#ancillaryservices

The central government forces idle gas-based power plants into operation through emergency directives, locking them into rigid, backward-looking compensation frameworks. State distribution companies bear the consequence, absorbing the delayed settlement costs when dynamic fuel prices mathematically outpace the static regulatory reimbursement formulas.

The "Procedure for implementation of MoP scheme for operation of Gas Based Stations (GBS)" allows grid operators to mandate the dispatch of stranded gas assets to meet critical peak demand. Because domestic gas is fundamentally illiquid, these plants must rely on spot market liquefied natural gas, which fluctuates wildly in real-time.

The regulatory mechanism, however, reimburses these mandated operations using aggregated, backward-looking Standard Cubic Meter (SCM) cost averages. This creates an unavoidable working capital gap; the generator must purchase fuel at today's highly volatile spot price but is compensated based on yesterday's average, forcing the distribution utilities to eventually bridge the mathematical deficit through delayed true-up petitions.

The North Eastern Regional Power Committee document titled "Compensation Account", dated March 20, 2026, logs this exact fuel pricing volatility, recording the Assam Gas Based Power Plant (AGBPP) claiming dynamic gas costs ranging from 15.90 Rs/SCM to 16.70 Rs/SCM across successive billing cycles. Concurrently, the Northern Regional Power Committee document titled "Ancillary Services Account and Regional SCUC Account", dated 20th March, 2026, records the structural execution of this emergency gas scheme, logging a 1,039,285 Rs. settlement specifically for the AURAIYA GPP gas station.

A localized 10.39 Lakh Rs. dispatch settlement matched against a floating 16.70 Rs/SCM fuel cost physically proves the administrative disconnect between real-time fuel volatility and retrospective regulatory compensation. Fuel procurement managers argue that spot market gas prices change by the minute, making it computationally impossible for the regulatory grid accounts to settle emergency dispatch orders in real-time without introducing massive daily accounting errors.

While real-time settlement of volatile global commodities is administratively complex, utilizing a backward-looking cost-recovery mechanism for emergency interventions structurally forces the generation company to act as an uncompensated short-term lender to the grid. The Central Electricity Regulatory Commission is likely to face a cascade of working capital petitions from gas plant operators seeking carrying costs.

Until the compensation formula is pegged directly to a daily fuel index rather than a monthly average, mid-scale gas dispatch settlements will persistently distort state utility ledgers.

The regulatory framework governing Tertiary Reserve Ancillary Services (TRAS) requires thermal generators to perform rapid cycling operations while limiting compensation for the resulting efficiency degradation below its physical cost.

Generators providing these services are unable to exit participation because long-term Power Purchase Agreements (PPAs) and mandatory grid-support codes require compliance with automated dispatch instructions.

Revenue impact documented in WRPC records

The Western Regional Power Committee (WRPC) Supplementary Agenda Notes dated 06.03.2026 provide a detailed commercial example involving Ratnagiri Gas & Power Pvt. Ltd. (RGPPL).

The station recorded a Monthly Energy Billing of Rs 3,11,70,410 during the billing period.

However, efficiency penalties associated with thermal cycling produced a Total Impact clawback of Rs 2,39,84,468.

This adjustment effectively removed 76.9 percent of the station's monthly revenue in a single settlement cycle.

Market design justification

Market operators maintain that participation in ancillary services carries a separate market-clearing premium.

Under this framework, generators are expected to optimize their operational performance rather than transferring degradation costs to the system pool.

Compensation formula constraints

However, the Central Electricity Regulatory Commission (CERC) order dated 14.07.2025, which defines the compensation formula for Station Heat Rate degradation, limits the reimbursable wear associated with cycling.

The formula imposes a mathematical cap that does not account for the actual mechanical stress imposed on aging thermal equipment.

Because the compensation framework is a regulatory instrument rather than a negotiated commercial agreement, generators cannot renegotiate the formula.

Market outcome

The system operator and the distribution utilities that depend on grid balancing services capture the operational benefits of TRAS participation.

Meanwhile, the generators providing the balancing capacity absorb the uncompensated mechanical and efficiency costs.

Regulatory implication

Unless the Central Electricity Regulatory Commission revises the compensation framework established in the 14.07.2025 order to reflect documented mechanical tolerances, thermal generators participating in ancillary services will continue to carry significant revenue reductions.

Renewable power generators are utilizing inaccurate day-ahead weather forecasts to externalize their balancing costs, forcing national grid operators to routinely purchase expensive reserve power. This structural imprecision forces distribution companies and retail consumers to absorb the financial burden of stabilizing an increasingly intermittent grid.

Grid stability requirements under the IEGC

Under the Indian Electricity Grid Code (IEGC), the grid must maintain a strict frequency band to prevent system instability.

When solar and wind generation deviates significantly from their day-ahead schedules, grid operators are legally required to activate Security Constrained Unit Commitment (SCUC) and Tertiary Reserve Ancillary Services to stabilize the system.

Because renewable operators are not penalized aggressively enough for forecasting deviations, they lack strong financial incentives to invest in localized battery storage or other balancing solutions. This shifts the real-time balancing burden onto the broader electricity market.

Grid reports reveal the operational impact

Official grid data from March 2, 2026 illustrates the scale of this imbalance.

The Renewable Energy Management Centre (REMC) Operation Report recorded forecasting inaccuracies across the grid, reaching a Normalized Root Mean Square Error (NRMSE) of 4.61.

To compensate for this deviation, the Grid Controller of India’s Daily Report on Ancillary Services and SCUC shows dispatchers activating 10,697 MWh of reserve energy, requiring 2,036 MW of immediate up-regulation from more expensive generating units.

Forecast uncertainty versus regulatory asymmetry

Wind and solar generation are inherently variable, and perfect day-ahead forecasting is meteorologically impossible.

However, the regulatory framework governing deviations is asymmetric. While renewable forecasting errors can be substantial, the penalties applied to developers often do not match the actual cost incurred by the grid to procure reserve power.

This creates a structural imbalance where grid operators must absorb the operational and financial consequences of forecast inaccuracies.

Regulatory implication

The Central Electricity Regulatory Commission (CERC) may need to recalibrate deviation settlement mechanisms to better reflect the real-time costs of activating ancillary reserves.

Aligning forecasting penalties with actual balancing costs could incentivize improved forecasting accuracy and investment in storage or flexible generation resources.

The Power sector reforms narrative confronts a stark datapoint: 0.0000 MWh cleared in the TRAS market during early morning blocks on 26 February 2026. This occurred while DAM purchase bids exceeded sell bids by 24,138 MW in a single 15-minute block, forcing prices to the Rs 10,000/MWh ceiling.

Such dynamics challenge the assumptions behind Power sector reforms in ancillary market design. When DAM margins peak, generators prioritize energy arbitrage over reserve commitments. The grid’s emergency buffer effectively disappears during its most stressed periods.

Gas-based capacity — essential for ramping support in Renewable energy India — remained largely dark. Several combined cycle units reported zero output under reserve shutdown. With AGC up-reserve limited and negative SRAS+TRAS averages, frequency dipped to 49.745 Hz, registering 171 sub-49.97 Hz excursions.

From a News on power sector standpoint, this divergence between market signals and physical reliability raises structural questions. The Inter State Transmission System absorbed stress through manual intervention rather than automated reserve injection.EnergylineIndia.com highlights that Power sector reforms must realign incentives. Mandatory reserve obligations or differentiated ancillary pricing may be necessary to prevent future zero-bid episodes under peak deficit conditions, Power Sector Reforms, Ancillary Services, Indian Power, Grid Reliability.

The National Grid’s SRAS mechanism is designed to provide rapid ramping support during demand spikes.

But recent settlement audits show gas stations in the Northern Region recording 0.00% performance reliability for an entire week.

Market prices surged during this period—evidence of grid stress.

Payouts concentrated among a few entities, while others earned nothing.

Fuel constraint claims do not always align with declared stock levels.

This points to an accountability gap: consumers are paying for reserves that may not exist when needed.

The late-November balancing fortnight has quickly become one of the most dissected developments in Indian Power news, thanks to a rare alignment of DSM inflows, VARh penalties and rising ancillary dependence. What appears as routine grid accounting on the surface has reshaped cash positions across the North.

The headline in Indian Power news is the massive DSM gain from WR and ER, transforming a normal fortnight into a revenue-boosting outlier. This cross-regional volatility now matters as much as internal discipline, a point repeatedly emphasised in Indian Power news commentaries.

Delhi’s situation provides the contrasting arc. With persistent VARh non-compliance and an abrupt DSM surge, the capital becomes a case study in operational misalignment. For analysts tracking Indian Power news, the issue is not just the numbers but the systemic vulnerabilities they expose: forecasting gaps, reactive-power mismanagement and tariff-sensitive commercial pressures.

Jammu & Kashmir’s deterioration across both DSM and VARh deepens the narrative. It reflects structural fragility in a terrain where outages and local constraints escalate quickly. This dual-stress pattern has been flagged often in Indian Power news as a precursor to reliability trouble.Meanwhile, DADRI’s coal units emerge as the grid’s top ancillary responders, absorbing imbalance after imbalance. Large RE fleets, however, show rising DSM bleed under TRAS-Emergency — a tension highlighted widely in Indian Power news as thermal-flexibility economics collide with solar variability penalties, Indian Power News, DSM, Grid Operations, Ancillary Services, Reactive Power, Delhi Power.

Western Region’s newest settlement sheets land with a jolt: ancillary revenues have fallen by nearly half in just two weeks, and whatever money is still on the table is being captured by a very small club of stations — mainly NTPC’s flex-optimised coal units and a couple of fast-response gas plants.

Everyone else, especially the older coal fleet, has been pushed into a corner where inflexibility isn’t just a technical handicap — it’s becoming an economic one.

Flexibility Wins. Hesitation Bleeds.

Solapur, Gadarwara and Khargone continued to behave like precision-tuned flexibility engines. Even with shrinking TRAS/SRAS liquidity, these stations kept monetising commitment and reserve windows with almost surgical timing. Gandhar and Kawas turned every viable TRAS event into real money.

But the pattern flips completely at VSTPS, Mouda and NSPCL. Their data trail is full of over-commitment on day-ahead schedules, sharp corrective down-regulation, weak AGC discipline and penalties accumulating across SCUC, SRAS and even TRAS.

In a fortnight where discipline mattered more than brute capacity, the gap became impossible to ignore.

The Tariff Fiction Cracks

For years, tariff design has politely assumed that all coal megawatts behave the same. Fixed charges flatten out differences. PPAs hide fleet-level variability.

But WRPC’s data cuts through that fiction. Supercritical NTPC units and RLNG gas plants are operating like market-ready flexibility products, while older sub-critical units are paying heavily for their inability to follow signals — yet both still enjoy similar fixed-charge treatment.

This leaves regulators staring at a very real fork in the road:

• Treat ancillary performance as a pure reward-penalty overlay, or • Hard-wire flexibility into the tariff structure itself, through differentiated capacity charges or explicit flexibility adders.

Either way, the status quo is running out of room.

A Quiet but Strategic Reordering

Plants that haven’t upgraded AGC behaviour or scheduling discipline are, in effect, subsidising the transition to a volatile, RE-heavy grid. The handful that have invested in flexibility are quietly stacking recurring ancillary income — the kind that funds automation, digital controls and skilled operations teams.

If this continues for a few quarters, the Western Region’s coal fleet will split into two classes: those surviving on energy + fixed charges, and those treating ancillary revenue as a core business line, not a bonus.

The Bigger Question Hanging Over WRPC

This fortnight isn’t just another settlement update. It is the early script of WRPC’s next structural argument:

Who pays for inflexibility? Who gets rewarded for ramping on command? And how long can tariff design ignore what the ancillary numbers already make painfully clear?

The grid is changing — and this is what the change looks like when it hits the balance sheet.

India’s power system is in the middle of a subtle but important shift. New NLDC data for September 2025 and the extended October 2025 window shows that ancillary services—SRAS, SCUC, and TRAS—are taking on a much larger role in balancing operations, even as the combined DSM + ancillary deficit shrinks significantly.

What’s striking is the contrast: ancillary volumes and gross payouts keep rising, yet the overall pool deficit tightens from about ₹742 crore to ₹401 crore. This is happening in a system where daily energy met stays in the 3,800–5,100 MU range, but the share of ancillary dispatch (TRAS + SRAS) is quietly inching up to nearly 3% of all-India energy on the busiest days.

India’s balancing ecosystem is getting heavier, faster, and far more financially interlocked.

SRAS: More Volume, More Money, More Weight

SRAS no longer feels like a marginal add-on service—its footprint is now unmistakable.

SRAS Up energy rises 52%, from 224.42 MU → 340.03 MU

Net SRAS energy rises from 16.38 MU → 96.06 MU

SRAS charges more than double, from ₹35.26 crore → ₹74.37 crore

Generators offering quick, dependable ramping see more revenue. But for state utilities and regional accounts, SRAS is now a large recurring payout that directly shapes monthly settlement exposure.

SCUC: A Bigger Operational Role at a Lower Unit Cost

SCUC grows even faster in energy terms:

SCUC Up: 2332.50 MU → 3033.77 MU

SCUC Down: 1814.04 MU → 2194.00 MU

And yet, net SCUC charges fall sharply, from ₹967.01 crore → ₹607.25 crore (down 37%).

Why? Two shifts:

SCUC Up payouts soften

SCUC Down receipts strengthen

The system is committing more SCUC energy, but at lower incremental cost, helping offset the steep SRAS bill.

TRAS Shortfall/Emergency: A Deeper Inflow Layer for the Pool

TRAS also swings toward higher utilisation:

TRAS Up grows from 294.62 MU → 381.72 MU

TRAS Down nearly doubles from 1099.18 MU → 1988.34 MU

While TRAS-Up charges remain stable, TRAS-Down receipts climb from ₹172.20 crore → ₹231.33 crore, pushing the net TRAS inflow deeper (from –₹18.33 crore → –₹82.93 crore).

A structural rule magnifies this: renewable plants dispatched under TRAS Emergency receive zero compensation, meaning their activation automatically boosts TRAS-Down inflows.

A Thicker Balancing Stack, A Smaller Deficit

When DSM and ancillary accounts are consolidated, the system deficit tightens by about ₹341 crore across the two months. The heavier SRAS burden is outweighed by:

Higher SCUC Down receipts

Stronger TRAS-Down inflows

DSM itself stays largely neutral.

The bigger picture is clear: India’s balancing architecture is growing more layered, more active, and more financially consequential. SRAS is now a major monthly cost, SCUC is performing more of the operational heavy lifting at lower marginal cost, and TRAS especially under zero-compensation RE rules is emerging as a decisive factor in whether the deviation pool bleeds or recovers money.