Updated September 26, 2026 · Market steps checked against live sources where marked
Every solar, wind, or storage project needs permission to connect to the grid, and it is often the longest and most expensive step. Who you apply to depends on the project's size and where it is.
Two paths. Small projects that connect to local distribution lines (in Texas, generally under 10 MW and below 60 kV) apply to the local utility. Large projects that connect to high-voltage transmission apply through the regional grid operator's queue (ERCOT, SPP, MISO, and others) and work with the transmission owner.
Texas utilities: where to apply
Your electric bill names your delivery utility. Distribution interconnection in Texas follows PUCT rules 25.211 and 25.212. The PUC has been drafting revisions (Project 54233, including a new rule 25.210 for projects over 250 kW); see the May 2025 discussion draft and check the PUC for its current status.
Oncor ERCOT · Dallas–Fort Worth and much of North, Central, and West Texas
Application and study-fee addendum by mail, fax, or email. Email: Residential_DG@centerpointenergy.com or Commercial_DG@centerpointenergy.comDER application package (PDF)
TNMP (Texas-New Mexico Power) ERCOT · Parts of North-Central, Gulf Coast, and West Texas
We could not confirm a dedicated interconnection page. Contact TNMP; distribution interconnection follows PUCT rules 25.211 and 25.212.TNMP website (company home page)
El Paso Electric Western grid (WECC) · El Paso area
Texas process for facilities up to 10 MW, with technical requirements and inspection before energizing.Texas interconnection up to 10 MW
Entergy Texas MISO · Southeast Texas
Application package, interconnection agreement, W-9, and one-line diagram; utility-approved outside disconnect required. Large projects go through the MISO queue.Net metering and interconnectionMISO queue (below)
Xcel Energy (SPS) SPP · Panhandle and South Plains
Large generators interconnect to the SPS transmission system through SPP’s queue; Xcel publishes separate guidelines for transmission-connected generation over 20 MW. We could not confirm a dedicated small-system page.Xcel Energy (company home page)SPP queue (below)
City utilities and electric co-ops Varies · Throughout Texas
Municipal utilities (for example Austin Energy and CPS Energy) and electric cooperatives set their own interconnection rules. Contact the utility named on the electric bill.
Transmission-level projects in ERCOT: file a generation interconnection request with ERCOT (see ERCOT below) and sign an interconnection agreement with the transmission owner. PUCT Rule 25.195 sets how much of the connection cost the transmission owner covers.
Checked against live sources 2026-09-25 · States: Texas
Applies to generation adding 10 MW or more at the point of interconnection (Planning Guide 5.1.1); under 10 MW goes through the TDSP distributed generation process, with an ERCOT INR still required for registration
Submit the Generation Interconnection or Change Request (GINR) in RIOO-IS and pay the fees in the current ERCOT Fee Schedule (the interconnection and full-study fees were restructured in 2023 under NPRR1153, so older $5,000/$7,000 figures are out of date); ERCOT confirms completeness within 10 business days
ERCOT Security Screening Study: up to 90 days, typically ~45
Within 180 days of screening results, elect to proceed to the Full Interconnection Study (FIS) or the GINR is cancelled and you start over with a new fee
FIS run by the host TSP (kick-off meeting within 10 business days of your election): steady-state N-1/N-2, dynamics, short circuit, reactive capability, and sub-synchronous resonance where flagged; 40–300 days depending on POI
ERCOT accepts the FIS (10–15 days); within 180 days execute the Standard Generation Interconnection Agreement (SGIA) with the TSP or the GINR is cancelled. All SGIAs signed on or after Jan 1, 2026 use the Nov 6, 2025 form approved in PUCT Project 58211
Cost shift for SGIAs executed after Dec 31, 2025: under PUCT Rule 25.195 the TSP funds transmission interconnection facilities only up to a CPI-indexed allowance ($14.408 million for 2026 at 138 kV and below; above 138 kV the rule set an initial $22.5 million, also CPI-adjusted each year); the developer pays the rest. Earlier SGIAs had the TSP fund all of it, with deposits refunded at COD
Registration and modeling: Resource Asset Registration Form (RARF), QSE designation, ERCOT-polled settlement meter, ICCP data link, PUCT registration for most Resource Entities
Energization, synchronization, and commissioning under the ERCOT New Generator Commissioning Checklist, then commercial operations
Overall expectation for ≥10 MW: roughly 18–30 months from GINR to commissioning, before equipment and construction delays (consultancy estimate, not an ERCOT commitment)
Checked against live sources 2026-09-25 · States: Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wyoming
SPP replaced its old DISIS cluster process with the Consolidated Planning Process (CPP), accepted by FERC and effective March 1, 2026. Transmission planning and generator interconnection now run as one cycle
Annual application window, December 15 to January 15 (the transitional 2026 window ran April 1 to May 31, 2026). Applications need complete technical models, 100% site control, and financial security
Annual Interconnection Cluster Study (about 180 days) with a single decision point
Upfront, standardized GRID-C charges for network upgrades instead of open-ended cost allocation, then the Generator Interconnection Agreement
Commissioning, model validation, and commercial operation
Checked against live sources 2026-09-25 · States: Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, Wisconsin
Apply in the Definitive Planning Phase (DPP) cycle: the DPP-2026 application deadline is January 15, 2027. MISO applies regional queue caps, and some regions (East/ITC) have already hit their 2026 cap
At application: non-refundable D1 fee ($7,600), D2 study deposit, M2 milestone of $8,000 per MW (cash or letter of credit), and M1 technical data. Site control is due at least 90 days before DPP Phase I kick-off
DPP Phase I, II, and III system impact studies with decision points between phases; penalty-free withdrawal only if upgrade costs rise past set thresholds, otherwise part of M2 is at risk
Generator Interconnection Agreement tendered and executed with MISO and the transmission owner, with further milestone payments
Expedited Resource Addition Study (ERAS) is a separate fast path limited to projects meeting a load-serving entity reliability need
Checked against live sources 2026-09-25 · States: Delaware, District of Columbia, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia, West Virginia
New requests go through annual Cycles under PJM Manual 14H. Cycle 1 closed April 27, 2026; the next Cycle window is announced by PJM. A separate Expedited Interconnection Track exists for qualifying projects ($15,000/MW readiness deposit plus a $500,000 study deposit, both at risk once the application is valid)
Application: executed Application and Studies Agreement, site control evidence, study-ready PSS/E power-flow and dynamic models, a tiered study deposit ($75,000–$400,000 by size), and Readiness Deposit No. 1 ($4,000/MW)
Phase I system impact study, then Decision Point I: withdraw or post Readiness Deposit No. 2 (a share of the Phase I network upgrade cost)
Phase II system impact study and Decision Point II (PSCAD/EMT models due at DP2 for bulk power system projects), then Phase III and Decision Point III
Final agreement negotiation: Generation Interconnection Agreement and construction service agreements, then interconnection facilities, model validation, and commercial operation
Checked against live sources 2026-09-25 · States: California, Nevada
Cluster 16 application window: October 1 to October 15, 2026 (5:00 p.m. Pacific), through the Grid Resource Interconnection Portal. Treat October 8 as the practical deadline, since later filings may not get a chance to cure deficiencies. Distribution-level (WDAT) windows run earlier by utility
Application fee $5,000 plus study and site-control deposits; site exclusivity and a technically valid model package required
Intake scoring and zonal screening under the Interconnection Process Enhancements (IPE 2023 and IPE 5.0): commercial interest (including load-serving entity interest), project viability, and system need decide which requests enter the study
Cluster study: system impact and facilities, with network upgrade allocation; Generator Interconnection Agreement and financial security postings
Deliverability allocation (Full Capacity Deliverability Status is needed to sell Resource Adequacy) and New Resource Implementation to COD
Checked against live sources 2026-09-25 · States: New York
The old Class Year process has been replaced by a cluster study under FERC Order 2023 (transition cluster began August 1, 2024). An optional, rolling pre-application process is available
Next cluster (the 2026 Cluster): NYISO announces the window date; the window is expected to be about 45 days. Application fee plus a study deposit scaled to project size, site control, and a physical-infeasibility screen
Phase 1 cluster study, then Phase 2 including deliverability, with decision points and additional deposits
Interconnection agreement with NYISO and the connecting transmission owner, security postings
Commissioning, market registration, and commercial operation; ORES siting runs in parallel for projects of 25 MW or more
Checked against live sources 2026-09-25 · States: Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont
First full cluster request window: October 5 to November 19, 2026. Requests are accepted only during a window
Complete request package with site control and financial requirements; ISO validates the request, then a customer engagement window and cluster study scoping meeting follow
Cluster study of all requests together (thermal, voltage, stability, short circuit), with withdrawal penalties; some clusters are enabled by a Cluster Enabling Transmission Upgrade (CETU)
Interconnection agreement with ISO New England and the transmission owner
Capacity market qualification (the market is moving to a prompt/seasonal design) and commercial operation
From our notes; not yet checked against live sources. Confirm with the operator or utility. · States: Alabama, Florida, Georgia, Mississippi, North Carolina, South Carolina
Interconnection request to the serving utility under its FERC-jurisdictional OATT (LGIP or SGIP), filed via OASIS
Cluster or serial study per the utility’s Order 2023 procedures: system impact, then facilities
Interconnection agreement (LGIA/SGIA) with security postings
Transmission service request if the offtaker is elsewhere
Commissioning and commercial operation; state PSC certificate may run in parallel
From our notes; not yet checked against live sources. Confirm with the operator or utility. · States: Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Texas, Utah, Washington, Wyoming
Interconnection request to the transmission provider under its OATT LGIP/SGIP via OASIS
Cluster study under Order 2023 procedures with deposits and site control
Facilities study and upgrade cost allocation
Interconnection agreement and security
Market participation through the Western Energy Imbalance Market or Extended Day-Ahead Market where the utility participates
Check before you file. Queue rules, fees, and windows change often. Confirm on the operator's or utility's site. This page is general information, not legal or engineering advice. Found an error? Let us know.