Ei R2026-08 Förslag Centralt Datahanteringsverktyg (2026)

Förslag om ett centralt datahanteringsverktyg för elmarknaden (Ei R2026:08 / Svk 2025/5201), the joint report by Ei and Svenska kraftnät answering the government assignment of 18 September 2025 (Source - Uppdrag Centralt Datahanteringsverktyg (2025)). It is the final September 2026 report that the April 2026 consultation material (Source - Ei Förslag Centralt Datahanteringsverktyg (2026), Source - DHV Presentation 2026-04-27) was heading toward. It is a proposal from two agencies: nothing in it is decided, and all cost and time figures are indicative. The report runs to about 325 pages including three annexes; Annex 3 (comparison of other countries’ data tools) is not summarised here. See Centralt Datahanteringsverktyg for the synthesis. The report was handed to the government on 30 September 2026 according to Ei’s press release of that day (clipped, see the last section); the raw for the press release is the clipping in Raw/Clippings/, the raw for the report itself the placed PDF.

Core proposal

• A centralt datahanteringsverktyg (central data management tool, DHV) for the electricity market, with a flexibilitetsinformationssystem (FIS) integrated in or closely tied to it. Starting point is the current market model; no fundamental change of responsibilities is proposed (Sammanfattning).
• The tool consists of (1) databases with the information needed for the market to function, (2) the FIS, and (3) a technical platform for the information exchange between system operators and market actors and for the supervision, analysis and statistics that state agencies need (proposed 10 kap. 14 § elmarknadslagen).
• Functional parts (ch. 6.1): structure and register management (central register of metering points and installations in the concession-regulated grid; contracts and balance responsibility; meter values; eligible parties, registered customer representatives, energy-sharing and energy-community data; in FIS, the register of flexibility resources), market processes and coordination (metering-point registration, supplier switching, moves, terminations, validation of meter values from grid companies, release to parties according to contracts, consents and permissions), calculation and verification, and customer interface and permission management.
• Market-near grid settlement (nätavräkning) moves to the tool, including aggregated volumes per grid area, supplier and BRP and the basis reported to Nordic imbalance settlement at eSett Oy. The grid companies’ own technical settlement (losses, load analysis, planning) stays with them.
• FIS verification: calculation of reference profiles, comparison with actual measured outcome, aggregation of verified flexibility volumes. Verified volumes feed payment between the procuring operator and the flexibility provider, imbalance adjustment for the BRPs concerned, and compensation basis to suppliers where needed.
• What stays outside the system (ch. 6.4): actual prequalification still happens directly against the procuring party, bids are submitted outside the system, and financial settlement between flexibility provider and procuring party is outside it. The model also “creates conditions for” a flexibility provider to act without holding balance responsibility for the metering point.

Who does what (ch. 6.4)

Ownership and governance (ch. 7, 12.1)

• Svk is proposed to be responsible for providing and managing the tool, organised through a wholly owned subsidiary for operation, cybersecurity, development, budget and long-term management. Reasons given: a focus on retail-market needs separate from Svk’s transmission and system-operator role, separate accounting that eases supervision of the fee model, and specialised IT competence.
• A company co-owned with industry actors is judged less suitable: less freedom of action for Svk, harder decisions, more complicated supervision of a fee-financed activity, and (citing Norwegian experience) co-ownership often complicates cybersecurity and operations-critical issues.
• Ei would have a central steering role: it can issue regulations on the tool’s functions and decides the maximum revenue (below).

Financing (ch. 8, 12.5–12.7, 12.19)

• User-financed through fees; state agencies as a rule exempt from fees.
• DHV fees: an annual fee (all registered actors; account handling and support, not linked to metering points), a base fee (grundavgift; funds investment and costs already incurred for communication, preparatory work and change management) and a service fee (serviceavgift; funds running operation, per metering point, based on access to data and process logic and not on actual data retrieval). Grid companies pay for all metering points in their area, suppliers for metering points with active supply contracts, energy service companies for metering points where they hold consents. How the base fee is split between actors is left open and should be designed with industry when the tool’s scope is settled; the Elmarknadshubb-era proposal (grid companies by energy withdrawn, suppliers by active metering points) is named only as a possible starting point.
• FIS fees: flexibility providers bear part through a fee tied to active flexibility resources (registered, prequalified and available on one or more markets); grid companies bear part for functions used by local flexibility markets, so they are not charged for resources qualified only for Svk’s balancing markets. Svk, as transmission system operator, uses the same functions but is not charged (“established practice for authorities”). Design of the FIS fee basis is explicitly to be developed later, aiming for an essentially cost-neutral distribution where flexibility activation is concerned.
• Ei decides the maximum allowed revenue (högsta tillåtna intäkt) for a set period and how fees are distributed between users. The report says this is closer to economic regulation than to ordinary fee financing, and considers and rejects setting the fees by government ordinance (as for preparedness fees and the REMIT fee). It is described as a special cost-coverage regulation, not a revenue-cap regulation of the kind used for grid companies.
• Cost estimates (ch. 8.5–8.6): establishment costs at most about 100 MSEK per year; total investment 300–800 MSEK from initiation to go-live, the wide range explained mainly by how much Elmarknadshubb material can be reused. Running cost 100–150 MSEK per year including depreciation over an assumed 10 years, for an organisation of about 30 full-time staff; the report says long-term costs may exceed this. Annex 1 gives an establishment cost of 0.5–1 billion SEK, of which about 160 MSEK was already invested in the earlier Elmarknadshubb work. The two ranges are stated in different places and not reconciled in the parts read.
• The estimates are “indicative levels”, not fee levels or final economic terms.

Implementation and timeline (ch. 9)

• Staged: the first release covers the functions needed for basic information handling and market processes: installation and metering-point data, grid and supply contracts, meter values, supplier switching, consents and permissions, customer interface, and the settlement-related functions. Energy sharing, energy communities, flexibility and more advanced processes follow through further development. A binding deployment plan (driftsättningsplan) is to be set before go-live.
• Two strategic options: A, reuse-based development (Elmarknadshubb material: business processes, requirements, architecture, adapted to the current market model rather than the supplier-centric model they were designed for); B, development from scratch, either by procuring a commercial standard product (B1) or in-house by the subsidiary (B2). The report considers a large element of reuse both possible and appropriate in either case.
• Indicative schedule (months from the start, month 0 = initiation after government decision, not dated to a calendar year): A, go-live and stabilisation in months 36–42; B1 and B2, go-live in months 90–96. The schedules are not based on supplier quotes or procurements but on Elmarknadshubb experience and earlier plans. Main external dependencies listed: regulatory decisions, market actors’ readiness, IT complexity, procurement, staffing, testing and migration, and changes in politics or EU rules.
• DHV before FIS: the FIS cannot be fully developed and taken into operation until the DHV provides stable structure data, identities and interfaces; they should be developed jointly. Without reuse there is “greater risk of a time gap” between the network code’s implementation requirements and when the DHV can deliver what the FIS needs. A separate, strictly time-limited interim FIS solution is described as a second-best fallback (more cost, complexity and delivery risk).
• NC DR sequence: after entry into force, national procedure rules, supervisory decisions, national conditions and FIS specifications follow before pilot testing and later full operation. The DHV can be built without the flexibility rules being final; the FIS needs concretised national procedure rules, provider conditions, reference-profile methodology and functional requirements before development and fully fixed ones before go-live.
• Legal regulation divides in two levels: registry legislation and regulation of the deployment plan (before testing and migration), and regulations plus supplementary law changes (before go-live). Ei’s existing regulations on metering and reporting of transferred electricity assume decentralised information flows and will need adapting.

Legal proposals (Författningsförslag, ch. 12–13)

• New provisions in the electricity market act (elmarknadslagen, 2026:1281): 10 kap. 14–36 §§; changed 1 kap. 5 §, 10 kap. 3 § and 18 kap. 1 §. The chapter is renamed “Mätning av transporterad el och centralt informationsutbyte”.
• Holder of a transmission system (Svk) must provide and manage the tool (14 §). The government or a designated authority may issue regulations on storage periods, functions, and the obligation of system operators and market actors to supply information in the platform, and on the obligation of flexibility providers and system operators in flexibility markets to supply information in the FIS (15 §).
• Market actors and system operators must apply for registration as users of the platform (16 §); state agencies may be registered when needed for supervision, follow-up, review or statistics.
• Definitions: nätavräkningsområde (grid settlement area) defined in law; marknadsaktör (market actor) defined by reference to Art. 2.25 of the EU electricity market regulation. No definition of flexibilitetsleverantör is introduced, because the NC DR is not yet adopted; the term corresponds mainly to the NC DR proposal’s “service provider” (“a market participant with service providing units or service providing groups able to provide system operator services in a balancing or local market”).
• Regulation 2023/1162 roles (12.16): Svk takes the roles of meter data administrator, data-access provider and permission administrator; system operators keep the metering-point administrator role. Grid companies remain responsible for sending meter values into the tool.
• Secrecy and public-access rules: a new secrecy rule (OSL 31 kap. 10 a §) for information handling in the tool, with exceptions for registered users (10 b §) and for the data subject and official statistics (10 c §); Svk exempted from the registration duty under 5 kap. 1 § OSL for data in the tool so every entry need not be logged in the register.
• Entry into force: the day the government decides, with different provisions possibly at different times; the report argues a fixed date would either delay the reform or bring rules into force before the technology exists.
• Costs of making meter results available (12.15): the rule on these stays in the electricity market act (section not read in detail).

Benefits, risks and impact assessment

• Needs (ch. 3): simple access to meter values at low cost for all customers; a cost-effective transition through a more flexible system; a well-functioning market; better energy-system planning, analysis and total-defence preparedness; and conditions for future market development. Today’s grid companies differ widely in technical maturity, automation, cost levels and organisational capacity, and settlement disputes are increasing (ch. 2).
• Risks (ch. 5): a central tool concentrates large amounts of information and raises demands on security, access control, logging, incident handling, data minimisation and clear responsibility, including NIS2 and total-defence aspects; these are to be handled through legal, organisational and technical safeguards. The report also weighs the risks of keeping today’s order. Overall assessment: the benefits outweigh the costs and risks, provided implementation is staged and security, legal clarity and responsibilities are addressed. (Chapters 5 and 11 were read in summary form only.)
• Annex 1 (impact assessment): quantifies effects per actor as ranges of hours per company and MSEK per sector (for grid companies, for example, supplier switching 2–532 MSEK, consents/powers of attorney 4–511 MSEK, data access 1–80 MSEK and market-near grid settlement at daily resolution 16–82 MSEK; for suppliers, supplier switching 0–65 MSEK, consents 4–81 MSEK and meter-value distribution 0–144 MSEK; suppliers also face about 400–1,000 hours of system adaptation per system; customers, energy service companies, BRPs and producers are not quantified). The ranges are very wide and the assumptions behind them were not audited here.

Ei press release, 30 September 2026

Ei’s news item “Förslag: Inför ett centralt datahanteringsverktyg för elmarknaden” announces the report on the day it was submitted to the government. It adds little to the report but fixes a few points:

• Date: the report was submitted to the government on 30 September 2026.
• Proposal in brief: a central data management tool for the electricity market, possibly with system support for flexibility-related information and processes; Svk develops, operates and manages it, with costs covered by fees from the actors that use its functions; Ei gets a central role in steering and follow-up, including föreskrifter on the tool’s functions and review of the costs that may be financed through fees. The starting point is that the current market model is kept: the work concerned only a common system for data handling.
• Four function areas: basic data for a uniform market, market processes and coordination, calculation and verification, and customer interface and permission management.
• Consulted authorities (Svk’s Robert Thelander, acting section head): Integritetsmyndigheten, Myndigheten för civilt försvar, Försvarets radioanstalt, Säkerhetspolisen and Försvarsmakten, each for its own expertise, with privacy and security as a key part of the work. (The September 2025 government assignment names seven agencies, see Source - Uppdrag Centralt Datahanteringsverktyg (2025); the two lists are not identical.)
• Other countries: Norway, Finland, Denmark, Estonia and Austria were analysed. Centralised tools gave clear efficiency gains (standardised processes, better data quality, clearer responsibilities, more effective supervision and market monitoring) but bring considerable challenges in the development and migration phase; the tool is not only a technical solution and needs to be well prepared, staged and based on clear rules for all actors.
• Rationale (Ei’s Johan Carlsson, jurist and project lead): similar processes are handled differently by each grid company’s own systems, so the time and cost of obtaining meter values or other data can differ greatly for an electricity user or an energy service company; access to meter values is central to users controlling consumption or saving energy.
• History: the question was investigated before, including in 2017, when the proposal was combined with a supplier-centric market model; no such change is proposed now, but Ei and Svk judge that parts of the earlier work can still be used.

Relevance to wiki topics

• Replaces the “proposal due 30 September 2026” item in Centralt Datahanteringsverktyg: the proposal is delivered, the decision now rests with the government.
• For Network Code on Demand Response: confirms the FIS is sequenced after the DHV and names a possible gap to NC DR requirements if the tool is built from scratch.
• For Aggregation and BSP and BRP Roles: verified flexibility volumes, imbalance adjustment and compensation basis are produced centrally; BRPs get flexibility volumes reported separately.
• For eSett: the tool would compute the aggregated settlement basis reported to eSett Oy.
• For Distribution System Operator: a clear list of which DSO tasks cease, remain or are added.