#powerfinance

State distribution companies are delaying payments to wholesale generators until regulatory sanction thresholds approach, effectively converting long-term power purchase agreements into zero-interest credit facilities.

Generators operating under regulated PPAs cannot terminate contracts solely due to payment delays, preventing them from redirecting power to alternative buyers.

Recorded payment delay

The WRPC Supplementary Agenda Notes dated 06.03.2026 document a case involving Ratnagiri Gas & Power Pvt. Ltd. (RGPPL).

The generator currently carries Rs 81 crore in unpaid dues from a single distribution utility.

The delay period recorded in the document is 502 days, exceeding sixteen months.

Cash flow justification

Distribution utilities attribute payment delays to retail tariff deficits and delayed subsidy disbursements.

They also cite the Late Payment Surcharge (LPS) framework, which is intended to compensate generators for payment delays.

Financing gap

However, the regulated surcharge rarely covers the actual borrowing costs generators incur when raising emergency short-term debt to maintain fuel procurement.

Market effect

This dynamic allows distribution utilities to operate using the liquidity of wholesale generators.

Policy question

Unless the Ministry of Power modifies the Late Payment Surcharge Rules to enforce automatic escrow deductions from tariff collections before dues age beyond 90 days, distribution companies will continue to rely on generators as a working capital source.

Transmission deviation charges India during early 2026 expose a critical flaw in deviation accounting under the GNA regime. March RTDA data and WRPC settlement records show that approved access revisions were not reflected in billing systems for months, despite being operationally effective.

Generators received revised GNA instructions from NLDC in October 2025. Dispatch followed those directions to maintain regional frequency. Yet settlement software continued to calculate limits on legacy access values. As a result, scheduled injections were misclassified, and Transmission deviation charges India accumulated continuously across December, January, and February.

This created a closed negative loop. Each settlement period reinforced the previous deviation position, regardless of physical compliance. For merchant industrial plants, the mismatch had immediate cash-flow consequences. Power was supplied, penalties were levied, and revenues were eroded before any corrective revision could be processed.

The magnitude is visible in RTDA annexures, where deviation volumes were priced at Rs 408 per MWh under temporary access logic. Such rates are punitive when applied to tens of thousands of units. Once settled, the charges could not be commercially recovered.EnergylineIndia.com documents how Transmission deviation charges India are shaped by administrative timing, not just grid behaviour. The case highlights weaknesses in power deviation settlement design and flags the need for real-time integration within General Network Access India to prevent systemic financial leakage, Transmission Charges, GNA Framework, Deviation Settlement, Power Finance.

Financial engineering systematically pushes massive grid infrastructure liabilities into upcoming regulatory tariff cycles.

A temporal distortion in capital planning

A review of the “Additional Capitalization” annexures within the March 2026 tariff filings reveals a pronounced shift in funding allocations across financial years.

Project disclosures show comparatively limited capitalization under FY 2025-26, while significantly larger allocations are concentrated under FY 2026-27.

Because Annual Revenue Requirement (ARR) calculations are linked to approved capitalization, postponing asset recognition reduces near-term tariff impact while expanding the future recoverable base.

Debt-backed continuity

Parallel financial disclosures indicate expanded short-term borrowing.

In certain cases, cash-credit limits increased from ₹825 crore to ₹1,825 crore within a quarter, secured against unrecovered regulatory assets.

This implies operational liquidity—coal procurement, maintenance, infrastructure works—is increasingly supported by commercial borrowing.

Compounding effect

Interest expenses have risen sharply year-on-year in thermal-heavy jurisdictions.

When FY 2026-27 capitalization is integrated into the rate base, regulators will incorporate:

Deferred capital expenditure

Return and depreciation components

Accumulated financing costs

The financial structure suggests cost timing has shifted across cycles rather than disappeared.