, and stability issues under faults and during transient conditions. HVAC operation also requires reactive power generation, and the non-controllable character of renewable generation affects the spinning reserves traditionally used for system balancing.

HVDC. Advances in power electronics have made efficient step-up of DC voltage possible, enabling HVDC systems suitable for long-distance transmission. The principal advantages over HVAC are that HVDC eliminates reactive power flow over the transmission link, supports higher power transfer for a given cable size, can interconnect asynchronous AC grids, and allows system operators to actively control power flow. After a break-even distance of 40–150 km for subsea cables and several hundred kilometres for overhead lines, HVDC becomes the more economical option, though break-even distances are highly project-dependent. HVDC technology has two main variants: Line Commutated Converter (LCC), a mature technology used for large bulk power transfer between strong AC grids, and Voltage Source Converter (VSC), a newer technology that can operate in weak or even passive AC systems, provide independent control of active and reactive power, and offer black-start capability. VSC is increasingly relevant for the Nordic system as wind expansion reduces system inertia. For detailed comparison, see ENTSO-E (2019), HVDC Links in System Operations.

A1.1.5 Oil refining metrics

Capacity. The maximum amount of inputs a refinery can process during a calendar year. Nameplate capacity refers to ideal operating conditions, without wear and tear. Operational capacity is the practical maximum accounting for equipment ageing, which is why older sources may quote higher figures than recent ones. There is no universal reporting standard. Nordic refinery operators use million tonnes of processed inputs per annum (Mtpa), thousand barrels per day (kbd) or tonnes per day. Conversion between them requires an assumption about the average density of the inputs:

capacity [Mtpa] = capacity [kbd] × 365 / density [barrels/tonne] / 1000

Many Nordic refineries have integrated liquid biofuel production, which adds ambiguity: reported capacity may refer to total liquids, only crude oil processing, or only biofuel production. Operators generally do not publish detailed capacity figures, citing commercial sensitivity.

Throughput. The actual amount of inputs processed in a given period, typically a calendar year. Throughput is always lower than capacity. Refineries are in principle in continuous operation, but planned maintenance and unplanned outages lower running time.

Utilisation rate. The ratio of actual throughput over operational capacity. In theory 0–100%, typically above 90%.

A1.1.6 Gas storage types

Underground gas storage. A suitable geological formation (e.g. impermeable) into which natural gas can be injected for seasonal storage. Gas remains in the gaseous state. In the Nordic region, such sites are operated by Gas Storage Denmark, with storage capacity of approximately 1 bcm.

LNG import/export terminals. Terminals include a short-term storage facility for liquefied natural gas. When liquefied, natural gas occupies 1/600th of its gaseous volume. Terminal capacities are nonetheless a fraction of seasonal underground storage. For instance, the Hamina LNG import terminal has storage capacity of 30 000 m³ LNG, equivalent to 18 million cubic metres (mcm) of natural gas in gaseous state.

Floating LNG storage (FSRU). A floating LNG terminal, in effect a marine vessel, has been operational in Inkoo, Finland since 2023. It can unload and load LNG vessels, store LNG, and regasify for redistribution to an inland pipeline. Storage capacity of the Inkoo terminal is 151 000 m³ LNG (approximately 90 mcm).

Part 2: Methodologies and data sources

This part documents the principal methodologies and primary sources behind the quantitative figures in the report. Entries follow the order in which the underlying figures appear in the report.

A1.2.1 National electricity demand scenarios

The country-level electricity demand projections in Section 5.1 are drawn from the most recent official scenarios published by national authorities or TSOs. Each source uses its own scenario methodology and assumptions, so cross-country comparisons should be read as indicative ranges rather than harmonised forecasts. The table below summarises the sources.

Country	Scenario source	Responsible body	Notes
Denmark	Climate Status and Outlook 2025 (Klimastatus og -fremskrivning 2025). Source	Danish Ministry of Climate, Energy and Utilities	Annual technical assessment of greenhouse gas emissions, energy consumption and production under a frozen-policy (“with existing measures”) scenario. Electricity-sector modelling documented in Danish: documentation. Datasheets available on the main report website.
Finland	Electricity system vision 2040. Source	Fingrid (Finnish TSO)	Biennial scenario-based analysis covering four pathways. The lowest-growth (“Voimaa vakaasti”) and highest-growth (“Vedystä valtavirtaa”) scenarios bracket the demand range used in the report. Scenario assumptions are documented in the report annexes (in Finnish). Datasheets not publicly available.
Iceland	Raforkuspá Landsnets fyrir 2024–2050 (Landsnet’s electricity scenarios 2024–2050). Source	Landsnet (Icelandic TSO)	Second edition. Four scenarios (“low”, “EU policy”, “government policy”, “high”) cover future supply and demand and the impact of the clean energy transition. Assumptions documented in the report (in Icelandic). Datasheet available on the report website.
Norway	Scenarios for the power market 2025. Source	Norwegian Water Resources and Energy Directorate (NVE)	Three scenarios: “basis” (baseline), “klimaplan” (planned government climate measures) and “klimatiltak” (all proposed climate actions). Based on NVE’s Long-Term Power Market Analysis 2025 (LA25). Assumptions documented in Norwegian. Datasheet available on the report website.
Sweden	Long-term scenarios 2025. Source	Energimyndigheten (Swedish Energy Agency)	Biennial study presenting four exploratory scenarios showing pathways to a net-zero energy system in 2050 and the following decade. Assumptions documented in Swedish. Datasheet available on the report website.

A1.2.2 Resource adequacy and Loss of Load Expectation (LOLE)

Adequacy modelling. ENTSO-E conducts an annual European Resource Adequacy Assessment (ERAA), which evaluates available resources against projected demand to identify supply-demand mismatch risks across scenarios. The ERAA-probabilistic methodology is considered the European reference for adequacy assessment, focused on the medium-term horizon and accounting for interconnections across the European perimeter. The model is a simplified representation of the pan-European power system, structured around five main elements: generation, demand, demand-side response, storage and network infrastructure. State-of-the-art adequacy studies use Monte Carlo simulation to capture system uncertainty, with results expressed as probabilistic indicators of adequacy under multiple plausible scenarios. Technical details and the full list of assumptions are in the ERAA Annex 2 Methodology document: ERAA 2025 methodology.

Loss of Load Expectation (LOLE). As part of the ERAA, LOLE is calculated for each bidding zone up to ten years ahead. The LOLE value is the expected number of hours per year in which generation resources are insufficient to meet demand. LOLE is a modelled probability of insufficient supply, not a prediction of actual blackouts. It does not capture the depth of any individual shortfall, but it is a useful comparative measure across years and zones.

Readers should always refer to the latest ERAA edition. Assumptions for a given target year can change rapidly from one edition to the next due to policy and system changes. For example, the cancellation of Hansa PowerBridge I between Sweden and Germany by the Swedish government in 2024 was not yet reflected in the 2025 ERAA, which assumed the link’s existence; post-2030 LOLE values for southern Sweden (SE4) in that edition may therefore underestimate adequacy risk.

A1.2.3 Oil product import dependency

Calculations in Section 7.3 use the Eurostat annual database for oil and petroleum products supply, transformation and consumption (nrg_cb_oil).

Demand by oil product is calculated as the sum of gross inland deliveries (code GID) and international marine bunkers (INTMARB). Gross inland deliveries cover uses in the transformation and energy sectors as well as final consumption (industry, transport, residential, services, agriculture and non-energy uses), including the “unspecified” category which captures military consumption where reported.

Total oil product demand is the sum of demand across all oil products used in the country. The share of each product in the total indicates its relative importance in the economy.

Net imports are calculated as imports (IMP) minus exports (EXP).

Import dependency by product is the ratio of net imports over demand. Two boundary cases require treatment to avoid confusion:

Negative values (net exporter) are set to 0, indicating the country is 0% import dependent for that product.
Values above 100% can arise from stock builds (which are excluded from the demand calculation). These are capped at 100%.

A1.2.4 Strategic oil reserve obligations

Strategic oil reserves serve as emergency stocks against supply disruption. Nordic countries are subject to two parallel obligation frameworks: the EU minimum stockholding rule and the IEA emergency reserve commitment. The two rules use similar inputs but differ in their reference units and calculation rules. The headline rules are summarised below; readers needing full technical details should consult the source documents linked at the end of this entry.

A1.2.5 EU obligation (Directive 2009/119)

EU countries must maintain oil stocks amounting to at least the greater of 90 days of average daily net imports or 61 days of average daily inland consumption. The 90-day rule generally applies to heavily import-dependent countries; the 61-day rule generally applies to those with significant domestic crude oil or oil shale production. The applicable reference is recalculated each July based on production and trade data for the previous calendar year.

The directive sets out detailed methods for converting petroleum product imports and consumption into crude oil equivalents (with naphtha-yield deductions and a 1.065 factor for non-naphtha products, or a 1.2 factor when applying the inland consumption method), and for counting eligible stocks (with a 10% reduction for tank bottoms and excluded categories such as pipelines, retail stations, military stocks and ships at sea). Full conversion factors, the list of products counted, and the eligible storage locations are set out in Annexes I–III of the directive: Directive 2009/119 (consolidated).

A1.2.6 IEA stockholding obligation

IEA member countries hold emergency reserves equivalent to 90 days of the previous calendar year’s average daily net imports. The obligation covers all petroleum (primary products and refined products), except naphtha and oil used as international marine bunkers. Refined products are converted to crude oil equivalent using factors broadly similar to the EU framework (a 4% naphtha-yield deduction on primary products, a 1.065 factor for refined products, or 1.25 if only the three main product groups—gasolines, middle distillates and heavy fuel oil—are counted). A 10% deduction is applied for unavailable stocks.

Days of net import cover is the ratio of emergency reserves over daily net imports. Full calculation details and notes on stocks held abroad are at IEA oil stocks of IEA countries.