Declared vs. Delivered — How Much DNDP Flexibility Need Becomes Procured Flexibility

Sweden’s first mandatory nätutvecklingsplaner (2025–2034) gave the country megawatt figures for how much flexibility each DSO expects to need: 277–1,030 MW nationally within two years by Ei‘s synthesis, ~700 MW and ~1 TWh per year for E.ON alone. Two winters of market data and the second-cycle plans (2027–2036) now make it possible to compare those declarations with what was actually procured. Every live Swedish local flexibility market combined has prequalified on the order of 100 MW, and E.ON’s markets activated 1,400 MWh in 2025/26, about a thousandth of the energy the 2025–2034 plan declared.

The gap is real but mostly structural. A DNDP flexibility need is the size of a grid constraint, not a statement of how much a DSO intends to buy; the plan’s own investment tables are how most of it gets closed. The FNA 2026 final report makes the point directly: DSOs reported no unmet distribution-level flexibility need, because they expect existing resources and planned grid investment to cover what they identified. The realization rate of a market is therefore bounded above by the share of the need a DSO ever meant to route through it, and that share was rarely stated. (Source - Svk FNA 2026 Slutrapport (2026))

Where a cold winter tests a constraint before the reinforcement arrives, the gap stops being an accounting artefact. Winter 2025/26 is the case: E.ON’s realized need in Södra Skåne reached ~12,000 MWh and its market supplied 3% of it, while Kinnekulle Energi‘s small market made its largest call-off of the season in the week after weekly peak demand reached its subscription ceiling. The causes of thin markets are treated in Why Swedish Local Flex Markets Are Thin — Structural Causes and the declarations themselves in Swedish DNDP First Round — DSO Profiles (2025-2034).

What is being compared

A DNDP need is a gross constraint. Under EIFS 2024:1 § 4.12 a DSO reports, in MW per delområde on a 5–10 year horizon, the gap between forecast load and the applicable capacity limit. E.ON’s method is explicit: the gap between forecast and N-1 capacity at each fördelningsstation on a cold-winter peak. NC DR Art. 31.1 then requires capacity already contracted under villkorade avtal to be treated as firm, so the reported figure cannot be netted down by existing contracts. (Source - E.ON Nätutvecklingsplan 2025-2034, Source - FNA Webinar 7 (2026-03-16))

“Procured” has three tiers. Capacity prequalified or contracted (MW); availability reserved and paid for (MWh of availability-hours); energy actually activated (MWh). Market reporting headlines the last, which is also the smallest. Setting declared MW against activated MWh is comparing the size of an insurance policy with the claims paid out under it, so the tables below keep the tiers apart.

Units and horizons differ. Most DSOs declared only MW. E.ON and GENAB also declared energy, and GENAB alone declared hours and occasions per year. DNDP horizons run 0–2, 3–5 and 6–10 years from 2025; the FNA uses 2030 and 2035; markets report by winter. The tables use the 0–2 year DNDP figure where one exists, labelled otherwise, against the 2024/25 and 2025/26 seasons.

Capacity ledger (MW)

The national ratio depends on both ends of the fraction. Taking prequalified capacity as on the order of 100 MW against the first DNDPs’ near-term PM2025:03 range, it is roughly a tenth of the 1,030 MW upper bound, a third of the 277 MW lower bound, and a sixth of the midpoint; the 2025/26-only sum of ~95 MW, with E.ON at its 67.5 MW season figure, is on the same order. Effekthandel Väst’s jump from ~20 MW of registered capacity to >70 MW tradeable within two seasons is itself unexplained in the sources, beyond the ~30 FSPs now on the platform. Ei attributes considerable uncertainty in the PM2025:03 range to inconsistent reporting methods across DSOs (differing reference years, accumulated versus incremental need), which is what the FNA’s standardized template fixes: against the FNA 2026 target-year figure, today’s ~100 MW is closer to a fortieth of the 3,691 MW declared for 2030, but the two aren’t measuring the same horizon — the FNA figure is a fixed target year eight winters out, not a 0–2 year band, so a small ratio there says less about today’s market than the PM2025:03 comparison does.

Energy ledger (MWh)

Finding 1 — need shrinks by an order of magnitude between the plan and the market

E.ON is the only DSO where every tier is public. Its second DNDP is the fairer starting point, since it isolates the lokalnät need (~340 MW of upregulation by 2036) that local markets could in principle serve; the first plan’s ~700 MW included regionnät need that E.ON now says it cannot quantify with confidence and that no local market was designed for. Against 340 MW, the ~71.5 MW E.ON stated as market need for 2025/26 is 21%, and prequalified supply of 67.5 MW is 20%. Against the older 700 MW both figures are about 10%. (Source - E.ON Nätutvecklingsplan 2027-2036 (Preliminär), Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025), Source - BeFlexible Technology Booklet (2026))

The order of magnitude goes missing between the plan and the market, not between the market and its suppliers. Prequalified capacity for the season, 67.5 MW per the BeFlexible Technology Booklet, came to about 94% of the ~71.5 MW stated market need, a per-area sum from FlexAbility’s October 2025 report. The 25.2 MW prequalified and 59.5 MW need in BeFlexible’s D5.2 were preliminary figures compiled before the season closed and are not final; the 42% ratio they gave is not the season’s outcome. On the trading side, supply is therefore close to the stated need. The large step is upstream: the ~71.5 MW E.ON stated as market need is about a fifth of the ~340 MW lokalnät need in its plan. The rest of the constraint sits on the investment side of the plan.

On the energy side the same funnel is steeper, and the cold winter made it measurable.

Against a declared ~1 TWh per year, E.ON’s markets activated 140, 466 and 1,400 MWh in successive seasons, a ten-fold rise that still lands at ~0.14%. But 2025/26 was the first cold winter since the plans were filed, and E.ON reported realized need in Södra Skåne alone at ~12,000 MWh, with the majority of need unmet on 10 of 11 markets after every available bid was dispatched and three markets with no active suppliers. Södra Skåne’s ~408 MWh of activation met about 3% of what the operator says it needed. The declared county upper bound of 66,000 MWh was not fantasy: the winter realized roughly a fifth of it in one market area, and the market supplied a thirtieth of that. (Source - E.ON Webinar Lokala Flexibilitetsmarknader 2026-2027 (2026), Source - SWITCH CSV Exports V2025-26 (2026), Source - E.ON Nätutvecklingsplan 2025-2034)

Finding 2 — two markets sit inside their declared need, and both declared something operational

Two DSOs have markets whose outcomes sit inside their declared need, and both declared something closer to an operational quantity than a planning envelope. The sample is two, and one of the two bands has a lower bound of zero, so this is an observation rather than a demonstrated cause.

GENAB’s DNDP quantified need in MW, GWh per year, hours per year and occasions per year, on the reasoning that MW sizes a resource while hours and occasions decide which product to buy. For Area A it declared 0–5 GWh and 0–140 hours per year on the 0–2 year horizon. Göteborg’s own activation in 2025/26 was ~1,216 MWh; the combined Effekthandel Väst figure, which includes Mölndal’s grid, was ~1,213 MWh in 2024/25 and ~1,746 MWh in 2025/26, ShortFlex plus MaxUsage in both seasons (NODES public market statistics, retrieved 2026-10-10). A band that starts at zero makes “inside the band” a weak test, but Göteborg’s own 1,216 MWh is about a quarter of the band’s ceiling, and the ceiling assumes every planned industrial connection in Area A lands on schedule. (Source - GENAB Nätutvecklingsplan 2025-2034 (2024), Source - Webinar Effekthandel Väst Säsongsuppstart (2026))

Kinnekulle never filed an energy figure, but its need is a single subscription ceiling against Ellevio’s regional grid and the market was sized to it. A hindcast of 2024 found 31.5 MWh of excess energy above the ceiling and a worst hour of 5.4 MW; the 5.28 MW contracted for 2024/25 would have covered every hour but one. In weeks 7 and 8 of 2026 weekly peak demand reached the ~60 MW ceiling (~61 and ~60 MW), and the season’s largest call-off (~65–67 MWh) followed in week 8. The 135 MW projected for 2028 makes today’s 5.28 MW look like 4% (7% of the ~75 MW gap above the ~60 MW ceiling), but the part of the constraint a given winter has actually produced has been met. (Source - Flexsäsongen i Götene 2024-2025 Sweco, Source - Kinnekulle Energi Marknadsdata Web 2025-2026)

The obvious confounder is scale: one constrained city area or one subscription point, against a 15-county N-1 envelope. Whether GENAB’s second-cycle plan keeps the hours-and-energy quantification, and whether E.ON’s lokalnät-only figure narrows the gap further, are the two things that would turn this observation into evidence either way.

Finding 3 — most delivered flexibility leaves no market statistics

Counting only market activations makes the realization gap look like a supply failure. Widening “procured” to every channel a DSO uses shows flexibility being delivered through instruments that produce no market data, and it shows the channel comparison is not one of like with like.

Ellevio reported 220,150 MWh of redispatching for 2024, 99% of all Swedish DSO redispatching, mainly hydro and wind under production agreements (nationally, redispatching was ~91% hydro, ~7% wind and ~2% demand response). Its single 320 MW produktionsgaranti was activated twice at 150 MW. The cause matters: Ei’s report attributes the volume to avoiding overload during ongoing regional-grid works, a construction-outage event tied to an investment programme, not a response to the load-growth constraint the DNDP quantifies. It is not comparable to a demand-side activation at 5,800 SEK/MWh, and it does not mean Ellevio’s declared need is being met by flexibility. What it does show is that the largest flexibility volumes in Sweden move through bilateral production contracts that never appear in a market ledger, on a DSO that runs no market. (Source - Ei R2025-13 Omdirigering i Sverige 2024, Source - Ei SGI Data 2023-2024)

The same holds by company count. Ei’s smart-grid indicators count 15 DSOs using flexibility services in 2023–2024, 13 of them through at least one bilateral agreement and 7 through a market; Energimyndigheten’s indicators record bilateral agreements growing from 233 to 393 with users and 22 to 32 with producers in a single year. Bilateral procurement is already the more common channel and the one growing faster. Its volumes are reported as summed MW called across events, a count of use rather than a volume, which is why they are not in the energy ledger above. (Source - Ei R2026-02 Utvecklingen av Smarta Elnät (2025), Source - Energiindikatorer 2026 (ER 2026-14))

Two further channels leave no procurement trace at all. Temporary subscription increases from the overlying grid are the substitute that decides whether a market is needed, as CoordiNet’s Uppland and Skåne results showed (Cause 1 in Why Swedish Local Flex Markets Are Thin — Structural Causes). And villkorade avtal, the instrument most DSOs name as primary, recorded no activations at Ellevio in 2024 (Ei SGI data), and no activation is documented in any source reviewed for E.ON. An unactivated conditional agreement produces no volume statistic, so a ledger built from market and redispatch reporting cannot see the capacity it holds back. (Villkorade Avtal)

What would move the ratios

Three changes would make the next comparison sharper. Second-cycle plans that separate the need a DSO intends to meet with flexibility from the need it intends to build away: E.ON’s lokalnät-only figure and Kraftringen Nät‘s pairing of a 3 MW Lund need with a market planned for 2027 are early versions, and Lund is the cleanest future test because need and instrument are declared together. A single ledger that counts bilateral contracts, subscription increases and market procurement in the same units, which Energimyndigheten’s indicators have begun to do. And DSOs declaring in hours and energy as well as MW, which would at least make the energy comparison possible for more than two of them.

Data gaps

• E.ON’s platform-wide realized need for winter 2025/26; only Södra Skåne’s ~12,000 MWh is stated, and “majority unmet on 10 of 11 markets” gives no total, so the national cold-winter energy realization rate can only be bounded (1,400 MWh activated implies realized need above 2,800 MWh)
• GENAB’s second-cycle DNDP (2027–2036): whether it retains the GWh/hours/occasions quantification, which Finding 2 treats as the variable worth watching

Related pages

• Why Swedish Local Flex Markets Are Thin — Structural Causes — the causal account this page puts numbers against; the TSO subscription mechanism is Cause 1 there and the invisible channel here
• Swedish DNDP First Round — DSO Profiles (2025-2034) — per-DSO declared needs in full
• Swedish Flexibility Market Landscape — season-by-season market volumes, the delivered side of the ledger
• Flexibility Need Assessment — the FNA framework, the Art. 31.1 firm-treatment rule, and the PM2025:03 national ranges
• Distribution Network Development Plan — what a DNDP must quantify and how the MW figure is defined
• Effekthandel Väst — Market Data and Season Outcomes — GENAB’s market data behind Finding 2
• Swedish Congestion Management — Redispatching Data and Regional Patterns — the Ei R2025:13 redispatching data behind Finding 3
• Villkorade Avtal — the conditional-agreement instrument and its SGI portfolio data
• DSO Flexibility Need Calculation Methods — how the declared figures are produced, and why fördelningsstation-level N-1 need is a planning envelope