Pakistan Electricity Tariff Structure: An Overview

The tariff structures and formulae set out below explain the principal economic architecture of electricity tariffs in Pakistan. They must not be treated as immutable statutory formulae. The applicable methodology, allocation basis, reference values, indexation, loss targets, capital structure and adjustment frequency must always be verified from:

1. the NEPRA Act;

2. the applicable Tariff Rules and regulations;

3. the relevant licence;

4. the governing tariff determination;

5. any approved power-purchase or use-of-system arrangement;

6. the applicable Market Commercial Code;

7. subsequent adjustment decisions; and

8. the relevant Gazette notification.

NEPRA’S INSTITUTIONAL MANDATE

1. Statutory and regulatory role

National Electric Power Regulatory Authority ("NEPRA") was established under the Regulation of Generation, Transmission and Distribution of Electric Power Act, 1997 as the national statutory regulator of electric-power services.

Its tariff function forms part of a wider mandate comprising:

• licensing and registration;

• tariff determination and approval;

• performance standards;

• consumer protection;

• market regulation;

• monitoring and enforcement;

• approval or oversight of investment and procurement arrangements; and

• promotion of competition and market development.

NEPRA remains the statutory regulator, but it is not the only institution performing functions within the electricity market. The contemporary market structure also recognises, among others:

• the Market Operator;

• the System Operator;

• transmission and provincial grid companies;

• distribution licensees;

• electric-power suppliers;

• traders;

• generators;

• special-purpose agents; and

• other registered market participants.

The legal role of each entity must be distinguished from NEPRA’s regulatory jurisdiction.

2. Regulatory mission

The regulatory mission may be expressed as securing:

• safe and reliable electric-power services;

• efficiency;

• affordability;

• consumer protection;

• reasonable financial viability for service providers;

• investment;

• competition;

• transparent market development; and

• consistency with the economic and social policy objectives lawfully established by the Federal Government.

This mission assists in understanding the statutory purpose, but it does not replace the operative provisions of the NEPRA Act. Where a general policy aspiration conflicts with an express statutory requirement, the statute prevails.

3. Balance between consumers and service providers

The Act does not direct NEPRA to prefer consumers in every case or to guarantee the recovery of every cost claimed by a licensee. It requires a legally structured balance between:

• protection against monopolistic or inefficient prices;

• recovery of prudent costs;

• reasonable investment returns;

• efficiency;

• quality and reliability;

• sectoral financial stability;

• competition;

• social protection; and

• long-term consumer welfare.

A tariff that is artificially low but financially unsustainable may be inconsistent with the Act. Equally, a tariff that passes inefficient or imprudent expenditure to consumers merely because it was actually incurred may also be unlawful.

REGULATORY INSTRUMENTS RELEVANT TO TARIFFS

1. Primary tariff instruments

The principal legal instruments are:

• the NEPRA Act;

• the NEPRA (Tariff Standards and Procedure) Rules, 1998;

• the applicable tariff-fee regulations;

• the relevant licence and licence conditions;

• tariff determinations and modifications;

• Gazette notifications; and

• valid Federal Government policy guidelines issued within the statutory framework.

2. Related regulatory instruments

Depending on the particular tariff, the following may also be material:

• licensing rules and regulations;

• Uniform System of Accounts Rules or Regulations;

• Performance Standards Rules and Regulations;

• Electric Power Procurement Regulations;

• Market Operator and System Operator licensing instruments;

• Open Access, Interconnection and Wheeling Regulations;

• Competitive Bidding Tariff Regulations;

• Interim Power Procurement Regulations;

• Market Commercial Code;

• Grid Code;

• Distribution Code;

• Consumer Service Manual;

• benchmarks for tariff determination;

• O&M contractor-selection guidelines;

• coal procurement guidelines; and

• applicable Government electricity policies and plans.

3. Rules and regulations

The distinction is legally important:

• Rules are made by the Federal Government under the rule-making power in the Act, following the consultation required by the statute.

• Regulations are made by NEPRA under its regulation-making power for carrying out the purposes of the Act.

Neither rules nor regulations may:

• exceed the parent statute;

• confer a power withheld by Parliament;

• contradict an express statutory requirement;

• remove a right conferred by the Act; or

• frustrate the statutory purpose.

PRINCIPAL TARIFF REGIMES

1. General classification

Tariffs may broadly be determined through:

1. cost-plus or revenue-requirement regulation;

2. multi-year tariff regulation;

3. revenue-cap regulation;

4. price-cap or performance-based regulation;

5. upfront or benchmark tariffs;

6. competitively bid tariffs;

7. interim power-procurement mechanisms; or

8. a hybrid methodology.

The choice of methodology is itself an exercise of statutory discretion. NEPRA must be able to explain:

• why the selected model is legally available;

• why it is appropriate for the relevant activity and risk allocation;

• what costs and risks remain with the licensee;

• what costs are passed through to consumers;

• how efficiency is incentivised;

• how extraordinary events will be treated; and

• how the methodology advances the purposes of section 31.

2. Cost-plus regulation

Under a cost-plus methodology, NEPRA determines an allowed revenue requirement by reference to:

• prudently incurred operating costs;

• depreciation;

• financing costs;

• an approved return on the regulatory asset base;

• taxes and insurance where allowable;

• approved losses;

• efficiency assumptions; and

• prior-period adjustments.

Cost-plus regulation does not mean automatic reimbursement of actual expenditure. Each claimed cost remains subject to:

• prudence;

• necessity;

• efficiency;

• reasonableness;

• allocation;

• verification;

• benchmarking; and

• the prohibition against double recovery.

3. Multi-year tariff regulation

A multi-year tariff ordinarily fixes the regulatory framework for a defined control period and may specify:

• an opening revenue requirement;

• efficiency factors;

• performance benchmarks;

• investment allowances;

• loss targets;

• indexation;

• pass-through items;

• adjustment mechanisms;

• service-quality obligations;

• sharing of efficiency gains;

• reopening events; and

• end-of-period true-up or rebasing.

The central public-law value of a multi-year tariff is predictability. Any reopening clause must therefore identify with sufficient clarity:

• the event triggering reopening;

• the component capable of adjustment;

• the applicable methodology;

• the effective date;

• the evidence required;

• whether the adjustment operates upward and downward; and

• the procedure, including notice and hearing.

4. Revenue-cap regulation

A revenue cap permits the regulated entity to recover an approved level of revenue, subject to adjustments for matters such as:

• demand variation;

• efficiency;

• inflation;

• service quality;

• approved investment;

• losses; and

• pass-through costs.

It regulates total recoverable revenue rather than merely prescribing a unit price.

5. Price-cap and performance-based regulation

A price-cap or performance-based regime limits the price or tariff path while allowing the operator to retain some benefits of outperformance.

The model seeks to:

• incentivise cost reduction;

• transfer controllable risk to the operator;

• reduce detailed cost-by-cost regulation; and

• reward efficiency.

A performance-based regime requires clear baselines. An apparent efficiency gain produced by deferred maintenance, deterioration in service quality, under-investment or inaccurate demand assumptions is not a legitimate efficiency.

Descriptions of the XWDISCOs as universally subject to cost-plus revenue caps and K-Electric as subject to a price cap should be treated as historical or determination-specific. The current methodology must be identified from the applicable multi-year tariff.

6. Upfront or benchmark tariff

An upfront tariff is generally based on standardised assumptions for a class of projects or technologies.

Its advantages may include:

• reduced transaction costs;

• speed;

• comparability;

• predictability; and

• support for market entry.

Its risks include:

• overcompensation where benchmark costs exceed efficient actual costs;

• under-compensation where assumptions become obsolete;

• reduced project-specific prudence scrutiny; and

• inflexibility where technology or financing conditions change.

Acceptance of an upfront tariff may limit the applicant’s ability subsequently to seek project-specific treatment, subject to the express terms of the tariff and governing law.

7. Competitive bidding

A competitively bid tariff is derived from a bidding process conducted under an approved procurement and tariff framework.

Competition may provide evidence of market price, but the existence of a bid does not remove NEPRA’s duties to examine:

• legality of the procurement;

• transparency;

• bidder qualification;

• conflicts of interest;

• bid responsiveness;

• evaluation methodology;

• risk allocation;

• affordability;

• grid and system requirements; and

• conformity with the approved request-for-proposals documents.

A bid price obtained through an unlawful, collusive or materially defective process does not become reasonable merely because it was the lowest submitted price.

ECONOMIC ANATOMY OF THE ELECTRICITY TARIFF

1. Vertical cost-flow chain

The principal cost chain may be expressed as follows:

1. fuel and primary-energy suppliers;

2. public and private generators;

3. the Central Power Purchasing Agency or relevant procurer;

4. transmission and system-operation functions;

5. distribution and supply licensees;

6. consumer categories; and

7. subsidies, surcharges and taxes where lawfully applicable.

In simplified form:

**Generation cost

• transmission cost and allowed transmission losses

• market and system-operation charges

• distribution and supply cost

• allowed distribution losses

• approved adjustments
  = cost-reflective consumer tariff**

The cost-reflective tariff must then be distinguished from:

• the uniform tariff;

• the notified consumer-end tariff;

• inter-category cross-subsidy;

• Government subsidy;

• taxes; and

• statutory surcharges.

2. Legal principle of cost traceability

Each material amount recovered from consumers should be traceable to:

• an identifiable statutory or regulatory source;

• an approved tariff component;

• a verified cost or formula;

• a defined allocation method;

• a relevant billing determinant; and

• a reasoned determination.

Cost aggregation must not obscure:

• inefficiency;

• excessive losses;

• unapproved costs;

• related-party margins;

• duplication;

• prior recovery; or

• expenditure properly attributable to another regulated or unregulated activity.

3. Prohibition against double recovery

The same economic cost must not be recovered:

• through both the base tariff and an adjustment;

• through both depreciation and immediate expensing;

• from more than one consumer category without appropriate allocation;

• through both a capacity charge and another fixed-cost component;

• through both a prior-year adjustment and a current-period allowance; or

• through both a Government subsidy and consumer tariff.

NEPRA’s reasons should disclose how double counting was excluded.

GENERATION TARIFFS

1. Two-part tariff structure

A conventional generation tariff may consist of an energy charge and a capacity charge.

A. Energy charge

The energy charge may include:

• fuel cost;

• variable O&M;

• start-up cost;

• part-load adjustment;

• fuel handling;

• limestone or reagent cost;

• water or consumables;

• variable taxes; and

• other approved costs varying with generation.

B. Capacity charge

The capacity charge may include:

• fixed local O&M;

• fixed foreign O&M;

• debt principal;

• interest and financing costs;

• return on equity;

• return on equity during construction;

• insurance;

• withholding tax where contractually and legally allowable;

• working capital;

• fixed taxes; and

• other approved fixed costs.

2. Legal character of capacity charges

Capacity charges compensate for making contracted capacity available rather than solely for electricity actually dispatched.

They may promote:

• bankability;

• investment;

• system adequacy;

• reserve capacity; and

• reliable availability.

They also transfer demand and dispatch risk to the purchaser and, ultimately, consumers. NEPRA must therefore consider:

• whether the capacity was prudently procured;

• actual and forecast system demand;

• plant availability;

• dispatch constraints;

• take-or-pay or take-and-pay allocation;

• minimum-load requirements;

• liquidated damages;

• outages;

• efficiency;

• contractual termination rights; and

• whether any cost could reasonably have been avoided.

A contractual obligation is relevant but not invariably conclusive. NEPRA must distinguish between:

• costs contractually payable by the purchaser;

• costs lawfully recoverable through tariff;

• costs caused by governmental or purchaser default; and

• costs that should remain with the project company.

3. Fuel-cost prudence

Fuel costs should be examined by reference to:

• approved fuel;

• quantity;

• quality and calorific value;

• heat rate;

• procurement method;

• transportation;

• storage losses;

• exchange rate;

• taxes and duties;

• alternative suppliers;

• contractual pricing formula; and

• compliance with procurement guidelines.

The pass-through character of fuel cost does not remove the requirement of prudence. A licensee cannot transfer an inefficient heat rate, avoidable procurement premium or unapproved fuel loss merely by proving that it paid the amount.

4. O&M costs

O&M costs should be assessed by reference to:

• the plant’s technology and age;

• manufacturer recommendations;

• expected operating hours;

• comparable projects;

• local and foreign cost composition;

• indexation;

• long-term service agreements;

• competitive procurement;

• related-party arrangements;

• warranties;

• financing requirements; and

• service and availability obligations.

Where NEPRA has previously approved an O&M structure and the project has relied upon it to achieve financial close, reopening requires particular care. NEPRA may still act where authorised by law, but should identify:

1. the statutory source of the reopening power;

2. the changed circumstance;

3. the evidence demonstrating that the approved allowance is no longer reasonable;

4. the effect on contractual and financing commitments;

5. the opportunity given to the licensee to respond; and

6. any transitional protection.

The principles in High Flying Solar Development Pakistan Ltd v NEPRA, 2016 CLC 1805, and Fatima Energy Ltd v NEPRA, 2018 CLC 13, are particularly relevant.

TRANSMISSION TARIFFS

1. Revenue-requirement model

A transmission tariff may be determined by calculating the approved transmission revenue requirement and allocating that amount through an appropriate billing determinant.

A simplified expression is:

Transmission charge
= Approved transmission revenue requirement
÷ Approved billing determinant

The billing determinant may include:

• maximum demand;

• coincident peak demand;

• contracted capacity;

• energy;

• a combination of demand and energy; or

• another approved measure of system use.

2. Principal cost components

The revenue requirement may include:

• general establishment costs;

• administrative expenditure;

• repair and maintenance;

• insurance;

• depreciation;

• finance costs;

• return on regulatory asset base;

• system-operation costs where applicable;

• approved network expansion;

• prior-year adjustments; and

• other income as a deduction.

3. Maximum demand and allocation

Where costs are allocated through maximum demand indicator or a similar demand measure, NEPRA should examine:

• the reliability of metering;

• coincident versus non-coincident peak;

• diversity;

• seasonal variation;

• demand forecast;

• embedded generation;

• network usage;

• treatment of new entrants;

• stranded capacity; and

• whether the allocation reflects cost causation.

The use of demand as the billing determinant is not merely a mathematical choice. It determines which consumers or distribution companies bear fixed transmission costs and must therefore be rational and transparent.

4. Transmission losses

An allowed transmission-loss target should:

• be based on reliable system studies;

• distinguish technical from non-technical losses;

• reflect voltage and network configuration;

• account for investment and operational constraints;

• remain challenging but reasonably achievable; and

• identify the treatment of performance above or below the target.

A historical allowance such as 2.80% is an example from a particular determination, not a universal legal standard.

Consumers should not ordinarily bear losses exceeding the approved benchmark unless the Act, applicable determination or a properly conducted adjustment proceeding justifies such recovery.

DISTRIBUTION AND SUPPLY TARIFFS

1. Composite revenue requirement

A simplified distribution and supply revenue requirement may be stated as:

**Total Revenue Requirement
= Power Purchase Price

• Net Distribution or Supply Margin

• Prior-Year Adjustment**

2. Power Purchase Price

The power-purchase component may include:

• fuel or energy purchase cost;

• variable O&M;

• capacity charges;

• transmission or use-of-system charges;

• Market Operator Fee;

• system-operation charges;

• procurement charges; and

• approved adjustments.

3. Distribution margin

The distribution margin may include:

• salaries and establishment costs;

• repair and maintenance;

• administrative expenditure;

• depreciation;

• return on regulatory asset base;

• insurance;

• financing costs;

• information technology;

• metering and billing;

• consumer service;

• approved investment;

• bad-debt or write-off allowances where legally justified; and

• other income as a deduction.

4. Prior-year adjustment

A prior-year adjustment may reconcile:

• allowed and actual power-purchase cost;

• under- or over-recovery;

• variation in demand;

• approved investment;

• depreciation;

• other income;

• losses;

• financing cost;

• indexation; and

• earlier provisional amounts.

A prior-year adjustment must not become an unexplained balancing figure. The determination should identify:

1. the year to which the adjustment relates;

2. the original allowance;

3. the actual verified amount;

4. the reason for variation;

5. previous recoveries or refunds;

6. the remaining balance;

7. the allocation among consumer categories; and

8. the recovery or refund period.

5. Distribution losses

The loss target is a major determinant of the consumer tariff.

A lower allowed-loss target places greater operational risk on the distribution company. A higher target passes more losses to consumers.

NEPRA should consider:

• technical network characteristics;

• feeder and transformer loading;

• metering;

• theft;

• recovery performance;

• investment;

• geographic and security conditions;

• historical efficiency;

• comparable licensees;

• controllability; and

• the approved loss-reduction plan.

The target must not reward inefficiency. Conversely, it should not be fixed at an unattainable level merely to suppress the apparent tariff.

6. Revenue recovery and collection

Allowed revenue and cash collection are distinct. A licensee’s inability to collect billed revenue does not automatically establish a right to recover the shortfall from compliant consumers.

The Authority should determine whether the shortfall arose from:

• Government non-payment;

• subsidy delay;

• theft;

• defective billing;

• poor collection;

• judicial restraint;

• force majeure;

• inefficient management; or

• another cause.

The cost should be allocated to the party or category legally responsible for the risk.

REGULATORY ASSET BASE AND RATE OF RETURN

1. Regulatory asset base

A regulatory asset base may broadly comprise:

• prudently incurred fixed assets in operation;

• qualifying capital work in progress, where permitted;

• approved working capital;

• stores and spares;

• other assets used and useful in providing the regulated service;

less:

• accumulated depreciation;

• consumer contributions;

• grants;

• deferred credits;

• unregulated assets;

• disallowed expenditure;

• relevant liabilities; and

• amounts already recovered.

2. Used-and-useful principle

An asset should ordinarily earn a regulated return where it is:

• prudently acquired;

• reasonably necessary;

• devoted to the regulated service;

• operational or treated as qualifying construction work under the approved methodology; and

• not already funded by consumers or Government grants.

The principle does not necessarily prohibit all return on construction work in progress. It requires NEPRA to explain when and why pre-operation investment is included.

3. Weighted average cost of capital

A simplified WACC formula is:

WACC = Ke(E/V) + Kd(D/V)

where:

• Ke is the approved cost of equity;

• Kd is the approved cost of debt;

• E/V is the equity proportion; and

• D/V is the debt proportion.

Depending on the tariff methodology, the debt component may require adjustment for tax.

A historical 30:70 equity-debt structure or a WACC of 11.83% is not a continuing legal benchmark.

4. Legal requirements for return

NEPRA should determine return by considering:

• comparable risk;

• efficient capital structure;

• actual and benchmark financing;

• country risk;

• technology;

• demand and dispatch risk;

• foreign-exchange exposure;

• construction risk;

• inflation;

• tenor;

• refinancing;

• tax;

• guarantees; and

• the need to promote continued reasonable investment.

The rate should be sufficient to attract prudent investment but should not protect investors from every commercial risk or provide a windfall.

5. Consumer-funded assets

Assets financed through:

• consumer contributions;

• connection charges;

• grants;

• subsidies; or

• another non-licensee source

should not ordinarily earn a full licensee-funded return unless the applicable law or determination provides a reasoned basis.

TRANSFER PRICE MECHANISM

1. Function

The Transfer Price Mechanism allocates the centrally procured generation and related system costs among distribution and supply entities.

In simplified form:

XTC = XCTC + XETC

where:

• XTC is the total transfer charge;

• XCTC is the capacity-related transfer charge; and

• XETC is the energy-related transfer charge.

A simplified energy-transfer rate may be expressed as:

XETC = CPGenE ÷ XWUs

where:

• CPGenE is the approved variable generation cost attributable to the billing period; and

• XWUs is the relevant energy delivered to the distribution and supply entities.

A simplified capacity-transfer rate may be expressed as:

XCTC = (CPGenCap + UoSC + MOF) ÷ XWD

where:

• CPGenCap represents approved capacity costs, adjusted where applicable for liquidated damages and other credits;

• UoSC represents use-of-system charges;

• MOF represents the Market Operator Fee; and

• XWD represents the approved demand or other capacity-allocation determinant.

The precise current formula must be taken from the applicable tariff determination and Market Commercial Code.

2. Legal implications

The allocation mechanism must be:

• mathematically reproducible;

• based on verified metering;

• consistent across comparable entities;

• adjusted for credits and liquidated damages;

• free from double counting;

• based on an authorised billing determinant; and

• supported by reasons.

NEPRA must also determine whether an allocation based on demand, energy or another measure fairly reflects cost causation.

3. Liquidated damages and credits

Any liquidated damages, rebates, insurance proceeds, contractual credits or other recoveries attributable to costs previously borne by consumers should ordinarily be credited in the tariff mechanism.

Retention of both:

• the original tariff recovery; and

• the related damages or compensatory receipt

may produce an impermissible double recovery unless expressly and rationally justified.

ADJUSTMENT MECHANISMS

1. Purpose

Adjustment mechanisms reconcile the base or reference tariff with defined variations occurring during the tariff period.

They may address:

• fuel prices;

• generation mix;

• exchange rate;

• inflation;

• interest rate;

• capacity payments;

• O&M indexation;

• transmission charges;

• Market Operator Fee;

• losses;

• insurance;

• taxes;

• approved investment;

• demand;

• prior-period amounts; and

• other expressly defined variables.

2. Current periodic structure

The older training material referred to fortnightly or monthly generation adjustments, bi-annual power-purchase adjustments and annual distribution adjustments.

The contemporary structure is more commonly described as:

• monthly Fuel Charges Adjustments;

• quarterly tariff or power-purchase adjustments;

• annual indexation, adjustment or rebasing; and

• determination-specific generation and transmission adjustments.

The exact frequency remains governed by the applicable tariff and current regulatory instruments. NEPRA’s 2026 notices continue to distinguish monthly FCA proceedings from quarterly adjustments involving capacity charges, transmission charges, Market Operator Fee, variable O&M and the impact of losses.

3. Fuel Charges Adjustment

A simplified FCA formula is:

Fuel Price Variation
= Actual Fuel Cost Component
− Reference Fuel Cost Component

The actual fuel-cost component represents the approved actual cost for the relevant month. The reference component is the amount already embedded in the base tariff.

The FCA should ordinarily:

• relate to a defined consumption month;

• use verified actual cost;

• apply the approved formula;

• account for generation mix;

• incorporate allowed losses;

• exclude disallowed or imprudent expenditure;

• recognise over-recovery as well as under-recovery;

• be shown separately on the consumer bill; and

• be supported by a published determination.

4. FCA is formula-bound but not legally immune

An FCA is not ordinarily a complete reopening of the base tariff. It is an application of an approved adjustment mechanism.

Nevertheless, NEPRA must still determine:

• whether the claimed costs fall within the formula;

• whether the underlying data are accurate;

• whether the cost was prudently incurred;

• whether any credit, saving or refund must be recognised;

• whether the loss adjustment is correct;

• whether the billing period is lawful; and

• whether the resulting charge is transparent.

5. Quarterly adjustments

Quarterly adjustments may include:

• capacity charges;

• transmission charges;

• Market Operator Fee;

• variable O&M;

• exchange-rate or interest-rate variation;

• impact of T&D losses on FCA;

• demand variation;

• incremental-consumption mechanisms; and

• other matters expressly allowed by the base tariff.

The determination should separately identify each component. Aggregating unrelated variations into a single net figure may impair transparency and appellate review.

6. Annual adjustment and rebasing

Annual adjustment may address:

• return on regulatory asset base;

• depreciation;

• financing cost;

• approved investment;

• insurance;

• withholding tax;

• other income;

• efficiency;

• loss performance;

• indexation;

• demand; and

• prior-year adjustments.

Annual adjustment must be distinguished from full tariff rebasing. Rebasing generally revisits the broader revenue requirement and reference assumptions, whereas indexation or adjustment applies previously approved formulae.

7. Symmetry

An adjustment mechanism must operate symmetrically unless the statute or determination clearly provides otherwise.

Accordingly:

• increases in fuel cost may be recovered;

• decreases must be passed through;

• under-recovery may be corrected;

• over-recovery must be refunded or credited;

• adverse exchange-rate movement may be recognised;

• favourable movement must also be recognised.

A mechanism that passes all adverse variation to consumers but allows the licensee to retain favourable variation requires particular statutory justification.

8. Temporal limits

NEPRA should identify:

• the cost-incurrence period;

• the consumption period;

• the application date;

• the recovery or refund period;

• whether the adjustment is provisional or final; and

• the authority for any retrospective billing.

Delay does not automatically extinguish a valid adjustment, but prolonged delay may affect:

• fairness;

• consumer reliance;

• ability to verify data;

• affordability;

• regulatory predictability; and

• the appropriate recovery period.

LEGAL PRINCIPLES GOVERNING TARIFF CALCULATIONS

1. Burden of substantiating costs

The applicant bears the initial burden of proving:

• the existence of the cost;

• its quantum;

• its relationship with the regulated activity;

• prudence;

• necessity;

• allocation; and

• compliance with the applicable tariff methodology.

Once the applicant provides credible evidence, NEPRA cannot disallow the cost through assertion alone. It should identify:

• the evidential deficiency;

• the applicable benchmark;

• the competing evidence;

• the inefficiency;

• the alternative cost; or

• the legal reason for disallowance.

2. Actual cost is not necessarily prudent cost

The fact that expenditure appears in audited accounts establishes that it was recorded or incurred. It does not conclusively establish that:

• it was necessary;

• its amount was reasonable;

• it was efficiently procured;

• it relates solely to the regulated service; or

• consumers should bear it.

Conversely, a cost is not imprudent merely because it later appears expensive. Prudence should ordinarily be assessed by reference to the information reasonably available when the decision was made.

3. Cost causation and attribution

A cost should be allocated to the activity or consumer group that causes or benefits from it.

NEPRA should avoid:

• allocation of generation cost to distribution margin;

• allocation of unregulated business costs to regulated consumers;

• recovery of theft from compliant consumers without statutory justification;

• charging one region for a cost unrelated to its service;

• allocation of capacity cost through an irrational demand measure; and

• shifting Government subsidy liabilities to licensees or consumers without lawful authority.

4. Matching principle

Costs and revenues should ordinarily be matched to the same regulatory period.

A prior-period cost should not be embedded indefinitely in the future base tariff without identifying:

• the original period;

• previous recovery;

• remaining balance;

• carrying cost;

• recovery period; and

• effect on consumers.

5. Controllable and uncontrollable costs

Tariff design should distinguish:

Controllable costs

• staffing;

• procurement;

• maintenance planning;

• administrative expenditure;

• commercial losses;

• billing and collection;

• operational efficiency.

Uncontrollable or pass-through costs

• certain fuel-price movements;

• specified taxes;

• specified exchange-rate variation;

• approved market charges;

• external policy changes;

• specified interest-rate movements.

Classification should depend on the actual tariff methodology. A cost should not be labelled “uncontrollable” merely because the licensee prefers to transfer it to consumers.

6. Benchmarking

Benchmarking may compare:

• similar technologies;

• comparable licensees;

• historic performance;

• international utilities;

• competitive bids;

• manufacturer data;

• regulatory guidelines; and

• efficient-operator costs.

A benchmark must be adjusted for material differences in:

• scale;

• age;

• technology;

• geography;

• security;

• fuel;

• service quality;

• labour conditions;

• financing;

• network density; and

• regulatory obligations.

Unadjusted comparison with a materially different utility may be irrational.

7. Demand forecasting

Demand assumptions affect:

• unit tariff;

• capacity-cost allocation;

• revenue recovery;

• investment;

• losses;

• stranded capacity; and

• affordability.

NEPRA should examine:

• historic demand;

• economic growth;

• price elasticity;

• distributed generation;

• captive generation;

• energy efficiency;

• industrial demand;

• weather;

• new connections;

• load migration; and

• market reform.

A tariff based on an unrealistic sales forecast may appear affordable initially but create substantial future adjustments.

8. Other income

Income earned through regulated assets or activities should ordinarily reduce the revenue requirement where consumers funded the relevant asset or bore the associated cost.

Relevant income may include:

• late-payment surcharge;

• rental income;

• sale of scrap;

• metering charges;

• connection income;

• interest;

• liquidated damages;

• insurance receipts; and

• ancillary services.

NEPRA should identify whether the income belongs:

• wholly to consumers;

• wholly to the licensee; or

• under an approved sharing mechanism.

9. Related-party transactions

Related-party costs require enhanced scrutiny concerning:

• arm’s-length pricing;

• procurement;

• transfer pricing;

• common management;

• duplication;

• affiliate margins;

• allocation of shared services; and

• conflicts of interest.

The existence of a binding affiliate contract does not itself establish prudence.

10. Investment and capital expenditure

An approved investment programme should be assessed by reference to:

• necessity;

• cost-benefit analysis;

• reliability;

• demand;

• loss reduction;

• service quality;

• procurement;

• project readiness;

• financing;

• implementation capacity; and

• historic capital-expenditure performance.

Where the tariff allows return or depreciation on projected investment that is not subsequently made, the unspent allowance should be adjusted or returned in accordance with the tariff mechanism.

11. Efficiency and service quality

Cost reduction should not be rewarded where achieved through:

• deterioration in reliability;

• unsafe operation;

• deferred maintenance;

• reduced consumer service;

• failure to connect consumers;

• inaccurate metering;

• environmental non-compliance; or

• non-performance of licence obligations.

Efficiency must be assessed together with quality.

12. Subsidy transparency

NEPRA should distinguish:

1. the cost-reflective tariff;

2. the uniform tariff;

3. the applicable consumer-end tariff;

4. inter-class or inter-region subsidy;

5. Federal Government subsidy;

6. surcharge; and

7. tax.

The amount and funding source of a subsidy should be transparent. A subsidy decision is principally governmental policy; tariff determination remains NEPRA’s statutory function.

PUBLIC-LAW REQUIREMENTS AT EACH COST LAYER

For each material tariff component, NEPRA should record:

1. Jurisdiction: What provision permits the component?

2. Purpose: What statutory tariff objective does it serve?

3. Evidence: What record supports the amount?

4. Prudence: Was the cost reasonably and efficiently incurred?

5. Allocation: Why is the cost assigned to this entity or consumer class?

6. Benchmark: What comparator or methodology was used?

7. Duplication: Has the cost already been recovered?

8. Adjustment: Is it fixed, indexed, passed through or subject to true-up?

9. Period: To what period does it relate?

10. Stakeholder response: What material objection was raised?

11. Finding: Why was the objection accepted or rejected?

12. Consequence: How does the component affect the tariff?

Failure to answer a material question may indicate:

• non-application of mind;

• failure to consider relevant material;

• reliance on an extraneous consideration;

• absence of reasons;

• irrationality; or

• procedural unfairness.

APPELLATE AND REVIEW STRUCTURE

1. Motion for leave for review

The Tariff Rules provide a limited review mechanism. It is not an unrestricted rehearing.

Review may ordinarily be sought on grounds such as:

• error apparent;

• material computational error;

• discovery of material evidence not reasonably available earlier;

• failure to address a decisive submission;

• contradiction between the reasons and operative order;

• legal error; or

• another sufficient ground within the applicable review jurisdiction.

2. Appellate Tribunal

The statutory Appellate Tribunal framework is contained in Chapter IIIA of the NEPRA Act. The Tribunal comprises legally, financially and technically qualified members in accordance with the Act.

An appeal against an appealable NEPRA decision is ordinarily filed within thirty days.

The Tribunal may:

• examine the record;

• make further inquiry;

• give the parties an opportunity of hearing;

• affirm, modify or set aside an appealable decision within its jurisdiction; and

• in tariff matters, remand the determination to NEPRA with relevant guidelines.

Where the Tribunal disagrees with a tariff determination, NEPRA is required to review its determination within one month of receiving the Tribunal’s guidelines.

3. Further appeal

The decision of the Appellate Tribunal is appealable to the High Court having territorial jurisdiction.

4. Institutional allocation

The statutory structure preserves specialist roles:

• NEPRA makes the primary technical and economic determination;

• the Appellate Tribunal reviews the determination through legal, financial and electrical expertise;

• where tariff methodology requires reconsideration, the matter is remitted to NEPRA;

• the High Court exercises appellate jurisdiction as provided by the Act; and

• constitutional review remains available within established public-law limits.