#aptel

Mid-scale private generators must navigate multi-year jurisdictional appeals regarding fractional megawatt capacities, a legal mechanism that locks up operational bandwidth. Short-term green markets bear the consequence, starved of the liquidity these generators could otherwise provide to the broader exchange.

The Electricity Act of 2003 established the Appellate Tribunal for Electricity (APTEL) to resolve disputes between generators and state regulators. However, the tribunal's procedural timeline allows contract disputes over minor capacity ratings to drag on for decades. This framework legally forces independent generators to prioritize litigation survival and legal overhead over active participation in real-time or term-ahead power exchanges, sidelining the exact flexible capacity needed to balance the grid.

A Judgment / Appeal Order from the Appellate Tribunal for Electricity, dated 16th March, 2026, officially dismisses an appeal over a localized 18 Megawatt (MW) capacity reduction for a Power Purchase Agreement originating in 2007. In contrast, the Indian Energy Exchange GTAM_Trade Details for 16-03-2026 logs a symptomatic clearing volume of just 0.73 MWh in specific trading blocks. A 19-year legal battle over 18 MW acts as a tracer dye, proving that the appellate framework structurally traps the mid-scale capacity required to deepen the illiquid 0.73 MWh green term-ahead market.

Legal authorities argue that statutory due process cannot be accelerated simply because the megawatt capacity in dispute is small, maintaining that all contractual appeals require rigorous judicial scrutiny to ensure regulatory fairness. While legal equity is necessary, utilizing a 19-year supreme appellate process to resolve an 18 MW contract dispute structurally paralyzes the commercial agility of mid-scale power producers.

The Ministry of Power must establish a fast-track arbitration mechanism with a strict 180-day resolution limit for all capacity disputes under 100 MW. Without this regulatory reform, mid-scale independent power producers will remain legally stranded in appellate courts rather than actively participating in the short-term energy markets.

In a major retrospective correction, the Central Electricity Regulatory Commission (CERC) has reopened and recomputed tariffs for PGCIL’s Northern Region ULDC fiber-optic communication assets after the Appellate Tribunal for Electricity (APTEL) condoned earlier disallowed time overruns.

APTEL’s 2022 judgment (Appeal No. 15 of 2016) held that construction delays on two key assets were the consequence of external factors — including delayed participation by UPPTCL and PTCUL, and unavoidable fog-related safety constraints. With these delays no longer attributable to PGCIL, CERC rebuilt the capitalisation figures from the date of commercial operation (COD), triggering a full recalibration of tariffs across multiple regulatory windows.

The outcome is a rare multi-period reset: tariff adjustments across 2009–14, 2014–19, 2019–24, and a revised opening capital base for the ongoing 2024–29 block.

Fiber-Optic Assets at the Core of the ULDC Backbone

The assets under consideration are part of the Northern Region ULDC modernisation programme, which replaced ageing microwave links with a modern fiber-optic communication system using OPGW, underground cable, aerial cable, SDH equipment and a network management system.

Assets 1–4 are classified as system-operation related communication assets under Section 28(4) of the Electricity Act. Asset-5, however, is treated as a transmission element under Section 62 read with Section 79(1)(d), bringing it under a different tariff methodology. CERC’s order therefore spans both families of regulatory treatment.

IDC and IEDC Reinstated — Capital Cost Reset from COD

A central consequence of APTEL’s ruling is the reinstatement of Interest During Construction (IDC) and Incidental Expenditure During Construction (IEDC) for Asset-2 and Asset-3. These amounts were previously cut when CERC refused to condone delays back in 2015.

By restoring IDC/IEDC and adding them back to the COD capital cost, CERC altered the foundational asset value used in multiple tariff blocks. Even though the additions themselves are modest, the regulatory impact is significant because all subsequent years depend on the opening capital base.

2009–14: Minor Fee Corrections, Major Structural Shifts

CERC has recomputed fees and charges for 2012–13 and 2013–14 for the affected assets. The adjustments range from ₹0.05 lakh to ₹2.47 lakh — numerically small, but critical in shaping the capital recovery trajectory.

These revised figures become the opening capital cost for 2014–19, which in turn feeds into 2019–24 and sets the stage for 2024–29. What appears to be a modest historical correction ends up reshaping three tariff cycles.

True-Ups Reworked for 2014–19 and 2019–24

With the corrected capital base flowing forward, CERC recalculated:

normative loan–equity balances

depreciation and capital-recovery factors

interest on loan based on weighted average rates

post-tax RoE at 15.5%

interest on working capital

This ensures that beneficiaries neither overpay nor underpay relative to the adjusted capital structure.

2024–29: New Period, Clean Opening Balance

For the ongoing control period, CERC has approved fresh fees and charges for communication assets and transmission tariff for Asset-5 under the 2024 Tariff Regulations.

The Commission applied updated O&M trajectories, revised benchmark rates for working capital, and the new tax/gst pass-through framework. Standard regulatory permissions to PGCIL — including income tax recovery, filing for security/insurance expenses, and claiming capital spares — have also been reaffirmed.

A Corrective Exercise with Limited Financial Shock

Despite the years being re-opened and recomputed, the financial impact on beneficiaries is limited: small upward adjustments in 2012–14 and modest realignments in later periods.

But the regulatory cleanup is substantial. CERC has now aligned all periods with APTEL’s findings, corrected historical inconsistencies, and ensured the ULDC fiber network’s asset values reflect actual allowable capitalisation from COD through 2024–29.

A Precedent for Future Delay-Related Appeals

The order reaffirms an important regulatory principle: where delays stem from beneficiary-driven or uncontrollable factors, the CTU cannot be penalised. It also shows how APTEL’s decisions cascade into tariff arithmetic many years down the line — affecting both historical true-ups and future tariff frameworks.

For the Northern Region’s communication backbone, the tariff architecture is now consistent, corrected and transparent — exactly as APTEL intended.

APTEL’s latest ruling sends a powerful message to generating utilities: once new regulations come into force, compliance must shift fully to the updated framework. Transition periods may be challenging, but they cannot be used as a defence for procedural lapses.

What RRVUNL Argued

RRVUNL claimed that several units including Kota TPS Unit-7, Suratgarh TPS Unit-6, and Chhabra TPS Units 1 ,2 were conceived under the 2009 regulations but reached COD under the 2014 regime.

The utility said this created a “regulatory twilight zone” where final capital expenditure and closing activities couldn’t neatly match the 2014 cut-off provisions.

Why APTEL Rejected the Argument

APTEL held that once the 2014 Regulations became effective, all tariff petitions — even for ongoing projects — had to align with the new framework.

Key points APTEL highlighted:

No automatic exemption during regulatory transition

Compliance is a continuous responsibility

Documentation must match the prevailing code

Relaxation Clauses Not Automatically Applicable

RRVUNL cited Regulation 2(17), its proviso for extensions, and Regulation 94 (relaxation powers). However, APTEL found that:

RRVUNL never sought an extension formally

No evidence was submitted showing delays beyond control

Relaxation powers must be invoked through a reasoned petition

In short: exceptions cannot be claimed retroactively.

Tribunal’s Core Principle

Regulatory transition does not suspend regulatory compliance.

Once a new tariff regulation is notified:

Cut-off dates must be respected

Documentation must be aligned

Tariff claims must meet updated procedural requirements

Legacy project timelines do not override current obligations.

What This Means for the Power Sector

This ruling strengthens regulatory accountability:

No automatic grandfathering of past projects

No retrospective condonation without evidence

Stricter scrutiny of capital expenditure claims

Greater procedural discipline expected across utilities

It also reflects a consistent trend across regulatory bodies and tribunals in India.

Gujarat keeps the 7–11 AM To U morning peak not because the data proves a peak exists, but because removing it risks creating one.

APTEL wanted a clean, fresh, empirical re-evaluation of the morning peak classification.

Because when you look at load data in Gujarat 7–11 AM does not display a conventional peak.

So logically: if there is no peak, why keep the premium?

What GERC argued instead

The morning curve is flat because the penalty exists. The price signal itself is suppressing the possible peak.

If you remove that signal the peak may reappear.

This is stability-by-policy not natural equilibrium of consumption behaviour.

PGVCL’s framing

daily load curve in Gujarat is shaped over 20 years of ToU + agriculture feeder scheduling

HT industrial consumers have already shifted what can be shifted

stability is artificially engineered therefore cannot be treated as “evidence” against the peak

The Meghraj study angle

While the study wasn’t written to test the 7–11 AM block directly GERC used it as contextual validation.

Small load shifts matter. They prevent certain network reinforcements + avoid costlier procurement in stressed hours.

Industry argued the opposite

If the data doesn’t show a peak → the premium is legacy inertia.

GERC rejected that. Continuity wins.

Final result

Morning peak stays

ToU rates FY 2016–17 unchanged

No new empirical study ordered

The deeper India tariff reality

Once a demand smoothing tool embeds inside the system… unwinding becomes politically + grid-operationally high risk.

The price of stability → is postponing discovery.

We don’t know if the 7–11 AM peak is real anymore because we refuse to test it.

For more

The Appellate Tribunal for Electricity (APTEL) has rejected the review petition filed by IPCL, confirming its December 2024 order that prioritises wind energy first, then STOA, and finally PGVCL supply. The dismissal removes ambiguity for Gujarat’s wind power developer ecosystem.

The bench ruled that no “self-evident error” existed and reiterated that review power is limited to glaring omissions. For every wind power developer, this means energy settlements will continue under the WTG-first rule, with surpluses valued at 85 %.

The judgment underscores that commercial grievances cannot reopen concluded interpretations. It strengthens investor confidence in wind power developer frameworks where sequencing stability governs return calculations and compliance.

More verified regulatory insights on EnergylineIndia.com, India’s independent energy-intelligence platform tracking wind power developer and renewable policy

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The 2010 WTG-first principle and 85% deemed-sale rule remain valid after the review dismissal. Utilities can continue settlement under the 2024 hierarchy.

Tribunal affirms earlier sequencing order

The Appellate Tribunal for Electricity (APTEL) has dismissed Review Petition No. 11 of 2025 filed by Investment & Precision Castings Ltd (IPCL) against its 3 December 2024 judgment in Appeal 339 of 2018. That earlier judgment had re-sequenced Gujarat’s multi-source energy accounting, giving first priority to wind-turbine generation (WTG), followed by Short-Term Open Access (STOA) energy, and finally distribution supply from PGVCL.

With the latest order dated 3 November 2025, the bench of Mr Virender Bhat (Judicial Member) and Ms Seema Gupta (Technical Member-Electricity) has reaffirmed the 2010 WTG-first clause and the 85 % deemed-sale pricing rule for monthly surpluses—closing a multi-year challenge.

Consumer’s banking-loss argument rejected

IPCL alleged a financial loss of ₹ 30.65 lakh in denied six-month banking benefit and ₹ 3.37 lakh from curtailed deemed-sale credit. The petitioner claimed APTEL’s 2024 formula ignored historical wheeling agreements (2006 and 2010) and the 2002 banking policy, terming it a “manifest error.”

The Tribunal disagreed, holding that the petition sought to substitute methodology rather than correct a self-evident mistake—and therefore amounted to an appeal in disguise. Only patent or apparent errors qualify for review, not interpretive disagreements.

Law of review strictly applied

Citing Order XLVII Rule 1 CPC and Supreme Court precedents—Kamlesh Verma v. Mayawati (2013) and S. Madhusudhan Reddy v. V. Narayana Reddy (2022)—the Tribunal reiterated that review powers extend solely to “glaring omissions or mistakes apparent on the record.” Erroneous decisions must be corrected through appeal, not re-hearing. Finding no fresh evidence or self-evident error, the bench declined jurisdiction to reopen the case.

Outcome and implications

APTEL concluded that no patent mistake or omission existed in its December 2024 ruling, dismissing the review petition without costs.

For Gujarat’s distribution licensees, the decision secures continuity of the 2024 settlement hierarchy— 1️⃣ WTG energy first (2010 WTG before 2006 WTG, surplus sold at 85 %), 2️⃣ then STOA energy, 3️⃣ and finally PGVCL supply.

For captive consumers, it clarifies that banking-benefit or tariff-valuation disputes must be raised before the regulator or via statutory appeal, not through review.

Final takeaway