CEA Guidelines for Solar Power Plants: 2019 Grid Rules

These CEA guidelines for solar power plants matter to every developer and EPC designing a grid-connected project. Every solar project connected to the Indian transmission or distribution network, from a 1 MW rooftop to a 500 MW utility-scale plant, must meet the Central Electricity Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007, as amended in 2019.

The 2019 amendment to the 2007 connectivity standards introduced new technical standards, application timelines, grid code compliance requirements, and evacuation planning norms that every solar developer and EPC must understand before the design stage begins.

Quick answer. CEA guidelines for solar power plants are the Central Electricity Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007, as amended. The 2019 amendment was notified on 6 February 2019 (gazette of 8 February 2019, Internet Archive capture). It added connectivity standards for generating stations using inverters, including a voltage-dip ride-through curve and an over-voltage ride-through table, and it applies to connection at 33 kV and above. Reactive power capability of 0.95 lagging to 0.95 leading comes from the earlier 2013 amendment for new generating stations.

This guide is a working reference, built from the CEA technical standards and the CERC and state connectivity procedures, for solar developers and EPCs, covering the application process, technical standards, interconnection study requirements, and the clauses most likely to affect your project timeline and budget.

Background: What the 2019 Regulations Changed

The CEA (Technical Standards for Construction of Electrical Plants and Electric Lines) Regulations 2010 and the earlier CEA Connectivity Regulations 2007 formed the previous framework. The full text of the CEA Connectivity Regulations 2019 (official gazette) is the authoritative reference for all connectivity applications. The 2019 overhaul was driven by three factors:

1. Renewable energy growth, the 2007 framework was designed for thermal power plants. Solar and wind projects have fundamentally different generation profiles (intermittent, no spinning reserve, inverter-based), which required new technical standards for ride-through capability, reactive power, and fault response.

2. Grid stability requirements, at 10 GW of solar on the grid (2017), frequency management was manageable. At 100 GW+ (2024), every solar plant needs to meet specific grid support requirements or the cumulative effect destabilises frequency control.

3. Evacuation planning gaps, the 2007 framework allowed connectivity applications without evacuation infrastructure confirmation, leading to stranded projects where generation capacity existed but transmission lines did not.

Freshness note. CEA has published a draft of the Central Electricity Authority (Technical Standards for Connectivity to the Grid) Regulations, 2026, dated 31 July 2026, which would replace the 2007 regulations and their amendments. It is a draft, and we have not reviewed its content here, so do not treat it as final. See the draft notification (Internet Archive capture, 3 October 2026) and check the CEA site for the final text.

Who the Regulations Apply To: Scope and Classification

Solar projects are classified by interconnection point and route, and the eligibility thresholds differ by route: Many applicants are SECI auction winners, so align filings with the SECI tender calendar.

Project Type	Typical Interconnection	Applicable Authority	Eligibility Threshold
Rooftop / Distributed	LT/HT DISCOM feeder	State DISCOM	Set by the state DISCOM rules
Intra-state utility scale	STU network	STU (State Transmission Utility)	Set by the state. Example: 5 MW and above (MERC TOA 2016, Reg. 5.1, base text)
Inter-State / Central	CTU network	CTU (CTUIL)	50 MW and above, alone or aggregated (CERC GNA Regulations 2022, Reg. 4.1(a))
Solar Park Projects	Pooling substation within solar park	SECI / Solar Park Developer + STU	Through the park developer

The Connectivity Application Process, Step by Step

The CEA technical standards do not set the application process. For inter-state (CTU) connectivity it is set by the CERC (Connectivity and General Network Access to the inter-State Transmission System) Regulations, 2022 and the CTUIL procedure. For intra-state (STU) connectivity it is set by the state’s open access regulations and the STU’s procedure. The four steps below are a generic outline, and the figures quoted come from the sources named in each step:

Step 1, Preliminary Connectivity Application (PCA)

Submit the PCA to the STU/CTU connectivity cell with:

• Site location (GPS coordinates, survey numbers)
• Proposed installed capacity (DC and AC)
• Evacuation voltage and proposed substation
• Preliminary single-line diagram (SLD)
• Land ownership / lease documentation
• Power Purchase Agreement (in-principle) or PPA intent letter

Decision timelines depend on the route. Under CERC Regulations 2022, Reg. 7, the CTU gives in-principle grant of connectivity within 60 days from the last day of the month of application where no augmentation is needed, and within 90 days where augmentation is needed. Under the MERC (Transmission Open Access) Regulations, 2016, Reg. 6.9 (base text, amendments not checked), the Maharashtra STU decides within 30 days of a complete application. Under the GERC-approved Gujarat procedure dated 7 January 2023, cl. 7.3, Stage-I grant is within 60 days, although GETCO has since listed a newer procedure approved on 4 August 2025 that we have not read. For any other state, use the STU’s current published procedure.

Step 2, Interconnection Study (ICS)

The STU or CTU runs the interconnection study to the CEA technical standards (CERC Regulations 2022, Reg. 6.1; MERC Transmission Open Access Regulations 2016, Reg. 6.1). The regulations read do not fix a single study duration. The study determines:

• The technically feasible injection point and voltage level
• The grid infrastructure upgrades required to evacuate the project’s generation
• The inter-connection equipment specifications (GIS/AIS substation, transformer, lines)
• The grid code compliance requirements specific to the injection point

Application fees are set by the route. CERC Regulations 2022, Reg. 3.2, set ₹5 lakh plus taxes for inter-state connectivity. The MERC Transmission Open Access Regulations 2016, Reg. 5.2 (base text, amendments not checked), set ₹1 lakh for renewable generators and ₹2 lakh otherwise. Other states set their own fees, so confirm with the STU.

Step 3, Connectivity Agreement

After the interconnection study, the developer signs the Connectivity Agreement (under CERC Regulations 2022, Reg. 10.1, within 30 days of the final grant). The agreement specifies:

• Point of common coupling (PCC) and injection voltage
• Power injection capacity
• Technical compliance standards (see §4 below)
• Evacuation timeline and milestones
• Security for the interconnection infrastructure (CERC Regulations 2022, Reg. 8, require connectivity bank guarantees: ₹50 lakh at application, a per-bay amount, and ₹2 lakh per MW)

Step 4, Detailed Engineering and COD Declaration

With the connectivity agreement signed, the developer can proceed to EPC contract award and detailed engineering. The CEA regulations require that all interconnection equipment meet the technical standards before COD declaration. The STU/CTU conducts a commissioning inspection before issuing the COD certificate.

What do the CEA guidelines require of a solar power plant?

This is the section most solar engineers need to understand for detailed design. The CEA Connectivity Regulations 2019 reference the CEA Technical Standards for Construction of Electrical Plants and Electric Lines (Amendment) Regulations 2019 for technical requirements. Key technical standards relevant to solar: Grid code compliance is proven at handover with tests like those in our IEC 62446 acceptance testing guide.

Reactive Power and Power Factor

Under the CEA connectivity regulations as amended in 2013, a generating station connected after the amendment took effect must be capable of supplying dynamically varying reactive power so as to maintain power factor between 0.95 lagging and 0.95 leading (gazette of 15 October 2013, Internet Archive capture of the CEA PDF). Confirm the current text and any later amendment before design. For utility-scale projects, this typically means:

• String/central inverters must have reactive power control capability
• For projects above 10 MW, a dedicated reactive power compensator (SVC or STATCOM) may be required if the grid impedance at the injection point is high
• Power factor control must be automatic, not manual, and must respond to grid operator instructions via SCADA

Frequency Ride-Through

The same 2013 amendment requires generating units to be capable of operating in the frequency range of 47.5 Hz to 52 Hz and to deliver rated output between 49.5 Hz and 50.5 Hz. Low-voltage ride-through (LVRT) and high-voltage ride-through (HVRT) requirements, and the frequency response and trip settings used at a given plant, come from the applicable grid code and the utility’s connection conditions, so take them from those documents for your project.

Metering Standards

Energy metering at the inter-connection point is specified by the utility’s connection agreement and the applicable metering regulations and grid code, including the accuracy class, whether a backup meter is needed, and who must test and seal the meters. We have not verified a single national figure here, so take the accuracy class and meter arrangement from the connection agreement and confirm them with the STU or CTU before ordering meters.

Protection Requirements

Protection for solar generating stations is set by the utility’s connection conditions and the CEA technical standards, and the protection scheme typically includes the following functions to confirm with the utility:

• Over/under voltage protection at the inter-connection point
• Over/under frequency protection (coordinated with the frequency ride-through requirements)
• Differential protection for the generator transformer (or inter-connection transformer)
• Distance protection or directional overcurrent protection for inter-connection lines above 33 kV
• Anti-islanding protection (mandatory for all inverter-based generators)

The CEA Connectivity 5-Document Framework

Every CEA connectivity application requires a 5-Document Framework, an illustrative checklist of engineering submissions that connectivity cells commonly review. It is not a statutory list. Each STU and CTUIL publishes its own document list, so confirm it before filing (see our STU connectivity guide).

Solar Park Connectivity: How It Differs from Direct Connectivity

Projects located within SECI or state government solar parks have a different connectivity pathway. The solar park developer obtains a pooling-substation connectivity from the STU, and individual project developers within the park connect to the park’s pooling substation, not directly to the STU network. Rajasthan is the largest example; see our Rajasthan solar park policy guide.

This means the CEA 2019 connectivity application is filed by the solar park developer, not the individual project developer. The individual project’s engineering team needs to:

• Obtain the solar park’s internal pooling substation SLD
• Design the project’s internal substation to match the pooling substation specifications
• Ensure the project’s metering and protection systems meet both the applicable CEA standards and the solar park’s internal grid code

The open access in solar parks mechanism adds another layer when power is sold to third parties rather than under the solar park’s standard PPA, the open access connectivity requires a separate SLDC registration.

Comparing CTU vs STU Connectivity for Utility-Scale Solar

Before choosing a route, check whether the substation appears in the current CTUIL or STU plan. Our guide to STU vs CTU solar transmission planning explains both plan cycles, and our STU connectivity guide lists the application documents state by state.

Dimension	STU Connectivity (State)	CTU Connectivity (Inter-State)
Authority	State Transmission Utility (TRANSCO/STU)	Central Transmission Utility (CTUIL)
Applicable voltage	33 kV - 220 kV (state-level)	220 kV - 765 kV
Eligibility by size	Set by the state. Example: 5 MW and above (MERC TOA 2016, Reg. 5.1, base text)	50 MW and above, alone or aggregated (CERC GNA Regulations 2022, Reg. 4.1(a))
Grant timeline	Set by the state. Example: 30 days from a complete application (MERC TOA 2016, Reg. 6.9, base text)	60 days (90 with augmentation) from the last day of the month of application (CERC GNA Regulations 2022, Reg. 7)
Application fee	Set by the state. Example: ₹1 lakh renewable, ₹2 lakh otherwise (MERC TOA 2016, Reg. 5.2, base text)	₹5 lakh plus taxes (CERC GNA Regulations 2022, Reg. 3.2)
Grid code	State SERC grid code	CERC Grid Code / IEGC
Dispute resolution	State SERC	CERC

For SECI tenders above 500 MW (e.g., Phase II RE parks, ISTS-connected projects), the CTU connectivity is obtained by SECI as the nodal agency, and individual developers connect under SECI’s connectivity umbrella, significantly simplifying the individual project’s regulatory burden.

Common Connectivity Rejection Reasons: The Solar Developer’s Risk Register

According to Mercom India’s 2024 connectivity delay analysis, the top five reasons for CEA connectivity application rejection or delay are:

1. Incomplete SLD, missing metering, protection, or earthing details on the preliminary SLD submitted with the PCA. The STU cannot conduct the interconnection study without a complete SLD showing all major equipment from DC to injection point.

2. Evacuation route not confirmed, submitting a connectivity application before verifying that the proposed evacuation route (transmission line corridor) is available. Forest land, railway crossings, and existing infrastructure on the proposed line route require separate clearances that can delay the interconnection study indefinitely.

3. Capacity mismatch with available grid capacity, the available capacity at a substation differs by site. An application for a project larger than the capacity available at the proposed injection point can require grid augmentation before connectivity is granted, which adds time. Check the STU’s published substation capacity list for the month you apply.

4. Non-compliant protection scheme, submitting a protection philosophy that does not meet the CEA 2019 protection requirements (particularly anti-islanding, LVRT, and distance protection for HV lines). The STU protection review is a separate approval gate from the connectivity approval.

5. Security deposit and fee non-payment, an application without the required fee, bank guarantee or documents is incomplete, and the STU or CTU will not process it. Check the route’s procedure for what must accompany the application.

How Heaven Designs Helps

The connectivity engineering documentation, the preliminary SLD, technical parameters sheet, protection scheme drawing, and substation layout, must be accurate and complete at the PCA stage to avoid rejection. Heaven Designs delivers connectivity-ready engineering packages for solar projects from 1 MW to 500 MW, with drawings formatted to the specific requirements of each state’s STU submission format.

• Electrical CEIG Drawings, CEA-compliant SLD, protection scheme, metering diagram for STU/CTU submission.
• Solar Ground Mount Design, full EPC design package including substation layout, evacuation line routing, and SCADA architecture.
• Engineering Documentation India, complete connectivity application document pack: SLD, technical parameters, protection philosophy, site plan.
• MW-Scale PMC, owner’s engineer for managing the connectivity application and interconnection study process.
• Download a sample deliverable, see a CEA-compliant preliminary SLD formatted for STU submission.

Contact us to begin your connectivity application documentation.

FAQ

What is the difference between CEA connectivity and DISCOM net metering for solar projects?

The CEA connectivity technical standards, as amended in 2019, apply to generators connecting to the grid at 33 kV and above (the 2019 amendment’s definitions of requester and user use that threshold). DISCOM net-metering regulations apply to smaller projects connecting to the distribution network, with the size limits set by each state. A rooftop solar project under the MNRE PM Surya Ghar scheme applies for DISCOM net metering, not CEA connectivity. A 50 MW utility-scale project applies for CEA connectivity to the STU or CTU, not DISCOM net metering.

How long does the CEA connectivity application process take from submission to COD?

There is no single timeline, because the route sets it. For inter-state connectivity, CERC Regulations 2022, Reg. 7, give in-principle grant within 60 days (no augmentation) or 90 days (augmentation), and the connectivity agreement follows within 30 days of final grant (Reg. 10.1). For intra-state connectivity, the state sets the timeline (for example, 30 days from a complete application under the MERC Transmission Open Access Regulations 2016, base text). Site clearances, line construction and substation work then decide the date to COD, which we have no source to put a figure on.

Does the CEA 2019 regulation require specific inverter certifications?

The CEA 2019 regulations reference grid code compliance rather than specific inverter certifications. However, the inverter must be capable of meeting the frequency ride-through, reactive power, and LVRT requirements specified in the regulations. In practice, inverters used for grid-connected solar projects must meet IEC 62116 (anti-islanding), IEC 61727 (grid interface), and the CEA Technical Standards for power quality and protection.

Separately, inverters sold for use in India must complete BIS solar inverter certification, and ALMM Part III registration is required for government-scheme projects.

Can a solar developer get connectivity approval before obtaining a PPA?

It depends on the state. In Gujarat’s GERC-approved 2023 procedure, the Stage-I application documents in cl. 6.2 (affidavit, fee, board resolution, company documents) do not include a PPA, while Stage-II (cl. 8.2.1) needs a letter of award, letter of intent or PPA. The CEA technical standards do not decide this. Check the STU procedure of the state where you connect.

What is the security deposit required for a CEA connectivity application?

The CEA regulations do not set one. For inter-state connectivity, CERC Regulations 2022, Reg. 8, require three connectivity bank guarantees: ₹50 lakh at application, a per-terminal-bay amount (₹1 crore below 132 kV, rising to ₹12 crore at 765 kV), and ₹2 lakh per MW. For intra-state connectivity, the amount is set by the state’s procedure.

Source: CERC (Connectivity and General Network Access to the inter-State Transmission System) Regulations, 2022, consolidated with amendments. State fees and deposits are in each STU’s published procedure.

What protection relay standards apply to solar generating stations under CEA 2019?

Solar generating stations must provide: over/under voltage protection (ANSI 59/27), over/under frequency protection (ANSI 81O/U), directional overcurrent protection (ANSI 67) for HV inter-connection lines, differential protection (ANSI 87T) for the inter-connection transformer, and anti-islanding protection meeting IEEE 1547-2018 or the equivalent IEC 62116 standard. The protection relay settings must be coordinated with the STU’s existing protection philosophy and approved by the STU’s protection engineering team before commissioning.

How do the CEA 2019 regulations interact with state SERC regulations for solar projects?

The CEA 2019 regulations set minimum national standards for connectivity. State Electricity Regulatory Commissions (SERCs) can and do impose additional requirements in their state-specific grid codes and renewable energy procurement regulations. For example, some SERCs mandate harmonic analysis reports, power system stabiliser (PSS) studies for large projects, or specific local earthing standards.

The CEA 2019 connectivity approval must be read in conjunction with the applicable SERC regulations. According to the CEA’s technical standards framework, state-specific requirements that exceed the CEA minimum are enforceable by the SERC and must be met for COD clearance.