The Great Britain transmission and distribution network in May 2026, the three transmission owners, the six DNO groups, and the LTDS Stage 2 picture published on 29 May 2026

Where the Great Britain transmission and distribution network stands in May 2026

These notes stay short on news and long on mechanics. Even so, two things shifted in the twelve months to May 2026, and they sit at the front of every connection conversation. The Long Term Development Statement reached its Stage 2 publication on 29 May 2026, under the Ofgem derogation letter dated 13 May 2026 from Steve McMahon, the Director for Network Price Controls, granting an extension that approved a one future-year EQ and SYSCAP model at Stage 2 with years two to five deferred to Stage 3, the movement of short-circuit results from SYSCAP into a dedicated SCR profile, and the movement of connections activity reporting into the Capacity Heatmap.² The Connections Reform Gate 2 outcomes from April 2026 progressed 283 gigawatts of generation and storage and 99 gigawatts of demand to firm offers across Phase 1 to 2030 and Phase 2 to 2035, which means the queue that a planner is now working against is the one that has cleared the Gate 2 readiness tests rather than the one filed in the order it landed at the post.⁹ The LTDS Direction issued by Ofgem under Standard Licence Condition 25.2 on 30 April 2024 is the statutory hook for the publication itself; the seven-year publication interval set by SLC 25.2 is the floor that keeps the published planning data current across the network.^{1 7}

The network itself has three transmission owners and six distribution network groups. The three transmission owners are National Grid Electricity Transmission for England and Wales, SP Transmission for central and southern Scotland, and Scottish and Southern Electricity Networks Transmission for northern Scotland. The six distribution groups, taken in the order the map reads from the south coast clockwise, are UK Power Networks (three licence areas covering London, the east of England and the south east), National Grid Electricity Distribution (four licence areas covering the East Midlands, the West Midlands, the south west and south Wales), Scottish and Southern Electricity Networks Distribution (two licence areas covering southern England and the Scottish Highlands and Islands), SP Distribution (the central and southern Scotland distribution area), Electricity North West (the single Cumbria and north west England area), and Northern Powergrid (two areas covering Yorkshire and the north east of England). The fourteen licence areas, the six groups and the three transmission owners are the operating units the reader will see referenced in every Distribution Code clause, every Grid Code clause and every LTDS data exchange in May 2026.⁵

Two systemic features are worth keeping in mind before the maps. The first is that the 132-kilovolt voltage tier sits on the transmission side of the boundary in Scotland and on the distribution side in England and Wales. The Scottish 132-kilovolt assets are owned by SP Transmission in the central and southern Scotland area and by Scottish and Southern Electricity Networks Transmission in the northern Scotland area. The English and Welsh 132-kilovolt assets are owned by the relevant distribution network operator. The second is that the long-term planning data set is moving onto a common information model under a directed standard. The Grid Code modification GC0139 brought CGMES v3 onto the LTDS as the data-exchange standard, the artefacts are kept on the BSI CIM Engagement Hub as the official location of record, and from Stage 2 onwards the LTDS published numbers are read against the CGMES profile families that the planner uses in modelling tools.²

One more thing worth setting down at the start. The fourteen distribution licence areas are kept distinct from the six commercial groups that hold them, because each licence area carries its own Standard Licence Conditions, its own RIIO settlement and its own Long Term Development Statement. National Grid Electricity Distribution holds four licence areas under a single corporate parent, but the four licence areas are read by Ofgem as four separate economic units with four separate output incentive frameworks. UK Power Networks holds three licence areas under a single consortium, but again the three areas are settled separately. The number that matters for a planner reading the price control track is the licence-area count (fourteen); the number that matters for a reader doing operator due diligence on the same picture is the group count (six); the number that matters for a reader doing a transmission-tier read is the transmission-owner count (three). All three numbers stay in view because each answers a different question, and none of them substitute for the others.⁵

The voltage cascade hooked to the geographic layout

The cascade has five tiers. Each tier is owned by a licensed transmission or distribution operator under conditions issued by Ofgem under the Electricity Act 1989.⁸ The 400-kilovolt and 275-kilovolt super-grid is the transmission tier. The 132-kilovolt tier is the boundary tier, and is the one place where the ownership pattern is asymmetric across the border between England and Wales and Scotland. The 33-kilovolt tier is high-voltage distribution and is owned everywhere by the relevant distribution network operator. The 11-kilovolt tier (and the legacy 6.6-kilovolt tier on a small number of urban networks) is medium-voltage distribution. The low-voltage service to the meter is 230 volts single phase and 400 volts three phase.

The cascade is geographic at every step. A 400-kilovolt substation at Drax in Yorkshire sits inside the National Grid Electricity Transmission footprint and steps down through a super-grid transformer to the 132-kilovolt tier owned by Northern Powergrid in the Yorkshire licence area. A 400-kilovolt substation at Beauly in northern Scotland sits inside the Scottish and Southern Electricity Networks Transmission footprint and steps down through a super-grid transformer to the 132-kilovolt tier also owned by Scottish and Southern Electricity Networks Transmission, because in Scotland the 132-kilovolt assets sit on the transmission side of the boundary. The same physical equipment carries the same physical current; the licensing changes because the boundary line in the statute is set differently in the two jurisdictions.

Reading the cascade the other way, an 11-kilovolt feeder in a town in the East Midlands runs back through a secondary substation, a primary substation, a bulk supply point and a grid supply point to the 400-kilovolt super-grid. The operator at each step changes only at the grid supply point boundary: the secondary substation, the primary substation and the bulk supply point are all owned by National Grid Electricity Distribution in the East Midlands licence area, and the grid supply point feeds the 400-kilovolt super-grid owned by National Grid Electricity Transmission. The statutory limits at each tier are set by the Grid Code at transmission and by the Distribution Code at distribution; the Engineering Recommendations G98 (micro-generation up to and including 16 amperes per phase) and G99 (everything larger up to and including transmission-connected generation) sit underneath the codes as the connection-stage rule set.^{3 4}

One feature of the cascade worth dwelling on is how the geographic distance shrinks as the voltage falls. A 400-kilovolt circuit between Drax and Sundon runs more than 200 kilometres on its longest leg. A 33-kilovolt ring serves a city the size of Sheffield. An 11-kilovolt feeder serves a few streets. A 400-volt three-phase service runs the last span from a pole or a pavement cubicle to the meter. The voltage cascade is also a length cascade, and the network operators are organised around that fact: a transmission owner runs an estate measured in tens of thousands of kilometres of conductor across hundreds of substations; a distribution network operator runs an estate measured in hundreds of thousands of kilometres of conductor and hundreds of thousands of secondary substations. The fall in voltage between tiers is matched by a multiplication in the number of nodes the operator has to keep in steady state.

The cascade is also a hierarchy of timeframes. A transmission switching action affects tens of millions of consumers within a few cycles; a distribution switching action affects a few hundred to a few thousand consumers within seconds; a low-voltage fault affects a single street within a fuse-clearing time of milliseconds. Operators plan and dispatch differently at each tier as a result. NESO operates the transmission system in real time against a half-hourly settlement period, with sub-second reactive support, frequency response and voltage management running underneath. A distribution network operator runs the distribution system through a control room that dispatches switching and reconfiguration on a minute-to-hour timescale, with the Distribution Code DPC4 voltage management clauses sitting on top. The Engineering Recommendations sit underneath both tiers as the connection-stage and quality-of-supply rule set that every connection has to clear before it joins the cascade at any voltage.³

The cascade is also a hierarchy of asset lifetimes. A 400-kilovolt overhead line lasts sixty to eighty years; a 33-kilovolt cable thirty to forty; an 11-kilovolt underground cable forty to sixty; a low-voltage service twenty to thirty before reinforcement or replacement is the usual driver. The replacement cycle is therefore weighted toward the lower voltages because the asset base is bigger and the lifetime is shorter. The RIIO-ED2 distribution settlement and the RIIO-T3 transmission settlement together budget a roughly 90 billion pound transmission investment pipeline and a 22.2 billion pound distribution baseline over the current and following price control periods, with the largest single share of new investment going to load-related expenditure at distribution and to strategic transmission reinforcement at transmission. The cascade is the planning hierarchy as well as the operating hierarchy, and the price control regime is sized against the cascade rather than against any single asset class.⁴

Transmission ownership: NGET, SPT and SSEN-T

Three transmission owners hold the licences for the 400-kilovolt and 275-kilovolt super-grid in Great Britain. They also hold the 132-kilovolt assets in Scotland. NESO holds the system operator licence and runs the integrated National Electricity Transmission System across all three transmission owners as a single machine.

National Grid Electricity Transmission owns and maintains the transmission assets in England and Wales. Its footprint covers about 7,200 kilometres of overhead lines and underground cables at 400 kilovolts and about 2,200 kilometres at 275 kilovolts, across roughly 350 substations, with the dense corridors running north to south through the Trent valley and east to west across the Pennines. The Warwick head office is the operating base. The owner sits inside the RIIO transmission price control and its allowed totex sits inside the RIIO-T3 settlement that started on 1 April 2026 and runs to 31 March 2031.⁵

SP Transmission, headquartered in Glasgow and owned by Iberdrola, holds the transmission licence for central and southern Scotland. The 400-kilovolt and 275-kilovolt footprint covers the central belt from Glasgow and Edinburgh down to the border with the National Grid Electricity Transmission area at Harker and Auchencrosh, and the 132-kilovolt footprint extends into the more dispersed networks across Galloway, the Borders, Ayrshire and the Lothians. SP Transmission also holds a distribution licence (SP Distribution, in the same geographic area) but the two licences are operated as separate businesses for regulatory purposes.

Scottish and Southern Electricity Networks Transmission, headquartered in Perth and owned by SSE plc, holds the transmission licence for northern Scotland. The footprint runs from the border with SP Transmission near Stirling up to the far north of Scotland and out to the Western Isles and Orkney. The 400-kilovolt and 275-kilovolt grid in this footprint is sparser than in the rest of Great Britain because the demand density is lower; the 132-kilovolt grid is the workhorse, picking up the offshore wind injection in the Moray Firth and the Pentland Firth and carrying it south. The Beauly to Denny 400-kilovolt line completed in 2015 closed the longest standing gap in the Scottish super-grid; the Eastern Green Link 1 and Eastern Green Link 2 high-voltage direct current bootstraps are under construction to move bulk Scottish wind power south to the demand centres without overloading the existing alternating-current corridors.

The three transmission owners together hold a single system that NESO operates against the Security and Quality of Supply Standard, the Grid Code and the System Operator-Transmission Owner Code. The statutory rule that gives the transmission licence its boundary at and above 132 kilovolts in Scotland and above 132 kilovolts in England and Wales is set by Ofgem under Section 6 of the Electricity Act 1989; the asymmetry is a legacy of the pre-1990 vertical integration of the Scottish utilities, and has not been changed since the British Electricity Trading and Transmission Arrangements went live on 1 April 2005.⁸ The Centralised Strategic Network Plan, whose methodology was submitted by NESO to Ofgem in January 2026 with first delivery due by end of 2028, will be the next major planning artefact that crosses all three transmission owner footprints in a single document.⁶

Two reading habits help when picking up the transmission tier for the first time. The first is to keep the system-operator role distinct from the transmission-owner role. NESO holds the system operator licence; it does not own any transmission assets. The three transmission owners hold the asset licences; they do not run the real-time dispatch of the transmission system. The two sides are bound together by the System Operator-Transmission Owner Code, which sets out the contractual interface between NESO and the asset owners on outages, switching, reactive support and capital project delivery. The reason this split matters in May 2026 is that NESO became a publicly owned not-for-profit corporation on 1 October 2024 under the Energy Act 2023 Part 5, and the public ownership of the system operator alongside the continued private and consortium ownership of the three transmission owners is the shape of the GB transmission system going into RIIO-T3.

The second reading habit is to keep the asset class register in view when reading about a transmission owner. Each transmission owner holds overhead lines and underground cables, substations including switchgear, transformers and busbars, reactive plant including capacitors, reactors, synchronous condensers and STATCOMs, telecoms infrastructure for the SCADA system, and, on most sites, a contracted Electricity System Restoration Service capability against the Black Start procurement. They do not hold generation, distribution assets below the super-grid step-down at the grid supply point, or interconnector assets, which sit under separate interconnector licences. The interconnector tier is the connection-point category that has changed the most in the last decade, and the geographic concentration of new landfalls on the south east and east coast of England is the operating reality the transmission owners on those routes have had to absorb at the same time as they have been planning the bootstrap circuits north to south.⁵

Distribution ownership: the six DNO groups across fourteen licence areas

Below the 132-kilovolt boundary (or below 33 kilovolts in northern Scotland, where the 132-kilovolt tier sits with Scottish and Southern Electricity Networks Transmission), the assets are held by six distribution network operator groups across fourteen licence areas. The licence areas are kept distinct for regulatory purposes even where the parent group holds more than one of them, because each licence area carries its own RIIO settlement, its own output incentives and its own Long Term Development Statement.⁷

UK Power Networks is the largest by customer count, with three licence areas: the London Power Networks area covering Greater London, the Eastern Power Networks area covering the east of England including Essex, Cambridgeshire and Norfolk, and the South Eastern Power Networks area covering Kent, Sussex and Surrey. The group is owned by a consortium led by KKR, the Ontario Teachers' Pension Plan and the PSP Investments fund, and its head office is in London. The three licence areas together cover the highest demand density in the country, with the London Power Networks area carrying the densest 11-kilovolt and low-voltage network on the system, and the South Eastern Power Networks area carrying the interconnector landfalls at Sellindge for the IFA and IFA2 cables to France.

National Grid Electricity Distribution, headquartered in Avonmouth and owned by National Grid plc since the acquisition of Western Power Distribution completed in June 2021, holds four licence areas: the East Midlands area covering Nottinghamshire and Derbyshire, the West Midlands area covering Birmingham and Black Country, the South West area covering Cornwall and Devon, and the South Wales area covering Cardiff, Newport and the south Wales valleys. The four areas are the inheritance of the Western Power Distribution group which was itself the consolidation of the East Midlands Electricity, MEB and Aquila businesses through the 1990s and 2000s. The South West and South Wales areas carry the highest density of distributed generation (solar PV and onshore wind) relative to their demand of any DNO areas in the country, which is the operating reality that put Active Network Management on the agenda in the South West first.

Scottish and Southern Electricity Networks Distribution holds two licence areas: the Southern area covering Hampshire, Oxfordshire, Berkshire and into the Thames Valley, and the Scottish Hydro area covering the northern Scotland Highlands and Islands. The group is the distribution arm of SSE plc, headquartered in Perth. The Southern area is one of the most demand-dense distribution areas outside Greater London, with the Thames Valley industrial corridor running through it; the Scottish Hydro area is the lowest demand-density distribution area in the country, with the Western Isles, the Orkney Islands and the Shetland Islands sitting at its far edge.

SP Distribution holds the central and southern Scotland distribution licence in the same geographic footprint as SP Transmission. The group is owned by Iberdrola and is run as a separate licensed entity from SP Transmission. Its head office is in Glasgow. The SP Distribution area carries the urban demand of Glasgow and Edinburgh and the industrial demand of the central belt; the connection to the SP Transmission 132-kilovolt boundary in this area is through bulk supply points that the two licensees jointly plan against the Distribution Code DPC4 voltage management clauses.

Electricity North West holds the single licence area covering Cumbria and the north west of England. The group is owned by a consortium led by First Sentier and Equitix, headquartered in Warrington. The area covers the Manchester and Liverpool conurbations on its southern edge and the Lake District and the Solway Firth on its northern edge; the demand density gradient across the area is among the steepest of any DNO licence area in the country.

Northern Powergrid, owned by Berkshire Hathaway Energy and headquartered in Newcastle, holds two licence areas: the North East area covering Northumberland, Tyne and Wear, and County Durham, and the Yorkshire area covering North, West and South Yorkshire. The two areas together cover the eastern half of northern England, with the Drax and Eggborough generation hubs on its southern edge and the Hartlepool and Teesside industrial clusters on its eastern edge. The Yorkshire area is the home of a substantial onshore wind and battery storage build-out that started in the early 2010s and accelerated through the connections queue from 2018 onwards.

Two further roles sit alongside the six groups in the distribution layer. Independent Distribution Network Operators hold their own Ofgem distribution licences and own portions of network, typically the new-build housing developments and industrial parks that are connected to the host DNO's network at a point of connection but are then owned and operated by the IDNO downstream of that point. The IDNO market grew out of the Competition in Connections regime entrenched in 2017 and now carries a material share of new connections in the most active development corridors. Independent Connection Providers hold no licence but are accredited by Lloyd's Register under the National Electricity Registration Scheme to design and build connection assets that the host DNO then adopts; the ICP route is the dominant one for connections in the new-build housing market and in much of the small-to-medium commercial market.

The reading habit that helps with the distribution layer is to keep the licence area, the parent group, the IDNO map and the ICP accreditation in view at the same time. A new connection in a Yorkshire development might involve the Northern Powergrid licensee as the host DNO, an IDNO holding the new development network, and an ICP designing and building the connection assets that the host DNO adopts at the point of connection. The Connections Action Plan published jointly by DESNZ and Ofgem on 22 November 2023 and the CMP376 modification effective 29 January 2025 are the reform package that sits behind the current connection process; the Gate 2 outcomes from April 2026 are the operating data point those reforms now produce on the ground.⁹

The boundary between transmission and distribution, and the 132-kilovolt asymmetry

The statutory boundary between transmission and distribution sits in the licences issued under Section 6 of the Electricity Act 1989.⁸ A transmission licence authorises operating the assets above 132 kilovolts in England and Wales (so 275 kilovolts and 400 kilovolts) and at 132 kilovolts and above in Scotland (so 132 kilovolts, 275 kilovolts and 400 kilovolts). A distribution licence authorises operating the assets at and below 132 kilovolts in England and Wales (so 132 kilovolts, 33 kilovolts, 11 kilovolts and the LV service) and below 132 kilovolts in Scotland (so 33 kilovolts, 11 kilovolts and the LV service). The 132-kilovolt tier is therefore on the transmission side of the boundary in Scotland and on the distribution side of the boundary in England and Wales; it is the only voltage tier where the boundary is set asymmetrically across the border.

The asymmetry has measurable operating consequences. A generator connecting at 132 kilovolts in the SP Distribution area in central Scotland connects under the Connection and Use of System Code because the assets at that voltage are owned by SP Transmission. The same generator connecting at 132 kilovolts in the National Grid Electricity Distribution East Midlands area connects under the Distribution Connection and Use of System Agreement because the assets at that voltage are owned by National Grid Electricity Distribution. The charging regime is different (Transmission Network Use of System charges in the Scottish case, Distribution Use of System charges in the English case); the technical compliance reference is different (Grid Code in the Scottish case, Distribution Code in the English case); the embedded benefits and the connection cost recovery rules differ. The same physical equipment, the same physical current, two different commercial and technical regimes by virtue of which side of the border the substation sits on.^{3 4}

Two practical reading habits help here. The first is to keep the licence type in view when reading a connection offer or a planning study: the regime is set by the licensee that owns the assets at the connection voltage, not by the voltage tier on its own. The second is to read the Standard Licence Conditions on each licence type as a single chain: SLC 25 of the Distribution Licence is where the Long Term Development Statement obligation sits, and the equivalent SLC on the Transmission Licence is where the Electricity Ten Year Statement obligation sits; both chain back to Section 6 of the 1989 Act.⁷ The boundary asymmetry is a deliberate legacy of the 1989 reform and the British Electricity Trading and Transmission Arrangements consolidation in 2005, and the regulatory architecture has been written around it rather than against it ever since.

The interconnector tier sits inside its own licence type and is the third licence category a network reader has to keep in view alongside the transmission and distribution licences. An interconnector is a high-voltage direct current cable connecting the GB system to a neighbouring synchronous area, and the owner holds an interconnector licence under Section 4 of the Electricity Act 1989. The interconnector licence sits alongside the transmission licence: the interconnector owner connects to the transmission system at a landfall substation, but the assets themselves are not part of the transmission owner estate. The Connection and Use of System Code carries the technical and commercial interface between an interconnector and the GB transmission system; the operating regime on the other side of the cable is set by the European partner system operator, which in May 2026 is RTE in France, TenneT in the Netherlands, Elia in Belgium, Statnett in Norway, Energinet in Denmark, EirGrid in Ireland, and TenneT in Germany for the connections that are connected or near connection at the May 2026 reading.

One feature of the boundary that has changed in the last five years is the rise of cap and floor as the financing model for new interconnector and new strategic transmission investment. Cap and floor is an Ofgem-set revenue regime that gives the owner a downside floor and an upside cap on its revenue, against a set of physical availability and capacity obligations. The regime has carried the financing of the Eastern Green Link offshore high-voltage direct current bootstrap circuits, the Greenlink interconnector to Ireland, and several pumped-storage projects under development. Cap and floor sits outside the RIIO settlement and is the principal alternative financing model for new transmission and interconnector assets in the GB regime in May 2026.

Connection points: grid supply points, bulk supply points and interconnector landfalls

The connection point names a planner reads on a single-line diagram are tiered to match the cascade. A grid supply point is the substation where a 400-kilovolt or 275-kilovolt transmission circuit steps down to 132 kilovolts. A bulk supply point is the substation where a 132-kilovolt circuit steps down to 33 kilovolts. A primary substation is the substation where 33 kilovolts steps down to 11 kilovolts. A secondary substation is the pole-mounted or pad-mounted transformer where 11 kilovolts steps down to the LV service. The four naming conventions are universal across the six DNO groups and the three transmission owners.

Connections at the transmission tier (400 kilovolts, 275 kilovolts, and in Scotland 132 kilovolts) go through CUSC and the connection offer is issued by NESO. Connections at the distribution tier (132 kilovolts in England and Wales, 33 kilovolts everywhere, 11 kilovolts and the LV service) go through DCUSA and the connection offer is issued by the relevant DNO. Embedded large connections that have a material effect on the transmission system trigger the Statement of Works procedure under CUSC, which brings the transmission owner and NESO into the assessment alongside the host DNO.⁵

The interconnector landfall pattern is the connection-point category that has changed the most in the last ten years. IFA at Sellindge (Kent, 2,000 megawatts to France, commissioned 1986) and the smaller Moyle interconnector to Northern Ireland are the legacy stack. IFA2 (Folkestone area, 1,000 megawatts to France, commissioned 2021), BritNed (Isle of Grain to the Netherlands, 1,000 megawatts, commissioned 2011), Nemo Link (Richborough to Belgium, 1,000 megawatts, commissioned 2019), North Sea Link (Blyth in Northumberland to Norway, 1,400 megawatts, commissioned 2021), Eleclink (the rail tunnel between Folkestone and Coquelles, 1,000 megawatts, commissioned 2022), Viking Link (Bicker Fen in Lincolnshire to Denmark, 1,400 megawatts, commissioned 2023), Greenlink (Pembrokeshire to Ireland, 500 megawatts, commissioned 2024), and NeuConnect (Isle of Grain to Wilhelmshaven in Germany, 1,400 megawatts, energisation expected 2028) make up the connected and near-connected stack at the May 2026 reading. Most of these landfalls are on the south east and east coasts of England, with one on the south west coast of Wales and one further into the North Sea at Blyth; the geographic concentration on the south and east coasts reflects the proximity to the Continental synchronous area and the offshore wind belts of the southern North Sea.

The Connections Reform Gate 2 process is the operating layer that sits over the connection point picture. A project that has cleared the Gate 2 readiness tests has a firm offer with a connection date that is read against the actual network capacity rather than against the order in which the application was lodged. The 283 gigawatts of generation and storage and 99 gigawatts of demand that progressed through Gate 2 in April 2026 are the projects that will be wired into the connection points across the next decade.⁹ The Centralised Strategic Network Plan whose methodology was submitted to Ofgem in January 2026 is the planning artefact that will rank the reinforcements those connections need against the available transmission build-out windows.⁶

The LTDS Stage 2 data layer published on 29 May 2026

The Long Term Development Statement is the published planning model that every distribution network operator has to maintain under Standard Licence Condition 25 of the Electricity Distribution Licence.⁷ The data set names the substations, the lines and cables, the transformers and the connection points across the operator's licence area, with a current-state snapshot and a forward-looking forecast of how the network will evolve. SLC 25.2 sets the publication interval at not more than seven years; the Ofgem LTDS Direction of 30 April 2024 set the staged timetable that is being delivered in May 2026 and Autumn 2026.¹

Stage 2 was published on 29 May 2026 under the Ofgem derogation letter of 13 May 2026 signed by Steve McMahon, Director Network Price Controls. The derogation approved four changes to the original Stage 2 specification: one future-year equipment (EQ) and SYSCAP model at Stage 2 with the remaining years two to five deferred to Stage 3; the movement of short-circuit results from SYSCAP into a dedicated SCR profile; the movement of connections activity reporting into the Capacity Heatmap; and the deferral of the Stage 3 production deadline from 15 August 2026 to 15 October 2026 with the Stage 3 publication held at 30 November 2026. The BSI CIM Engagement Hub was confirmed in the same letter as the official location of record for LTDS data-exchange definition artefacts.²

The CGMES v3 profile families that make up the LTDS data exchange are the equipment (EQ), the steady-state hypothesis (SSH), the topology (TP), the state variables (SV), the diagram layout (DL), the short-circuit results (SCR) and the header. A planner reading the Stage 2 publication is reading a CGMES v3 model on the LTDS profile, with the operator's identification of every substation, every line, every transformer and every connection point against the standard naming and the standard data types. Loading the Stage 2 model into a CGMES-compliant tool such as PowerFactory or PSS over E gives a working model that the operator and the planner can read against the same picture; the LTDS published numbers are the picture both sides have to plan against, by statute, under SLC 25.

The Stage 2 picture is also the picture that the Connections Reform Gate 2 offers were issued against. A project with a Gate 2 offer in the National Grid Electricity Distribution East Midlands area has its connection point identified in the LTDS Stage 2 model for that licence area, with the transformer ratings, the line and cable impedances and the substation arrangement set out in the CGMES profiles. The 132-kilovolt tier in the same area is also in the model because that tier is owned by National Grid Electricity Distribution in England and Wales. In the SP Distribution area in central Scotland, the 132-kilovolt tier sits in the SP Transmission Long Term Network Development picture rather than in the SP Distribution LTDS, because that tier is on the transmission side of the boundary in Scotland; a planner reading a Gate 2 offer in central Scotland reads two models against each other and lines up the boundary substation on both.

The reading habit that helps with LTDS Stage 2 is to keep the staged timetable in view. Stage 1 (data preparation and the legacy Excel LTDS) was the May 2025 milestone under the November 2024 derogation letter. Stage 1.3 (the deliverables in Table 7 of the Form of LTDS) ran to a 28 November 2025 publication. Stage 2 (the equipment, steady-state and topology profiles, with one future-year EQ and SYSCAP model under the May 2026 derogation) is the 29 May 2026 publication that the workspace reading is set against. Stage 3 (the deferred future-year models, the dedicated SCR profile, the Capacity Heatmap inclusion of connections activity reporting, and the production deadline of 15 October 2026 with publication held at 30 November 2026) is the next milestone. The staged delivery is set inside the seven-year publication interval that SLC 25.2 requires.⁷

For a planner picking up the LTDS for the first time, the relationship between the LTDS and the operator's other published data sets is worth setting out. The Embedded Capacity Register, published per DNO under Standard Licence Condition 50 of the Distribution Licence, lists the generators and storage assets embedded in the distribution network with their connection details and operating limits. The Distributed Energy Resources data published by each DNO sits alongside the LTDS and provides the operating reality on the ground at the connection point. The connection process pages (DCUSA for distribution, CUSC for transmission) publish the heat maps, queue positions and offer statuses for the live process. The LTDS is the published planning model; the ECR is the published asset register; the connection process pages are the published live state. Reading the three sets against each other is the working pattern for any project-specific question on a connection point.

The Connections Reform Gate 2 outcomes and what they mean on the ground

The Connections Reform Gate 2 outcomes published by NESO in April 2026 are the operating data point that any reader of the network in May 2026 has to keep in view. The Gate 2 process replaced the legacy first-come first-served queue with a readiness-and-strategic-alignment test: a project is offered a firm date once it has demonstrated land rights, planning consent progress, fuel or technology readiness, and alignment with the network plan. 283 gigawatts of generation and storage and 99 gigawatts of demand progressed through Gate 2 in April 2026; offer-issuance windows run from March to November 2026; the next applications window is expected in the second half of 2026.⁹

The reading habit that helps most here is to read the Gate 2 outcome alongside the LTDS Stage 2 picture, the Electricity Ten Year Statement 2024 and the Centralised Strategic Network Plan methodology consultation. The four artefacts together give the picture a planner needs to understand a single connection: what the network looks like now (LTDS Stage 2), what the transmission system was on track to need before Gate 2 (ETYS 2024), what the new portfolio of firm connections looks like (Gate 2 outcomes), and how the centralised plan will rank the transmission build-out across the next price control period (CSNP methodology).^{5 6}

The on-the-ground picture is concentrated. The 283 gigawatts of generation and storage in the Gate 2 portfolio is heavily weighted toward batteries, solar PV and offshore wind, with onshore wind, hydrogen-ready combined cycle gas turbines and nuclear small modular reactors carrying a smaller share. The 99 gigawatts of demand is heavily weighted toward electrolysers and data centres, with electrification of process heat and electric vehicle depots carrying a smaller share. The geographic concentration is at the eastern coast of England and Scotland for offshore wind and demand at the south east and east coast landfalls, in the Yorkshire and Humber industrial cluster for hydrogen-ready generation and electrolysers, and around the Greater London and Thames Valley demand densities for data centres and electrification. The picture on a map looks like the country being rewired around the existing transmission corridors, with the bottleneck moving from connection-stage queueing to network-stage delivery.

What this means for a reader picking up the network for the first time in May 2026 is that the Gate 2 portfolio sets the next decade of network capital investment. The RIIO-T3 transmission price control settlement that started on 1 April 2026 carries a roughly 90 billion pound investment pipeline, against a roughly 28.1 billion pound baseline, with the uplift coming from uncertainty mechanisms tied to the Strategic Spatial Energy Plan and the Accelerated Strategic Transmission Investment fast-track. The RIIO-ED2 distribution price control that runs to 31 March 2028 carries the connection-stage capital plan, with the load-related expenditure mechanisms tied to forecast electrification and a Net Zero Re-opener clause for the largest commitments. The Gate 2 portfolio is the demand signal those settlements are sized against.

The connection points in the Gate 2 portfolio sit on a network whose constraint pattern has shifted in the last five years. The constraint cost that NESO pays to balance the system around transmission bottlenecks rose from around 1.5 billion pounds in the 2023 to 2024 financial year to around 1.9 billion pounds in the 2024 to 2025 financial year, and the Frontier Economics analysis for NESO projects the constraint cost rising to between 4 and 8 billion pounds by 2030 unless the transmission build-out catches up with the connection pipeline. The Eastern Green Link 1 and Eastern Green Link 2 high-voltage direct current bootstraps, the Sea Link offshore high-voltage alternating-current connection between East Anglia and the south east, and the Western Link upgrade are the named transmission projects whose delivery dates the Gate 2 portfolio is being read against. The Accelerated Strategic Transmission Investment regime gives Ofgem a fast-track route to approve the cost allowances for these projects without waiting for a full RIIO Final Determinations cycle; the regime survived into RIIO-T3 and forms the principal vehicle for the strategic build-out the portfolio depends on.⁶

Reading the Gate 2 portfolio against the network in May 2026 is therefore a four-corner exercise. The first corner is the connection point itself, set in the LTDS Stage 2 model. The second corner is the transmission reinforcement that delivers the headroom for the connection, set in the ETYS 2024 picture and the CSNP methodology. The third corner is the price control envelope, set in the RIIO-T3 and RIIO-ED2 settlements. The fourth corner is the planning consent and the project readiness, set in the Town and Country Planning Act 1990 (for England and Wales) and the Electricity Act 1989 (for transmission consents) plus the developer's own delivery plan. A planner who reads the four corners against the same connection point has the full picture of why the connection has the date it has, what the network needs to do to deliver it, and where the risks sit. The four corners do not always line up; the Gate 2 process is the operating layer that brings them into alignment over the next decade.

The embedded network explorer

The static reading above sets the picture. To work with it, the interactive network explorer below searches the map, compares operator areas, inspects the voltage tiers at a chosen point, and screens candidate connection points. The surrounding section carries the explanation and the sources; the explorer carries the map, the search, and the interactive layout, so the move from reading to working stays on one page. The engineering tools page uses the same pattern for its screening bench.

Two reading habits keep the explorer useful and keep it inside its sourcing boundary. The first is to use the embedded component for orientation, hierarchy, operator-area comparison and first-pass connection screening, and to use the LTDS Stage 2 publication and the operator's own connection process pages for any decision that affects a real connection offer, a real network capacity number or a real design. The second is to read the result alongside the surrounding section: a candidate connection point identified in the explorer is a starting point for a CUSC or DCUSA application, not a substitute for one, and the relevant operator publication is the authoritative number.

The explorer is the working surface for the picture the reading sets out. The intended sequence is: read the static map for the picture, open the explorer to find the point or the area in view, open the operator's own LTDS release on the BSI CIM Engagement Hub for the published planning numbers, and open the relevant connections route on the operator's site for the live process. The four steps share the same statutory frame (the Electricity Act 1989, SLC 25, the Distribution and Grid Codes, the Engineering Recommendations) and the same data layer (LTDS Stage 2 on 29 May 2026, the Gate 2 outcomes from April 2026, ETYS 2024 and the CSNP methodology in consultation), so the reader stays inside the same picture from a top-down reading to a project-specific question.^{2 9}