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By a professional energy-sector journalist | Originally published on EnergyLineIndia.com

Gujarat’s winter power strategy is now in motion. Petition No. 2569 of 2025, filed before the Gujarat Electricity Regulatory Commission (GERC), reveals Gujarat Urja Vikas Nigam Limited’s (GUVNL) detailed blueprint to manage the high-stakes December–March window — a season where volatility, not demand, defines the grid.

GUVNL’s move isn’t routine. It’s a deliberate hedge a winter power insurance policy designed to secure supply at predictable rates through Round-the-Clock (RTC) and peak power procurements.

This strategy ensures Gujarat won’t have to scramble later, when real-time prices spike.

Winter isn’t about demand it’s about volatility

Between December and March, Gujarat’s system faces sharper risks:

Wind collapses

Solar hours shrink

Hydro dispatch stays fixed

Industrial clusters run full throttle

GUVNL’s procurement design directly reflects this reality:

500–800 MW RTC power: the risk-absorbing base layer.

500–600 MW Peak power: the volatility shield for the 6–10 p.m. risk window.

By asking the Commission to adopt tariffs discovered through the DEEP portal’s reverse auction, GUVNL is paying a controlled premium now — instead of facing unpredictable costs later.

What bidder behaviour reveals

The petition’s technical reports tell a clear story about market psychology this winter:

RTC drew the most competition. Predictable revenue makes RTC contracts attractive for suppliers.

Peak slots saw fierce last-minute trimming. Everyone wanted the lucrative evening block, but margins were razor-thin.

Reverse auctions worked as designed. Prices compressed within narrow bands proof that competition is real, but still rational.

In short: everyone wanted in, but nobody was reckless.

For GUVNL, it’s price insurance not capacity hoarding

Gujarat’s base power remains strong. Its coal and lignite fleet is stable, and renewable additions are consistent.

But winter risk isn’t about base-load — it’s about:

evening peaks,

older thermal units tripping, and

renewable variability.

Short-term procurement gives GUVNL flexibility without long-term cost commitments. Even if the winter tariff looks slightly higher, it’s still cheaper than buying at double-digit exchange rates during scarcity hours.

So this petition isn’t just regulatory paperwork it’s strategic risk management.

Why this matters for the wider sector

Two trends stand out across India’s short-term market:

Winter procurement is now structural. GUVNL has institutionalised the December–March buying cycle setting a model other states are beginning to follow.

Reverse auctions compress margins, not opportunities. Tight competition hasn’t scared off suppliers it’s made the short-term market more disciplined, predictable, and transparent.

The bottom line

Petition No. 2569 of 2025 isn’t just about adopting discovered tariffs. It’s GUVNL’s strategic bet on a volatile winter and an attempt to stay ahead of the market curve.

The crowded bid field shows how valuable the December–March window has become. In Gujarat, winter isn’t just a season anymore it’s a procurement cycle. And GUVNL has chosen to enter early, lock in discipline, and let the reverse auction do the work.

Originally reported and analysed by EnergyLineIndia.com Written by a professional energy-sector journalist.

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India’s renewable energy developers are facing a new kind of compliance one that begins after the Power Purchase Agreement (PPA).

A Shift Beyond PPAs

Signing a PPA and securing a CTU node are no longer enough to bring a gigawatt-scale renewable project to life.

Developers will now have to formally participate in Regional Power Committees (RPCs) as recognised entities under the Central Electricity Regulatory framework.

This governance shift, initiated by the Ministry of Power and implemented by the Southern Regional Power Committee (SRPC) in September 2025, aims to bring renewable players into the same operational discipline that already binds conventional generators and state utilities.

The SRPC Chairperson has even written to the Central Electricity Authority (Member, GO&D) to facilitate structured membership for major renewable players in the Southern Region.

From “Counted” to “Represented”

Until now, renewables were merely counted for scheduling and dispatch — not represented in regional decision-making.

That changes with this reform. Developers will now need to attend RPC meetings, share operational data, report performance, and contribute to real-time grid management.

It’s a move that introduces institutional accountability into a space previously handled through commercial agreements and grid coordination alone.

What Developers Fear

Many renewable developers see this as a potential burden rather than empowerment.

Formal RPC participation could mean:

New procedural and membership fees

More compliance paperwork

Periodic operational submissions

Possible exposure to grid performance penalties

Independent power producers without state backing are particularly concerned that this governance-level accountability could spill over into operational liability.

Questions are already being raised over voting rights, representation levels, and the scope of regulatory coverage.

Why Grid Operators Support It

From the grid operator’s perspective, the reasoning is simple: renewable energy has become too large a share of the system to remain outside its formal governance framework.

As renewables approach 40% of total generation in the Southern Region, maintaining grid stability now depends on close coordination with developers themselves.

Outage planning, curtailment decisions, and reactive power management are inseparable from renewable operations. Without direct representation, developers remain outside the decision-making loop a gap that has led to scheduling mismatches and operational inefficiencies on high-solar and high-wind days.

Governance Is the Next Frontier

The next phase of India’s energy transition is about governance as much as technology.

By bringing renewables to the RPC table, policymakers acknowledge that the grid is no longer a one-sided system run by state utilities. It’s a multi-actor ecosystem that requires shared accountability.

But whether this reform will empower participation or merely add another layer of compliance remains to be seen.

For India’s renewable developers, the road from PPA to RPC might define how effectively the sector integrates into the nation’s evolving power governance model.

Originally published by EnergyLineIndia.com Written by a professional energy-sector journalist

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The core issue: Who pays for stranded capacity when big users move to Open Access?

The Karnataka Electricity Regulatory Commission (KERC) has rescheduled the hearing on Additional Surcharge for Open Access consumers to 2:00 pm, December 2, 2025, and extended the deadline for objections to 5:00 pm, December 1, 2025.

This update is procedural, not substantive the commission hasn’t disclosed BESCOM’s cost model, rate computation, or legal backing. But the underlying question remains unchanged: who bears the cost of stranded capacity when large industrial users shift to third-party power supply?

Inside BESCOM’s Argument

When industries switch to Open Access, BESCOM’s power sales drop, but its long-term power purchase agreements (PPAs) and the fixed capacity charges that come with them stay put.

BESCOM’s case is that these under-utilised PPAs create stranded fixed costs, which must be recovered from the consumers who caused them i.e., Open Access users.

Originally, BESCOM proposed an Additional Surcharge of ₹1.65 per kWh. After recalculations and updated energy/sales projections, the figure fell to ₹0.58 per kWh.

This reduction reflects a narrower attribution of stranded costs to Open Access migration rather than an overall policy retreat. The principle of recovery stays intact.

Why ₹0.58/kWh Still Matters

Even a smaller surcharge can hit hard in an industrial ecosystem like Karnataka’s.

The state’s cross-subsidy structure and recent tariff adjustments make every additional rupee count for industries running on tight margins.

For tech parks, process industries, and captive users, the landed cost of power determines competitiveness. Even ₹0.58 per unit can reshape Open Access viability, banking strategies, and power scheduling.

No surprise industry bodies are gearing up to formally object.

What to Watch in the December 2 Hearing

Causality & Measurability Does BESCOM’s model directly link stranded capacity to Open Access withdrawals, or does it mask broader revenue gaps?

Double-Recovery Risks Are these fixed costs already recovered in ARR/tariffs? How will KERC ensure Open Access users aren’t charged twice?

Revised Arithmetic The drop from ₹1.65 to ₹0.58 raises questions. Stakeholders will seek detailed workings, assumptions, and PPA-wise backing-down data.

Temporal Ring-Fencing For what period is the surcharge applicable, and how often will it be trued-up as Open Access volumes fluctuate?

Interaction with Other Adders How does this surcharge sit alongside other levies like the Pension & Gratuity Add-on? Clarity here matters for transparency and billing accuracy.

Timeline & Participation

Objections/comments: Up to 5:00 pm, December 1, 2025

Public hearing: 2:00 pm, December 2, 2025 (Virtual Mode)

Impact on Large Consumers

Even at ₹0.58/kWh, the surcharge can narrow Open Access arbitrage margins and shift industry behavior:

More on-site or captive generation

Shorter OA contracts to hedge risk

Optimised load management during peak blocks

If upheld, this rate could alter Open Access economics across Karnataka’s industrial clusters.

Bottom Line

The procedural change might look minor, but the principle at stake is major — how should the grid recover fixed costs when consumers increasingly go self-supply or third-party route?

As KERC reconvenes on December 2, expect this hearing to become a reference point for how India’s regulators interpret Section 42(4) and balance utility recovery vs consumer choice.

Originally reported for EnergyLineIndia.com Written by: [Jaya]

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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.

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CERC’s April 2025 Change-in-Law ruling continues to change how India shares sudden regulatory cost shocks inside the transmission system.

This is not a one-time impact. It is now structural.

A procedural looking instruction that quietly rewired the pool

When CERC passed Order 131/MP/2024, it looked like just another directive.

But it changed the recovery protocol: every approved Change-in-Law claim now gets built directly into monthly ISTS computation by NLDC — instead of being handled as separate delayed settlements.

Monthly billing rounds now reveal it

From the October + November 2025 rounds, NLDC notifications show this is now fully autopilot.

Each new tax/duty/compliance-driven cost escalation gets added to Yearly Transmission Charges (YTC) of the affected licensee — and then spreads across all DIC states through PoC.

Even though total national transmission charges dipped from Rs 3,985 cr in Oct to Rs 3,773 cr in Nov — state level share weights quietly shifted because mid-cycle Change-in-Law claims were embedded.

Invisible cost re-allocation

Nothing shows as a “surcharge”.

But the redistribution is real. And monthly.

Transmission developers gain revenue predictability. States lose opacity-free visibility.

Usage signal + regulatory compensation = same merged number now.

Structural impact

India’s national transmission pool has now become a continuous micro-shock absorber.

Not episodic. Not quarterly dispute based.

This one April 2025 order permanently turned Change-in-Law from an event… into an ongoing dynamic inside ISTS pricing.

silent monthly nationalised redistribution.

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