Distribution Network Development Plan

A Distribution Network Development Plan (DNDP; Swedish: nätutvecklingsplan) is submitted to the national regulatory authority (Ei in Sweden) under Directive 2019/944 Art. 32(3)–(4). See FNA for how DNDP data feeds the national needs assessment.

The three planning pillars

Legal basis

Directive 2019/944 Art. 32(3):

• Biennial publication obligation
• Covers planned investments for the next 5–10 years
• Must include flexibility service needs and investment plans for essential distribution infrastructure
• Must be consulted with all relevant system users and TSOs
• Submitted to NRA alongside consultation results

NC DR Arts. 43–44 (near-final text, Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1)):

• Mandatory content requirement: planning framework, scenarios, investment plans, local services assessment
• Where local services are deemed relevant and cost-effective, DNDP must include: forecasted needs, cost-effectiveness methodology, and medium/long-term estimates with locational and time granularity
• Minimum 6-week public consultation (same requirement echoed in Source - ACER CEER DNDP Guidance (2025))
• NRA may request amendments; DSO publishes final version on website and central platform

ACER/CEER guidance (July 2025) recommends extending the horizon to at least 10 years and aligning DNDPs with TSO NDPs on timing. (Source - ACER CEER DNDP Guidance (2025))

The three-pillar planning process

ACER/CEER identify three essential steps in network planning, applicable to DNDPs — shown in the diagram above.

Pillar 1 — Scenario development: Projects possible futures for electricity demand and supply over 5–10+ years. Inputs: NECPs, TSO scenarios, municipal plans, local load data, EV/HP/battery forecasts. Multiple scenarios recommended to test resilience of investment plans. Scenarios should be coordinated with TSOs and aligned with other sector plans (gas, hydrogen, heating).

In Sweden, the national reference for this pillar’s demand/price trajectory inputs is Energimyndigheten’s long-term scenario work (BAS/NORM/HETS vs. the spring-2025 BP25 baseline). A June 2026 update (Source - Energimyndigheten ER 2026-20 Uppdatering Långsiktiga Scenarier (2026)) revised near-term assumptions upward: electricity prices now rise faster to 2030 than in BP25 (slower onshore wind buildout against still-rising, industrial-electrification-driven demand), easing again after 2035 as new nuclear capacity is now assumed to arrive on a fixed schedule from 2035 rather than purely endogenously. Only the high-growth NORM scenario (350 TWh demand) justifies offshore wind and further new-nuclear investment — a useful upper-bound reference for high-growth DNDP scenarios.

Pillar 2 — Grid capacity needs identification: Determines where and when additional grid capacity is needed. Builds on existing grid + scenario projections. Typically uses load flow simulations. Applies technical constraints: N-1 criteria, operational transfer limits, quality-of-supply indicators (SAIDI, SAIFI). Outputs: congestion maps, capacity gap forecasts, connection queue data.

Pillar 3 — Project identification and selection: Develops the optimal solution to each identified need. Solutions include: grid reinforcement (new/upgraded lines, substations, transformers) or non-wire alternatives (flexibility procurement, Villkorade Avtal, storage). Cost-effectiveness analysis determines the preferred option.

CEER’s 2026 smart-grid performance indicators paper extends this three-pillar frame into a broader “triptych” for NRA oversight purposes: the DNDP (scenarios + methodology + project portfolio) is joined by a business plan (a TOTEX view of the resulting network action plan, covering infrastructure and non-infrastructure/flexibility alternatives alike) and a performance evaluation framework (the output/input indicators — see Digitalization and Smart Grid) that links DNDP objectives to concrete, monitorable metrics. (Source - CEER Electricity Smart Grid Performance Indicators (2026))

Required DNDP content

Based on the NC DR (Arts. 43–44) and ACER/CEER guidance, a comprehensive DNDP covers:

1. Current state of the distribution system

• Network infrastructure: line lengths (HV/MV/LV), substations, voltage levels, geographic area
• DER presence: distributed generation capacity (wind, solar), smart meter deployment
• Ownership and regulatory framework
• Relationship to other planning documents

2. Planning assumptions and scenarios

• Methodology and assumptions documented
• Aligned with NECPs and TSO scenarios (translated to local level)
• Local specificities: connection requests, EV/HP deployment, municipal plans
• Multiple scenarios spanning the planning horizon
• Scenarios for flexibility options considered alongside generation and consumption

3. Flexibility needs assessment (mandatory where relevant)

Where local services are deemed relevant and cost-effective:

• Direction of the need (upward or downward)
• Location and voltage level (preferably disaggregated per voltage level)
• Time of use (preferably hourly time-blocks; yearly minimum)
• Contractual arrangements planned: market-based flexibility or flexible connection agreements
• Competing reinforcement alternative and cost-effectiveness analysis supporting the chosen option

This section must comply with the FNAM’s Tabell 15 template (from ACER Decision 05-2025 Annex 2) — the same data format used in the FNA process. (Source - ACER CEER DNDP Guidance (2025), Source - FNA Bilagor I-V (2025-2026))

4. Planned investments and projects

• Investment programs by category: grid reinforcement, DER connection, resilience, modernization
• HV projects: full detail (description, location, technical specification, status, expected commissioning, estimated costs)
• MV projects: aggregated by program type; more detail adds value
• LV projects: aggregated
• Worksheet format and unique project coding recommended
• Smart grid, SCADA/ICT, digital twins, cybersecurity included as project categories

Relationship to FNA and NC DR

The DNDP is the central node in the three-way FNA–DNDP–NC DR linkage — FNA feeds the NC DR Art. 29.1 biennial assessment, which in turn is used to fulfill DNDP obligations. See Flexibility Need Assessment › NC DR Art. 29.1 — the three-way FNA-DNDP-NC DR linkage for the diagram.

ACER/CEER (2025) explicitly states: “DNDPs are the primary source of DSOs’ data and analyses” for the FNA. The DNDP flexibility section and the FNA reporting tables should use the same underlying data and methodology. (Source - ACER CEER DNDP Guidance (2025))

NC DR Art. 31.1: When assessing flexibility needs in the DNDP and FNA context, flexible connection agreements (Villkorade Avtal) must be treated as firm connections — the full underlying grid constraint must be reported, not a reduced figure because some capacity is already contracted. (Source - FNA Webinar 7 (2026-03-16))

Anticipatory investments

A key concept endorsed by the EU Grid Action Plan (COM/2023/757, 2023) (which points to the then-pending EMD reform proposal and commits to guidance under its Action 4) and codified in the EMD Reform 2024: investments sized for expected future needs rather than just current connection requests. The principle:

• Distribution grids should not become bottlenecks in the energy transition
• Earlier investment can avoid costlier later upgrades and accelerate RES connection
• DNDPs should flag which projects are “anticipatory” — enabling market participants to see where future grid capacity will be available ahead of actual requests

The EU DSO Entity’s 2024 Technical Vision reinforces this: it advocates for DNDP planning horizons of 10–20 years (vs the Directive’s minimum 5–10 years) and calls for EU-level harmonization of DNDP definitions and methodologies to improve planning coordination across member states. The Vision’s formal definition: “Anticipatory investments result from planning aimed at identifying investments that proactively address expected developments, looking beyond immediate needs of generation or demand into the mid and long-term. The planning should consider new generation and/or demand that will materialize with sufficient certainty, even while utilization could be low in the short term.” (Source - EU DSO Entity Technical Vision (2024))

The EC-commissioned comparative study (Fraunhofer ISI, August 2025) provides the most recent EC-level formal definition: “investments into grid infrastructure assets that proactively address network development needs beyond the ones corresponding to reinforcements relating to currently existing grid connection requests, that are justified in network development plans.” The study also confirms that Ireland is the EU best-practice example for performance-based regulatory incentives encouraging cost-effective (including non-wire) solutions, and that TOTEX is the key structural reform for eliminating CAPEX bias — validating Ei‘s RP5 direction. (Source - EC Study Distribution Grid NDP Tariffs and Connections 2025)

Links to Sweden’s Svenska kraftnät NordSyd program and to the TOTEX/lösningsneutralitet reform at Ei — the regulatory incentive structure must not penalize anticipatory flexibility procurement (wiki inference; not stated in the DSO Entity good-practices guide).

Anticipatory investment is a legal obligation under Swedish law: Ei’s ställningstagande Ei2025:03 (Source - Ei Ställningstaganden Anslutningsprocessen (Ei2025-02 till 05)) makes explicit that proactive investment is not merely good practice — it is required by the combination of 3 kap. 1 § (efficient and safe grid operation), 4 kap. 1 § (connection obligation), and 4 kap. 5 § ellagen (maximum two-year connection time). A DSO that waits for formal applications before investing may already be in breach of its connection obligation by the time demand materializes. The DNDP — as the statutory planning instrument — is the primary vehicle for documenting and operationalizing anticipatory investment decisions.

Capital base conditionality and the 5 kap. 7 § safety valve: Anticipatory investments face a cost-recovery tension: assets enter the capital base only when used during the supervisory period (Förordning (2018:1520) om intäktsram, 2 § and 6 §). A proactively built asset not yet in service cannot be recovered. However, 5 kap. 7 § ellagen provides a skälighetsbedömning mechanism through which Ei may allow capital base inclusion before full use if circumstances justify it — intended as the escape valve for genuine anticipatory investment.

Sweden

Sweden has >100 DSOs and operates distribution grids up to 220 kV. Ei is the supervisory NRA. Key features:

Portugal is currently the most advanced EU country for DNDP flexibility quantification, using probabilistic analysis and cost-benefit comparison of flexibility vs. reinforcement — a model Sweden could follow. (Source - ACER CEER DNDP Guidance (2025))

Swedish legal chain: The complete statutory basis for Sweden’s DNDP obligation runs:

(Source - Ellag (1997-857), Source - Förordning (2022-585) om elnätsverksamhet, Source - EIFS 2024-1 Nätutvecklingsplaner (konsoliderad))

Note: §14a of Förordning (2022:585) (added by SFS 2025:272) provides the statutory mandate for Ei’s DNDP map visualization tool and for the PM2025:03 synthesis publication. Prior to this provision, Ei’s DNDP aggregation activities lacked an explicit legal basis; §14a created it retrospectively.

From 2027-01-01: förordning (2022:585) is repealed and the DNDP rules move to 2 kap. 9–13 § of the elsystemförordning (2026:1522): a plan must state the medium- and long-term need for flexibility services, planned investments over 5–10 years, and the resources used as alternatives to grid expansion; DSOs consult TSOs and affected users and publish the responses; Ei compiles the plans and publishes the content on its website (2 kap. 12 §, the counterpart of today’s §14a). The delegation chain in the diagram above is the one in force until then. (Source - Elsystemförordning (2026-1522))

Swedish DNDP template: Ei has issued both a common template and binding guidelines under EIFS 2024:1 (Source - EIFS 2024-1 Nätutvecklingsplaner (konsoliderad)). The regulation mandates: (a) use of Ei’s prescribed template (§ 4.1); (b) capacity forecasts in MW per year per delområde (§ 4.7); (c) explicit MW quantification of flexibility service needs on a 5–10 year horizon (§ 4.12); (d) adequacy assessment (§ 4.14); (e) a minimum 6-week consultation with a preliminary plan published by 15 September (§§ 6.1–6.2); and (f) submission by 31 December (§ 7.1). The regulation defines medellång och lång sikt as 5–10 years, delområde as a geographically bounded sub-area, and konsoliderad version as the original plan with all amendments incorporated. Svenska kraftnät‘s transmission network development plan (NUP 2026–2035, Source - Svk Network Development Plan 2026-2035) is the TSO-level complement; DSO DNDPs should be coordinated with it.

EIFS 2026:4 — amendment in force 30 April 2026: Source - EIFS 2026-4 Ändring i EIFS 2024-1 (2026) restates several provisions of EIFS 2024:1 for the next DNDP cycle (plans covering 2027–2036, due 31 December 2026). Ei’s own news item describes the mandatory reporting system as the main change and the rest as minor clarifications of existing provisions; the new elements are marked below.

• Digital submission (new 1 kap. 4 §): DSOs must submit via Ei’s designated IT system
• Six-item methodology (updated 4 kap. 8 §; the item on actual load and diversity effects is new, the list had five items): assumptions, actual load and diversity effects, demand drivers, municipal/regional plans, cooperation with other grid companies, long-term national energy system development
• Historical comparison (updated 4 kap. 9 §): percentage increase or decrease of the forecast need versus recent historical years, per forecast year (and per delområde where the grid is divided); otherwise qualitative
• Flexibility service use documentation (4 kap. 10 §, unchanged in substance from the original): the capacity analysis specifies current use of flexibility services as alternatives to grid investment (type and extent), alongside current and future capacity constraints; the amendment only adds that a constraint may be in the own grid, the overlying grid or both
• Investment reporting basis (updated 4 kap. 11 §): planned 5–10 year investments are based on the 7 § capacity forecasts; new is that each project also states its main purpose and a project description
• Consultation account (updated 6 kap. 3 §): the plan must itself describe how and over what period the consultation was carried out; the views are compiled in a separate samrådsredogörelse (still published and submitted alongside the plan under 7 kap. 1 §)

Transition: the old EIFS 2024:1 rules apply to plans covering the 2025–2034 period; the amended rules govern later plans, i.e. the 2027–2036 cycle. The provision most relevant to the flexibility domain remains the requirement to document existing flexibility service use in the capacity analysis (4 kap. 10 §, already in the original), a systematic evidence base for the FNA pipeline; the newly added 4 kap. 8 § item on actual load and diversity effects links the forecast method to the faktisk belastning approach.

Second-cycle reporting route: Ei opens a new e-service for DNDP reporting on 2 November 2026, replacing the earlier route; plans for 2027–2036 are due by 31 December 2026. Companies upload the plan and the consultation report as PDFs and attach maps as shapefiles, can save drafts and resubmit until the period closes, and log in with BankID (signatories assign reporter permissions beforehand). Ei says the structured data should be more usable by county administrative boards, municipalities and flexibility service providers, and only what is reported in the e-service feeds Ei’s DNDP map service (Source - Ei Nätutvecklingsplaner E-tjänst (2026)). The e-service is presumably the designated IT system the new 1 kap. 4 § of EIFS 2026:4 refers to; Ei’s news item does not state the link.

Key gap: Sweden’s DNDP first round specified flexibility in only one direction. The FNAM Tabell 15 v1.03 reporting template already requires both directions from FNA 2026 (obligatory ↑ uppreglering and ↓ nedreglering rows per target year/season; Source - FNA Bilagor I-V (2025-2026)) — so the next DNDP cycle (2027–2036, due 31 December 2026) will need to align its flexibility section accordingly. This is an FNA 2026 requirement, not an FNA 2028 one as earlier assumed.

First-round synthesis — Ei PM2025:03 (March 2025)

Ei published its official synthesis of the first round of DNDP submissions in Ei PM2025:03 (13 March 2025), covering 152 of the 155 DNDPs eventually submitted. (Source - Ei PM2025-03 DNDP Sammanställning (2025))

Ei categorized companies into four size groups (small <10,000, medium 10,000–100,000, large >100,000, production networks) — see Distribution System Operator › Swedish DSO landscape for the full breakdown. The six large DSOs account for approximately 61% of all Swedish customers.

Four multi-area companies span multiple elområden and are reported separately: Vattenfall Eldistribution, E.ON Energidistribution, Ellevio, and Skellefteå Kraft Elnät. These four represent approximately 50% of all Swedish customers.

Capacity forecasts: ~90% of companies forecast increased capacity needs for 2025–2034 (serving ~100% of customers); separately, 100% of large companies report needing capacity-raising actions to meet the forecast. Top drivers: EV charging (~60% of companies, ~90% of customers), punctual loads such as industry and data centers (~50%, ~85%), production installations (~35%, ~70%).

Flexibility use and need:

• ~20% of companies currently use flexibility services — but these represent ~70% of customers (dominated by large and medium-large DSOs). All six large companies use flex services; only ~10% of small companies do.
• Aggregate projected flex need (companies reporting combined consumption+production need, Tabell 7, 122–127 companies, ~60% of customers):

• Three companies reporting separately by direction (Tabell 8, ~20% of customers):
  • Consumption: 301–346 / 821–1,092 / 0–1,688 MW
  • Production: 2,462–2,572 / 2,110–2,550 / 6–2,948 MW (very high production figures reflect DSOs with large renewable generation portfolios)

Tool mix (among companies reporting tools): ~40% mention villkorade avtal or bilateral agreements; ~20% use or plan battery storage; ~15% are considering creating or participating in a flexibility market; ~40% mention effekttariffer; 5 companies used omdirigering (redirection) in 2023.

Adequacy: >80% of companies say planned actions will be sufficient for their own grid — but these represent only ~55% of customers. ~50% flag overlying network constraints as a potential barrier (representing ~80% of customers). All four multi-area companies flag overlying constraint risk.

Ei’s forward agenda: Ei is developing a map-based visualization of DNDP content (IT development phase due 31 August 2025). Ei has proposed that the förordning om elnätsverksamhet be amended to give Ei bemyndigande (authority) to prescribe standardized structured data reporting for DNDPs — without it, aggregation and visualization are limited by inconsistency. Ei will conduct tillsyn (oversight) of DNDP compliance during 2025. Next DNDP cycle: all companies must submit by 31 December 2026 (starting the 2027–2036 planning period).

Methodological note: Ei acknowledges significant limitations — different reference years, accumulated vs incremental reporting, inconsistent load diversity assumptions, and “considerable uncertainty intervals” in all aggregate numbers. These limitations drive the case for bemyndigande and for the FNA 2026 FNAM methodology.

For per-company DNDP profiles — Vattenfall Eldistribution, Ellevio, E.ON Energidistribution, and GENAB — and Skåne regional cross-DSO findings, see Swedish DNDP First Round — DSO Profiles (2025-2034).

DNDP forecasting and automation

Digitalization and automation of DNDP production

Energiforsk 2024:1043 (Source - Energiforsk 2024-1043 DNDP Analys och Flexibilitet (2024)) provides the most detailed published analysis of the current state of DNDP production workflows and where digitalization effort yields the highest return.

International benchmarks: Interviews with UK and Portugal DSOs (which have among Europe’s most mature DNDP practices) show that Excel dominates DNDP work in both countries, creating problems with version control, documentation, and knowledge transfer. FTE burden: approximately 1 FTE per 40,000–80,000 grid connections for DNDP production and maintenance — a significant ongoing cost for medium and large DSOs.

Automation index: The report proposes a framework that scores each DNDP sub-task on (a) resource intensity and (b) automatability. The flexibility need forecast scores index 9 (the maximum) — it is simultaneously the most time-consuming sub-task and the most amenable to automation given that inputs (load data, EV scenarios, network topology) are machine-readable and outputs (MW × hours by location) are well-defined.

“What-if” flexibility forecasting method: Rather than producing a single point estimate of flexibility need, the report proposes explicit behavioral scenarios for EV charging:

(Two case studies — one using a Stockholm-local hourly load profile, one using a generic SE3 profile; figures illustrative of method, not validated forecasts)

Using the Stockholm-local profile alone, the range is ~19.5× in peak kW and ~71× in duration — figures from the two profiles should not be blended into a single range. The range still shows that behavioral assumptions dominate the flexibility need answer — more than any technical modeling choice. The report argues that publishing scenario assumptions alongside forecasts, rather than a single number, allows municipalities, customers, and aggregators to form their own views on plausibility and is both more honest and more practically useful.

Cost benchmark: Capacity upgrade alternative ≈ ~4 SEK/kW (transformer upgrade, 50-year lifetime). This is the reference value against which flexibility service costs should be compared at the DNDP project selection step (Pillar 3).

National forecasting standardization

Energiforsk 2026:1157 (Source - Energiforsk 2026-1157 Nationell Metod Effekt och Kapacitetsprognoser (2026)) documents the sector-wide forecasting capability gap and proposes a national top-down method to address it. This project was led by AG Kapacitetsprognoser (Energiföretagen) with input from the largest Swedish DSOs and Svenska kraftnät.

Scale of the problem: A survey of 50 DSOs combined with interviews with six major actors (E.ON, Vattenfall, Ellevio, Göteborg Energi, Öresundskraft, SvK) found:

• 28% of DSOs lack any documented forecasting methodology
• 40% lack documented power templates
• 36% do not validate systematically against actual outcomes
• Several DSOs note their forecasts have systematically overestimated actual power needs — creating upward bias in investment decisions
• Methods, definitions, and data sources vary so much that DNDPs are not comparable between companies — preventing national aggregation

This directly explains why Ei‘s PM2025:03 synthesis of 152 first-round DNDPs carried “considerable uncertainty intervals” and could not produce consistent aggregate numbers: the underlying inputs were not produced on a common methodological basis.

Top-down method: The national method uses only official, recurring, nationally published data sources (Energimyndigheten scenarios, SCB population statistics, Trafikverket traffic data). This ensures that all DSOs using the method start from the same national assumptions, producing comparable and traceable outputs. The method produces national totals → geographic breakdown to county/municipality level. Worked examples: rooftop solar PV and home EV charging.

Key limitations: The top-down method cannot capture local point loads (large industrial connections, data centers), connection queues, or municipal development plans. These must be added as bottom-up supplements by individual DSOs — the national method provides the baseline, not the complete picture.

Relationship to DNDP regulation: The report’s standardization agenda directly supports Ei’s proposed bemyndigande (authority) to prescribe structured DNDP data reporting. Without standardized methodology, Ei cannot compile meaningful national aggregates; with it, the DNDP/FNA reporting chain becomes a genuine policy instrument. (Source - EIFS 2024-1 Nätutvecklingsplaner (konsoliderad), Source - Ei PM2025-03 DNDP Sammanställning (2025))

Data platform (Phase 2): A conceptual MVP (Minimum Viable Product) data platform is designed — data catalog with FAIR metadata, open API, basic visualization. Phase 2 will build the MVP and establish governance. Long-term: the platform could support a national capacity map following Netherlands (tennet.eu) and Norway (wattapp.no) models.

European landscape

From the DSO Entity survey and ACER/CEER NRA questionnaire, the EU DNDP landscape is highly heterogeneous:

Portugal is the EU reference case for advanced DNDP flexibility quantification — including the FIRMe reserve price methodology, probabilistic planning, and ERSE opinion authority (may determine amendments). See Portuguese DNDP — PDIRD-E 2024.

Relationship to other wiki concepts

• Flexibility Need Assessment: DNDP is the primary data source for the FNA; same Tabell 15 template
• Flexibility Market: DNDP documents forecasted flexibility needs that inform local market design
• Villkorade Avtal: DNDP must specify contractual arrangements for flexibility, including flexible CAs; CAs counted as firm connections in DNDP needs assessment
• Network Code on Demand Response: NC DR Arts. 43–44 formalize DNDP content requirements; Art. 29.1 biennial assessment uses DNDP to fulfill Directive Art. 32(3) obligations
• Congestion Management: DNDP identifies congestion forecasts and planned solutions
• Ei: supervisory authority; issues template, guidelines; central publication platform
• Svenska kraftnät: TSO NDP (NUP) coordinates with DSO DNDPs
• Swedish DNDP First Round — DSO Profiles (2025-2034): per-company DNDP profiles from the first mandatory round and Skåne regional cross-DSO synthesis

Load forecasting in DNDP

DNDP load scenarios are built on medium- and long-term load forecasting (MTLF/LTLF). A dedicated Energiforsk project (Source - Energiforsk 2026-1157 Nationell Metod Effekt och Kapacitetsprognoser (2026)) developed a national method for effekt (peak demand) and capacity forecasting specifically for DNDP needs — covering the local distribution grid level and accounting for EV penetration, heat pump deployment, and electrification of industry. This is the DNDP-relevant forecasting layer; the operational STLF layer used for day-ahead BRP and FSP market participation is conceptually distinct. See Load Forecasting for the full horizon taxonomy and how the different layers connect.