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By NiLu Updated

Capacity, interconnection queues, and reinforcement

Generation queue is not load queue, MW in queue is not operation date, and reinforcement comes from a study — not a universal MW threshold.

Article summary

  • Generation connection queues and load connection requests are different processes with their own rules and sources — in the US, Order 2023 governs generation; the large-loads track (DOE §403 / RM26-4) is separate.
  • Active MW in a queue is not an operation date: in the US, most generation projects that enter the queue are withdrawn before generating, and the time between request and operation keeps growing.
  • Grid reinforcement is the outcome of a study (cluster, budget, access opinion, connection agreement) — there is no universal MW threshold that triggers reinforcement in every jurisdiction.
  • Each regulatory bloc has its own vocabulary: in the US, generation and load follow distinct FERC rules; in Brazil, distribution and Rede Básica have their own products and deadlines; in the European Union, the Demand Connection Code sets technical requirements, not a public connection queue.

Two processes, two scoreboards

The previous text in this series showed that “capacity” changes meaning depending on context — maximum generation, physical line limit, contingency margin, congestion. This text focuses on a fourth meaning: the connection queue, i.e., the process by which a project requests grid access and awaits studies before it can operate. The first hard lock is simple to state and easy to forget in practice: the generation process and the load process are not the same rulebook.

In the United States, FERC Order No. 2023 — issued on July 28, 2023, and published in the Federal Register on September 6, 2023 — reforms generator interconnection procedures and agreements (the LGIP/LGIA and SGIP/SGIA templates). It is not a load interconnection rule. [1] [2] The large-loads track is separate: FERC docket RM26-4-000 originated from a DOE letter, based on Section 403 of the Department of Energy Organization Act, dated October 23, 2025, on the timely and orderly interconnection of large loads — the DOE asked FERC to reach a final decision by April 30, 2026. [3] [4] Treating Order 2023 and RM26-4 as the same thing is the kind of error that leads a manager to compare timelines from different processes as if they were the same scoreboard.

How to request connection in the US, Brazil, and Europe

In the US, Order 2023 replaced the serial study process (first-come, first-served) with a first-ready, first-served cluster process: projects enter study batches, must prove readiness — with commercial-commitment deposits and site control — and go through restudy rules when other projects in the same cluster withdraw. FERC’s explainer cites a cluster study with a reference timeline of 150 days, followed by a facilities study and the interconnection agreement; the network reinforcements required for the cluster are allocated by a proportional-impact method. [1] This applies to generation — the large-loads track, still in public consultation (ANOPR), proposes studying loads and hybrids together with generation whenever practicable, plans to seek comments on faster studies, and, in the proposal, would assign 100% of studied reinforcement costs to the load or hybrid, with the credit mechanism still open — these are proposed principles, not a final FERC rule. [4]

In Brazil, the connection request for load follows different paths depending on the voltage level. In distribution, ANEEL’s REN No. 1.000/2021 treats connection as a right once requested — the distribution utility cannot refuse to receive the request — subject to technical and safety conditions and to regulated costs. [9] The connection budget is mandatory in a series of situations set out in the rule — new connection, increase in demanded or injected power, change of connection point or voltage, capacity reservation, or the addition of distributed generation to an existing consumer unit, among other triggers. [9] The deadlines for the distribution utility to issue that budget are also fixed by the rule: 15 days for units with distributed micro-generation or without generation, below 69 kV and without the need for works; 30 days when distribution or transmission works are required; 45 days for other connections — with the possibility of pausing the deadline to consult the ONS or another distribution utility. [9] REN 1.000 coexists with PRODIST — the Distribution Procedures set out by REN No. 956/2021 — as complementary ANEEL rules for the distribution layer; this dossier maps the budget process under REN 1.000 and does not state, in this cycle, whether the current text of PRODIST Module 3 adds its own deadlines or access-opinion labels for load. [10]

In the Rede Básica — the transmission network at 230 kV or above — the request follows Sub-module 3.4 of the ONS Network Procedures. The output of this process is the Access Opinion (Parecer de Acesso), which consolidates the technical feasibility assessments and then feeds into the Transmission System Usage Contract (CUST); the type of accessing agent includes, among others, the Free Consumer. [11] The study has two possible paths: if no expansions, reinforcements, or improvements are needed, the Opinion is issued and goes directly to the CUST; if only reinforcements or improvements are needed, the ONS informs the accessing party and has up to 90 additional days to analyze the access conditions — an analysis that can feed into the Module 4 expansion and reinforcement study cycle. [11] The Opinion that defines the access conditions is valid for 90 days; priority over new requests lasts until the CUST is signed within that period — if the CUST is not signed in time, the priority is lost. [11]

In the European Union, the regulation governing demand connection is the Demand Connection Code — Regulation (EU) 2016/1388, of August 17, 2016 —, which covers demand facilities connected to transmission, distribution facilities connected to transmission, distribution systems (including closed distribution systems), and demand units used for demand response. [12] The DCC defines maximum import capacity as the maximum continuous active power consumable at the connection point, as specified in the connection agreement with the relevant system operator, and it establishes a ladder of operational notifications — energization, provisional, final, and limited — which is a technical-compliance path, not a public MW queue. [13]

Reinforcement is a study outcome, not a magic number

The second hard lock in this text: grid reinforcement is not triggered by a universal MW threshold — it is the outcome of a specific study, carried out within a specific jurisdictional process. In the US, the Order 2023 explainer itself describes studies determining which equipment and transmission reinforcements are needed before a project can connect, and assigning costs based on that outcome — reinforcement is a study output, not a separate “queue volume” metric. [1] In Brazil, the same pattern appears across two distinct processes: in distribution, the REN 1.000 budget has a clear fork between connection with no need for works (shorter deadline) and connection requiring distribution or transmission works (longer deadline); in the Rede Básica, the ONS Opinion forks between “no need for reinforcements” (Opinion straight to the CUST) and “reinforcements needed” (a further 90 days of analysis). [9] [11] In the European Union, the DCC sets technical requirements and maximum import capacity, but does not establish an MW threshold nor a pan-European reinforcement trigger — that is left to the national processes of each transmission and distribution operator. [12] [13]

On the definition of “large load” that drives part of the current US debate: the DOE’s proposal under consultation defines large load, for the purposes of that specific process, as above 20 MW connecting directly to transmission, aligned with the large-generator threshold already used in FERC Order No. 2003. It’s a jurisdictional framing proposed for that process — not a universal definition of “large load” applicable outside that regulatory context. [4]

Where a public queue exists — and where it does not

In the United States, there are widely cited public interconnection-queue portals: the PJM Cycle Service Request Status (under the cycle/cluster process in effect since July 10, 2023), MISO’s generator interconnection queue, ERCOT’s GIS report, and CAISO’s interconnection queue reports. [7] All of these are generation (and storage) interconnection products — not load interconnection queue datasets. The Lawrence Berkeley National Laboratory consolidates this data nationally in the Queued Up series; [5] the 2024 edition, with data through the end of 2023, totals about 11.597 active projects, approximately 1.570 GW of generation plus 1.030 GW of storage — about 2.598 GW of active capacity in the treated sample —, plus about 17.873 withdrawn projects (~3.097 GW) and about 4.155 operational projects (~470,4 GW). The report itself is explicit: the scope is the bulk power transmission system, excluding distribution-connected projects and “behind the meter” projects. [6]

There is no public dataset, among this dossier’s sources, equivalent for the load interconnection queue in the US — the portals above measure generation, not large-load requests awaiting connection. This transparency may emerge from RM26-4 developments or from regional operators’ tariff filings, but it does not exist today. In the European Union, the picture is similar for a different reason: neither the DCC, nor ENTSO-E’s network-codes hub, nor the European resource adequacy assessment (ERAA) amount to a pan-European connection-queue dataset comparable to Queued Up — ENTSO-E frames the DCC as focused on industrial loads and distribution networks, with some parameters set at the European level and others at the national level, while the ERAA deals with resource adequacy, not connection backlog. Load connection queues in Europe, where they exist in an auditable way, live within the national processes of each transmission and distribution operator. [14]

MW in the queue is not an operation date

The third hard lock: an active megawatt in a generation queue is not a promise of a megawatt that will operate, let alone a commercial operation date (COD). LBNL’s Queued Up 2024 shows this with numbers: of interconnection requests submitted between 2000 and 2018, only about 20% of projects — and about 14% of capacity — had reached commercial operation by the end of 2023; more than 70% of requests from that period were withdrawn. [6] The delay metric the report itself favors is not queue size, but the median time between the interconnection request and commercial operation: for projects completed in 2023, that median was close to 5 years, against about 3 years in 2015 and less than 2 years in 2008. Separately, the time between the interconnection agreement and commercial operation also grew, from about 17 months for 2007–2015 builds to about 25 months for 2016–2023 builds in the sample. [6]

The Monitoring Analytics report on the PJM market (2024, Section 12) corroborates this pattern regionally: at the end of 2024, PJM’s generation queue totaled 221.297,3 MW on an energy basis (active, under construction, or suspended); historically, only about 17,4% of that type of MW reaches in-service status, and, looking at the queue’s entire history, 11,1% of MW entered service against 62,2% withdrawn. [8] The Order 2023 explainer also cites a different metric, which should not be confused with these completion rates: at the end of 2022, there were more than 10.000 active interconnection requests and more than 2.000 GW of potential generation and storage in the system; of the 2.179 studies completed in 2022, 68% came out late — that is a study-process delay metric, not a completion-to-commercial-operation metric, and it has a different base year from Queued Up 2024. [1] [6] Separating these metrics by vintage and by what each one measures — active MW, completion rate, study delay, request-to-operation median — is what keeps a queue number from being mistaken for a forecast of capacity that will actually operate.

Joint load and generation connection — without mixing jurisdictions

One final point of hygiene: behind-the-meter (BTM) distributed generation and hybrid load+generation connection are concepts that only make sense when localized — mixing definitions from different jurisdictions produces an invalid comparison. In Brazil, ANEEL’s REN 1.000/2021 (as amended by REN 1.059/2023) requires that, for a consumer unit with micro or mini distributed generation, the distribution utility issue a single budget covering load and generation jointly. [9] In the US, the DOE’s proposal under consultation (ANOPR) includes principles for studying loads and hybrids together with generating facilities when practicable, considering the requested injection and withdrawal rights — one example cited in the proposal is a 500 MW load plus 600 MW of generation resulting in 0 MW of withdrawal and 100 MW of injection — in addition to requiring protection against unauthorized injections or withdrawals. [4] These are distinct mechanisms, at distinct regulatory stages (a rule in force in Brazil; a proposal under consultation in the US), and neither should be read as synonymous with residential rooftop distributed generation — LBNL’s Queued Up, for example, explicitly excludes distribution-connected and “behind the meter” projects from its generation-queue scope. [6] [9]

Who pays for grid reinforcement — and how that cost is split between whoever requests the connection and whoever is already connected — is a cost-allocation topic left for another text in this series; the detailed regional map of Brazil, the United States, and Europe also gets its own texts.

Uncertainties

  • There is no public load interconnection queue dataset in the US, among the sources consulted in this cycle, equivalent to the generation portals (PJM, MISO, ERCOT, CAISO, LBNL); this transparency may emerge from RM26-4 developments or from regional tariff filings.
  • It is not mapped in this cycle which national hubs in the European Union (for example Germany, the Netherlands, or Ireland) publish demand connection queue records with auditable MW and timelines — what exists today, at the European level, is the DCC (technical requirements) and the ERAA (resource adequacy), neither equivalent to a connection queue.
  • The most recent edition of LBNL’s Queued Up (with data through the end of 2025) may change the magnitudes of active capacity, completion rate, and request-to-operation median cited here, which are fixed in the 2024 edition (data through the end of 2023) — the numbers should not be added across editions without labeling the reference year.
  • It is not verified in this cycle whether the current text of PRODIST Module 3, following ANEEL’s REN 956/2021, adds deadlines or access-opinion labels for load that diverge from the connection budget already mapped in REN 1.000.

References

  1. FERC — Explainer on the Interconnection Final Rule (Order No. 2023). Federal Energy Regulatory Commission. Accessed August 09, 2026.
  2. Federal Register — Improvements to Generator Interconnection Procedures and Agreements. Federal Register. Accessed August 09, 2026.
  3. FERC — RM26-4 (large loads docket hub). Federal Energy Regulatory Commission. Accessed August 09, 2026.
  4. U.S. DOE — Ensuring the Timely and Orderly Interconnection of Large Loads (§403 ANOPR letter). U.S. Department of Energy. Accessed August 09, 2026.
  5. LBNL EMP — Queued Up hub. Lawrence Berkeley National Laboratory. Accessed August 09, 2026.
  6. LBNL — Queued Up: 2024 Edition (data through the end of 2023). Lawrence Berkeley National Laboratory. Accessed August 09, 2026.
  7. PJM — Cycle Service Request Status. PJM Interconnection. Accessed August 09, 2026.
  8. Monitoring Analytics — 2024 State of the Market Report for PJM, Section 12. Monitoring Analytics. Accessed August 09, 2026.
  9. ANEEL — Resolução Normativa nº 1.000/2021. Agência Nacional de Energia Elétrica. Accessed August 09, 2026.
  10. ANEEL — Resolução Normativa nº 956/2021 (PRODIST). Agência Nacional de Energia Elétrica. Accessed August 09, 2026.
  11. ONS — Submódulo 3.4 dos Procedimentos de Rede (Solicitação / Parecer de Acesso). Operador Nacional do Sistema Elétrico. Accessed August 09, 2026.
  12. Regulamento (UE) 2016/1388 — Demand Connection Code. European Commission / EUR-Lex. Accessed August 09, 2026.
  13. ENTSO-E — Demand Connection Code hub. ENTSO-E. Accessed August 09, 2026.
  14. ENTSO-E — ERAA hub. ENTSO-E. Accessed August 09, 2026.