The utility now decides when your solar project goes live

Interconnection delays now decide when US solar and wind projects start earning revenue, and the dates that govern them sit in utility letters and portals the EPC schedule cannot see. Leading developers are managing network upgrades, outage windows and witness tests as owned, priced obligations alongside construction.

Solar and windSegeta Insights
Solar and wind
The number330 GW

of solar and wind hold a signed agreement but are not yet online

What is at stake

A missed outage window that defers energization by five months could put about $$25 million at risk on a 300 MW solar project.

Where days are lost
  1. Network upgrades
  2. Outage windows and backfeed
  3. Protection reviews and witness tests

An interconnection agreement is usually read as the end of the hardest phase of solar and wind development, with the years in the queue, the cluster studies and the deposits finally behind the project. In practice, the agreement converts a queue position into a set of utility obligations: network upgrades, a backfeed date, an outage window for the tie-in and a sequence of protection reviews and witness tests, each performed on the transmission owner's calendar. The commercial operation date (COD) therefore depends on work that the developer can monitor and the EPC contractor cannot schedule.

The data show how much of the timeline now sits after signature. In 2025 the median project took 31 months from signing its interconnection agreement to commercial operation, up from 21 months in 2008.1 Those months are governed by letters, portal postings and study reports that seldom reach the construction schedule in time to change a decision. This article argues that solar interconnection delays have become largely a post-agreement problem, sets out where the days are lost between developer, contractor and transmission owner, and estimates what each day costs.

Interconnection queues have stretched the path from request to power

About 2,061 gigawatts (GW) of generation and storage capacity was actively seeking interconnection at the end of 2025, and the median project built that year took 61 months from interconnection request to commercial operation.1 The study phase alone took a median of 45 months to reach an interconnection agreement, and only 13 percent of the capacity that requested interconnection between 2000 and 2020 had reached operation by the end of 2025.1 A signed agreement offers limited certainty, because 41 percent of the capacity that signed agreements between 2000 and 2022 had withdrawn by the end of 2025.1

Federal reform has so far targeted the study backlog in the queue. FERC Order No. 2023, issued in July 2023, moved transmission providers to cluster studies with 150-day deadlines and penalties for late studies, after 68 percent of the 2,179 interconnection studies completed in 2022 were issued late.2 Faster studies shorten the wait for an agreement, yet the work that follows it, from network upgrades to outage scheduling and protection reviews, still runs on the transmission owner's calendar.

Solar interconnection delays now accumulate after the agreement is signed

Once an agreement is signed, the project's schedule depends on a sequence of utility obligations communicated through study reports, portal postings, letters and email. At the end of 2025, 549 GW of capacity held a draft or executed interconnection agreement but had not reached commercial operation, and solar and wind accounted for about 330 GW of it.3

Solar and wind make up about 330 GW of capacity that holds an interconnection agreement but has not yet reached operation.

Exhibit 1About 330 GW of solar and wind hold interconnection agreements but are not onlineCapacity with a draft or executed interconnection agreement not yet in operation, end of 2025, GW
Solar256
Storage161
Wind76
Natural gas45

Source: Lawrence Berkeley National Laboratory, Queued Up: 2026 Edition, 2026

01Network upgrades

Upgrades on the transmission owner's system often set the earliest possible backfeed date, and for recently withdrawn projects they made up about 70 percent of interconnection costs.4 Their in-service dates can move with equipment shortages and competing utility work, and CAISO reported in 2024 that such factors were driving out initial planned dates for network upgrades.5 A revised date typically reaches the developer as a letter or portal update, and it may take weeks to appear in the EPC's schedule.

02Outage windows and backfeed

Tying a new substation into the grid usually requires a planned transmission outage, and utilities grant those outages around seasonal peaks. In PJM, transmission outages longer than five days are scheduled six months to a year in advance where possible, and about 30 transmission jobs a day are approved on peak summer and winter days, against roughly 200 a day outside the peaks.6 A project that misses its window is likely to wait for the next shoulder season.

03Protection reviews and witness tests

Before energization, the utility reviews relay and protection settings, approves metering and telemetry, and witnesses commissioning tests at the point of interconnection. Each step has its own reviewer, queue and turnaround time, and comments often arrive in email threads the site team does not see. A single unanswered comment can hold a witness test, and with it the backfeed date and the guaranteed COD.

A connected operating model treats utility dates as obligations

Leading developers are beginning to manage the period between interconnection agreement and COD as a set of obligations, each with an owner on both sides of the handoff, a deadline and a cost for every day it stays open. A live layer reads the systems already in use, including utility portals, Primavera P6, SAP or Oracle, email and site messaging, and runs a four-step loop:

  1. Detect

    a change in a utility date as soon as it is posted, such as a revised in-service date for a breaker replacement at a remote substation.

  2. Explain

    which downstream milestones the change moves, from the protection settings review and witness test to the next outage window and the guaranteed COD.

  3. Recommend

    recovery options with owners and expected impact, such as closing the open settings comments within the week or splitting the tie-in into a shorter outage that fits the remaining window.

  4. Execute and track

    each agreed action with the utility and the EPC through to closure, measuring the days and dollars of exposure retired.

The same record can give the utility's interconnection engineer, the EPC and lenders one current view of open items, and give offtakers early notice when a utility date moves. Artificial intelligence does the reading, linking and drafting, including comparing each utility letter against the construction schedule, while the interconnection director and project director remain accountable for every commitment made to the utility.

A missed outage window can cost a 300 MW solar project $$169,000 a day

The cost of an interconnection delay is the daily revenue, financing carry and contractual exposure a project incurs while it is built and ready but waiting on utility upgrades, approvals or an outage window to energize.

A missed outage window that defers energization by five months could put about $$25 million at risk on a 300 MW solar project.

Exhibit 2. Estimated daily cost of delayed energization for a composite 300 MWac solar project

ComponentBasisEstimate per day
Energy revenue deferred or lostAbout 1,800 MWh a day at a 25 percent net capacity factor, priced at the Q2 2026 solar PPA market average of $$61.40 per MWh 78About $$110,500
Construction financing carryCapital cost of about $$510 million at $$1.70 per watt AC; assumes 60 percent drawn at a 7 percent all-in rate 7About $$58,700
Total before delay damages and tax credit riskSum of the two componentsAbout $$169,000

Source: Segeta estimate based on Lawrence Berkeley National Laboratory and LevelTen Energy data; financing assumptions are illustrative.

On these assumptions, a 30-day slip in energization puts about $$5.1 million at risk and a 60-day slip about $$10.2 million, while a missed outage window that defers backfeed by about 150 days could approach $$25 million. Partial offsets are limited, because EPC liquidated damages rarely cover delays caused by the utility and, in our experience, interconnection agreements seldom compensate the developer for a late upgrade. Offtake contracts may give some relief for grid-related delays, yet that relief is negotiated project by project and is usually capped.

What interconnection and project directors can do now

  1. 01Put every utility milestone on the critical path

    Load network upgrade in-service dates, outage requests, settings reviews and witness tests into the same schedule as construction, each with a named owner at the utility and at the developer.

  2. 02Book outage windows well before they are needed

    Request the tie-in outage as early as the utility's process allows and agree a fallback slot, since long outages in some regions are scheduled six months to a year ahead.6

  3. 03Read every utility letter on the day it arrives

    Assign one person to log each portal posting, study report and letter on receipt, and to compare its dates with the EPC schedule within two working days.

  4. 04Clear protection and telemetry comments within a week

    Treat relay settings and telemetry comments as critical path work, with a target turnaround and a standing weekly call with the utility's interconnection engineer.

  5. 05Attach a daily cost to every utility date

    Price each utility milestone in dollars per day, so a slipped upgrade date reaches leadership, lenders and offtakers in the same week it is posted.

Developers cannot build the transmission owner's upgrades or shorten its outage calendar, yet they can control how quickly a changed utility date becomes a decision on site. Those that manage utility obligations with the same discipline as construction are likely to protect their outage windows, shorten the gap between mechanical completion and COD, and earn credibility with the utilities they will connect to again.

Questions leaders ask

Why are solar interconnection delays getting longer?

Queues remain large and studies slow. Lawrence Berkeley National Laboratory reports that the median project built in 2025 took 61 months from interconnection request to commercial operation, including a median of 45 months to reach an agreement. After signing, the median project still needed 31 months to reach operation, up from 21 months in 2008, as network upgrades and utility approvals ran their course.

What happens after a solar project signs an interconnection agreement?

The transmission owner designs and builds any network upgrades, schedules the outage needed to tie in the new substation, reviews protection and relay settings, and witnesses commissioning tests before backfeed and energization. Each step has its own reviewer and calendar, and dates usually arrive through letters, portals and email, so the EPC schedule can miss a change for weeks.

How much does a delayed energization cost a solar project?

For a composite 300 MWac solar project, a Segeta estimate puts the cost at about $$169,000 a day, combining about $$110,500 of deferred energy revenue at Q2 2026 PPA prices and about $$58,700 of construction financing carry. A missed outage window that defers backfeed by about five months could therefore put roughly $$25 million at risk before delay damages.

Did FERC Order 2023 fix interconnection delays?

FERC Order No. 2023, issued in July 2023, moved transmission providers to cluster studies with 150-day deadlines and penalties for late studies, after 68 percent of interconnection studies completed in 2022 were issued late. The reform targets the study phase. The construction of network upgrades, outage scheduling and energization approvals that follow an agreement still depend on each transmission owner.

Notes and sources
  1. Lawrence Berkeley National Laboratory, "Queued Up: 2026 Edition, Characteristics of Power Plants Seeking Transmission Interconnection As of the End of 2025," June 2026, eta-publications.lbl.gov.
  2. Federal Energy Regulatory Commission, "Explainer on the Interconnection Final Rule," July 2023, ferc.gov.
  3. Lawrence Berkeley National Laboratory, "Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection," 2026 Edition summary, June 2026, emp.lbl.gov.
  4. William Driscoll, "Grid connection barriers and solutions for utility-scale renewables," pv magazine USA, January 17, 2025, pv-magazine-usa.com, reporting Lawrence Berkeley National Laboratory interconnection cost research.
  5. Neil Millar, California ISO, "Prepared statement on innovations and efficiencies in generator interconnection," FERC Docket AD24-9, August 27, 2024, caiso.com.
  6. PJM Interconnection, "Spring Means 'Shoulder Season' in PJM," Inside Lines, March 19, 2024, insidelines.pjm.com.
  7. Lawrence Berkeley National Laboratory, "Utility-Scale Solar, 2025 Edition," October 2025, emp.lbl.gov.
  8. LevelTen Energy, Q2 2026 North America PPA Price Index, as reported by TaiyangNews, July 23, 2026, taiyangnews.info.