The Jharkhand State Electricity Regulatory Commission (JSERC) has issued the draft “Terms and Conditions for Determination of Distribution Tariff Regulations, 2025.” These regulations, with a control period from April 1, 2026, to March 31, 2031, establish the financial and operational framework for electricity distribution in the state.

The draft aims to promote competition among distribution licensees, improve operational efficiency, ensure prudent investment in infrastructure, and guarantee a reliable electricity supply to consumers.

Scope and Applicability

The regulations apply to all distribution licensees operating in Jharkhand and cover the determination of aggregate revenue requirement (ARR) and tariffs for electricity wheeling and retail supply.

To promote competition, the Commission may prescribe a maximum ceiling tariff for retail supply only, where multiple licensees supply electricity in the same area. For consumers with open access permissions, the Commission will determine wheeling tariffs, cross-subsidy surcharges, additional surcharges, and related charges in accordance with the JSERC Intra-State Open Access Regulations, 2016.

The tariffs determined under these regulations are considered ceiling tariffs. Distribution licensees are permitted to propose reduced tariffs for consumers. However, such reductions will not affect their revenue requirement as approved by the Commission.

Multi-Year Tariff Framework

The multi-year tariff (MYT) framework is a central component of the regulations. It requires distribution licensees to file MYT applications with supporting documents, including audited accounts for the fiscal years (FY) 2021 to 2025, revised estimates for the FY 2026, and projections for each year of the control period.

The guiding principles include filing a business plan for the entire control period, forecasting ARR and tariffs for each year, prescribing trajectories for performance parameters, and conducting annual performance reviews.

Variations in performance are categorized into controllable and uncontrollable factors. A mechanism has been established to distribute gains and losses from controllable factors between licensees and consumers, while fully accounting for uncontrollable variations.

Segregation of Accounts

Licensees must maintain separate accounts for wheeling and retail supply businesses. Where accounts are not fully segregated, allocation statements must apportion revenues, costs, and assets.

The allocations must be approved by the board of directors and accompanied by a clear methodology. If a methodology is not provided, the Commission can adopt previously approved allocation norms, such as allocating 40% of employee costs to supply and 60% to wheeling, or assigning 100% of power purchase costs to supply.

Business Plan Requirements

Every licensee must submit a business plan for the control period, separately for retail supply and wheeling businesses. The plan must include:

• Capital investment plan: A program-wise plan detailing purpose, approval, capital structure, detailed project reports, cost-benefit analysis, capitalization schedule, and implementation timelines. Projects must cover load growth, asset replacement, reduction of technical and commercial losses, quality improvements, and enhancements to customer service
• Sales and demand forecasts: Category-wise and voltage-wise projections for each year, based on historical growth, consumption patterns, and anticipated demand
• Power procurement plan: Covering demand forecasts, renewable purchase obligations, energy efficiency, and demand-side management
• Targets for controllable parameters: Including distribution loss reduction, billing efficiency, collection efficiency, working capital requirements, and quality of supply metrics such as system average interruption frequency index (average number of interruptions per customer per year), system average interruption duration index, and momentary average interruption frequency index (average number of momentary interruptions per customer per year)
• Human resource plan: Year-wise manpower additions and retirements to meet demand growth
• Non-tariff income and other business proposals: Itemized revenue streams and their projections

The business plan must also include audited data from the previous control period, covering capital investment, consumer base, power procurement, and expenses.

Power Procurement Framework

Licensees must prepare power procurement plans for the entire control period, based on sales forecasts and demand projections. These plans can include long-term (12 to 25 years), medium-term (three months to 3 years), and short-term (up to one month) contracts. Short-term procurement is discouraged except in cases of supply failure, emergencies, or cost reduction.

Each plan must include monthly demand and supply projections in MW and million units, base and peak load requirements, renewable energy procurement, and measures for energy conservation.

A mandatory, application-based, automated tool utilizing artificial intelligence and machine learning must be implemented to manage procurement portfolios. This tool must optimize procurement cost, minimize deviation settlement mechanism charges, and improve demand-supply forecasting.

All power purchase agreements require prior Commission approval. Cost overruns without approval may be disallowed. Short-term purchases must be reported to the Commission within 15 days.

Operation and Maintenance Expenses

Operation and maintenance (O&M) expenses consist of employee costs, administrative and general (A&G) expenses, and repairs and maintenance (R&M). For the base year, O&M expenses will be determined based on audited accounts for FY 2021 to FY 2025, estimates for FY 2026, and prudence checks.

Future O&M costs are indexed. R&M expenses are determined by linking to Gross Fixed Assets (GFA) using the formula R&M = K × GFA × (Indexn / Index0), where K is a constant and the index is based on the consumer price index and the wholesale price index.

Employee and A&G expenses are similarly indexed, with the Consumer Price Index carrying a 55% weight and the Wholesale Price Index a 45% weight. Terminal liabilities will be allowed at actuals. Pay commission revisions and wage agreements will be considered separately.

Legal expenses can be claimed, provided supporting documentation is submitted, such as invoices, fee receipts, and case references. However, costs related to cases filed against Commission orders are not recoverable.

Capitalization and Financing

Capital costs include expenditure on the original scope of work, financing charges, and interest during construction. Capitalized initial spares are allowed up to 1.5% of the project cost. Costs funded by consumer contributions, grants, or deposit works will be deducted from the capital base.

Additional capitalization is permitted for deferred liabilities, arbitration awards, statutory orders, changes in law, and force majeure events. De-capitalization requires statutory auditor certification and corresponding adjustments to loan and equity accounts. Asset monetization proposals may be considered, provided grid security is not compromised.

Financial Parameters

Debt-Equity Ratio

For programs capitalized after April 1, 2026, a normative debt-equity ratio of 70:30 is prescribed. If actual equity exceeds 30%, the excess will be treated as debt. If actual equity is less than 30%, the actual ratio will apply.

Return on Equity

The return on equity (RoE) is fixed at 14.5% (post-tax) for assets capitalized before the notification of these regulations and 14% thereafter. An additional 0.5% RoE may be granted if uninterrupted supply is provided to universal service obligated entities, such as hospitals, schools, public water supply systems, street lighting, and renewable energy projects. Non-compliance with renewable purchase obligations may reduce RoE by up to 1.5%.

Tariff Recovery and Fixed Charges

Tariffs determined under these regulations serve as ceilings. Licensees may propose reduced tariffs, but the revenue requirement will not be lowered. Recovery of fixed charges is linked to the minimum hours of supply.

Cross-Subsidy and Additional Surcharges

Cross-subsidy surcharge is calculated using the formula: S = T – \[C / (1 – (L / 100)) + D + R], where T is the tariff payable by the consumer category, C is the weighted average power purchase cost, D is transmission and wheeling charges, L is losses, and R is regulatory asset cost. The surcharge is capped at 20% of the average cost of supply. An additional surcharge will be levied only if stranded costs are demonstrated.

Fuel and Power Purchase Adjustment Surcharge

The fuel and power purchase adjustment surcharge (FPPAS) mechanism allows recovery of variations in power procurement costs. It will be billed in the second subsequent month.

If the variation is up to 5%, the full amount will automatically be recoverable. For variations above 5%, 90% of the balance is recoverable automatically, with the remaining portion subject to Commission approval.

The formula for FPPAS accounts for actual power purchase, bulk sales, incremental average power purchase cost, transmission charges, and approved losses. Carry-forward is permitted for up to two months, with carrying costs allowed at bank rate plus 150 basis points.

Excess recovery must be refunded, including carrying cost, at 1.2 times the approved rate. Licensees must update their billing systems to implement this mechanism and publish all calculations on their websites.

Late Payment Surcharge

Consumers must pay bills within 15 days (for high-tension/extra-high-tension) or 21 days (for low-tension). Delays incur a late payment surcharge at 12% per annum for up to 60 days and 14% per annum for delays between 60 and 90 days. These charges will apply on a simple interest basis to outstanding amounts, including taxes, duties, and levies.

In July this year, JSERC issued draft regulations to determine the tariff for procuring power from solar and solar-thermal power projects.

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