Background Paper

Regulator’s Perspective

of

Utillity Benchmarking and Performance Monitoring

By

G.P.Rao

former Chairman Andhra Pradesh Electricity Regulatory Commission

In India, the benchmarking is still at a nascent stage and the focus of the reforms till date has been more on the industry structure, efficiency improvement through loss reduction. The transmission and distribution losses are at very high levels and the focus has been to bring in efficiency gains and reduce commercial losses. Not much of efforts have been put on benchmarking exercises.

The Andra Pradesh Electricity Regulatory Commission (APERC) has however made a beginning, attempting to strengthen the regulatory framework to improve operational efficiency of the licensees, through a closely involved and coordinated working relationship with the licensees and the Government. This has helped maintain consistency of reform goals across all stakeholders, and thus ensure united action. The APERC has reviewed each component of the value chain to bring in financial and operational efficiency of the utilities. This was done more by fixing the norms for the operational and financial parameters, which are similar to benchmarking in a way.. This has helped the utilities to improve performance in a number of areas.

Development of benchmarks is not an easy task. Firstly, the exercise is highly data intensive. and in India the data issues are characterised by two features viz., non-availability of information and asymmetry of information (Though the information is available with the licensee, they are not inclined to share the information with the regulators ) .Data when available, is either not properly structured or the data is not of sufficient length of period on a consistent basis. Secondly, benchmarks to be universally applicable need to incorporate differences in technology, variations in capital vintages and when norms need to be applied, non-technical reasons such as work practices need to be taken into consideration.

Before I present the initiatives taken by the APERC on benchmarking exercises or fixing the normative values for the financial and operational parameters, I would like to highlight the issues that need to be addressed in any benchmarking exercise. In comparing financial and operational indicators of the region’s utilities, following issues must be addressed:

(a) Access and reliability: The analytical framework must initiate on parameters for which data is reliable and available. Hence the APERC has focussed on parameters like operational and maintenance cost, working capital cost, collection efficiency, Station Heat rate etc.

(b) Normalisation: To compare financial, operational, technical and supply quality data, a common basis i.e., normalisation is a must, as utilities collate and present data on different basis, relevant for their purposes.

(c) Process: The business practices in utilities may differ, such as in the terms of billing, adjustments, accounting (such as in capitalisation, stores, pension liability, deferred expenses, etc), and scope for standardisation in process, and data capture will need to be assessed.

As far as Andhra Pradesh electricity sector is concerned, a few basic facts will be helpful in understanding the process of fixing benchmarks by APERC. To start with, public utility ( State Electricity Board ) in Andhra Pradesh had a high level of technical competence, which meant that fixation of norms for technical parameters in generation was easy as the state-owned generating company, Andhra Pradesh Generation Corporation rated the best in the country, had already achieved some of the benchmarks prescribed. Furthermore, a large amount of data was available. The data mainly relating to operational parameters such as number of employees, wage structure, expenditure on repairs and maintenance, tariff rates, number of consumers, was available and was regularly published. However, the data required collecting, collating and tabulating on a systematic basis in order to develop benchmarks for operational usage. It maybe pointed out here that the accuracy of data especially with regard to commercial dimensions was definitively questionable. There were also major data gaps especially with regard to the assets on ground and on the financial side the matching loans requiring the creation of an asset register. The Commission while developing benchmarks had to take into account these shortcomings and accordingly proceed in the matter

As designed the development of the required benchmarks is categorized into three aspects:

  1. Operational and Commercial efficiency
  2. Cost and Financial Issues
  3. Customer Standards and Interface

Analysis is made separately for generation and network business.

Generation

The generation segment was the first to be unbundled and in Andhra Pradesh the generators spanned the entire spectrum of public sector, private sector and joint ownership with large variations in size of plants, fuel (thermal, hydel, renewable), age of plants, and technology. The introduction of private power generators as early as 1995 saw the emergence of two-part tariffs in long-term Power Purchase Agreements (PPAs). All power was sold to a single buyer, initially the integrated public utility , the State Electricity Board and later to the Transmission Corporation, which was also the single bulk supplier of power. . At present the bulk supply business of APTRANSCO is transferred to the distribution companies – a move from single buyer model to multi-buyer model.

The two major areas of action for the Commission at the time of its creation were:

1.  To balance the risks inherent in long-term PPAs of the private power producers

2.  To introduce the two-part tariff(and also base the tariffs on accrual basis instead of cash outgo basis) in the state generating sector and to enable them to enter into a PPA with the Licensee viz. the Transmission Corporation of Andhra Pradesh (APTransco);

Both sets of action required developing benchmarks. The long term prevailing PPAs (25 years) were on a ‘take or pay’ basis . The technical norms were fixed by the Central Electricity Authority, a body set up to evaluate the technological feasibility of power plants. The financial norms however evolved from the lending practices of financial institutions. The Commission, in the PPAs that came before it for approval, both private power generators and the State owned Andhra Pradesh Generation Corporation (APGENCO) aimed at rebalancing the risks by applying technical and financial norms.

i) Technical Norms- Operational and Commercial Efficiency

Technical norms as stated earlier were evolved on the basis of experience in Andhra Pradesh and they are:

Ø  Auxiliary Power Consumption

– Coal Plants – 7.0% to 9.0%

- Gas Plants – Open Cycle: Stabilization Period 1.5%

Subsequent Period 1.0%

- Combined Cycle – Open Cycle – Stabilization period 3.5%

Subsequent period 3.0%

)

Ø  Station Heat Rate

-Coal Based plants – 2050 to 2350 kcal/kWh

-Gas plants – 1850 kcal/kWh

Ø  Specific Oil Consumption – 2.0 ml/kWh

Ø  Plant Load Factor PLF – increased from 68.4% to 85%

ii) Financial Norms and Costs

Financial costs are defined by the initial capital costs and the required operating costs. Capital costs in a PPA framework under single buyer model inevitably tended to be overstated. The Central Electricity Authority which was a Statutory body, which undertook technical appraisal of generation projects tended to have wide margins as regards capital costs. As determination of capital cost was out of the purview of the Regulatory Commission, it preferred to concentrate on the operational norms relating to the financial flows incorporated into the projects. These related to i) financing charges, ii) escalation factors, iii) return on equity and incentives, and iv) O&M charges.

The Commission observed that the main areas where rebalancing of the risk was required were: a) inflation factor; and b) foreign exchange risk . The Commission attempted to handle inflation risk and foreign exchange risk by fixing a margin on the permissible amount of loading on the generation tariffs by negotiation. But what was possible was in the area of financing charges where the Commission was able to insist on lower interest rates in line with the market trend of falling interest rates both in the domestic money market and in the international money market. Loans that had been negotiated for a higher interest rate were renegotiated on prevailing lower rates. Further, wherever it was economical ,swapping of loans was encouraged

Escalation of costs was permitted on the basis of a combined index of 60% Wholesale Price Index and 40% of Consumer Price Index.

The Government of India fixed return on equity in 1995 at 16% in line with the then prevailing interest rates. To this an incentive structure was included that allowed investors a 1.0% increase in incentive, permitted for every increase in the Plant Load Factor ( PLF ). PLF was fixed at 68.4% and for every 1% increase in the PLF, an incentive was provided. The initial incentive structure was loaded heavily in favour of investors. In the new PPAs the PLF was raised to 85% with a cap on incentives of 0.5% by the Commission.Incentives on deemed generation were removed.

In the case of O&M costs, a cap of 2.5% was fixed to the total capital costs as a norm by CEA and later endorsed by the Central Electricity Regulatory Commission .

On the basis of the above norms, the Commission reviewed Power Purchase Agreements totaling over 2400 MW,,signed by generators and the Andhra Pradesh Transmission Corporation and this review resulted in a saving of Rs. 1000 million per annum.

PPA of APGENCO : Earlier PPA of APEGNCO, the state-owned generator operating 51% of the capacity contracted in the state, was based on reimbursement of all costs viz. fuel, operating & maintenance costs and interest & debt repayment. This offered no incentive for efficiency, and was in fact impairing the capacity-planning decisions. In this case the PPA was originally fixed on the basis of single part tariff and this was shifted to a two-part tariff using the norms developed above. The change to norm-based PPA, along with some financial restructuring, helped reduce the fixed costs. The unit cost savings envisaged in the FY04 Tariff Order was about 17%. The new PPA resulted in a total savings of Rs.4000 million per annum.

Network Business

The Network business of the lines above and including 132 KV was part of Andhra Pradesh Transmission Corporation ( APTransco ) and the rest was part of the Distribution Companies, which were four in number. APTransco was handling both transmission business and supply of bulk power. The four distribution companies were delegated the retail supply business with the distribution wires business.

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As regards the network business, like many other developing countries’ pre-reform days, the emphasis was more on generation than on transmission and distribution networks. Efficiency in the network business therefore depended entirely on the maintenance of existing networks and on new investments to meet load growth. At the operational level this required developing benchmarks on O&M expenses, while at the same time ensuring that all investments for which costs were loaded on to the tariffs, fulfilled the criteria of being ‘used and useful’.

The Commission preferred to concentrate on ensuring that investments cleared by it underwent a detailed scrutiny based on Guidelines developed before inclusion in the tariffs. If in the year of operation the investments were not made as per the approved capitalization schedule, a claw back of investment expenditure and related expenses on interest, depreciation, employees, repairs and maintenance was done in the next year’s revenue requirement of the Licensee. A required adjustment on the rate of return provided on the capital base was also carried out. Following these guidelines, the Licensee improved its performance in investments as may be seen from tne Table given below:

TABLE-1

2000-01 / 2001-02 / 2002-03 / 2003-04 / 2004-05 / 2005-06
Total Investments proposed for the year / 2078.72 / 2233.00 / 1891.59 / 1984.99 / 1613.72 / 2129.25
Total Investments made during the year / 937.91 / 382.46 / 1317.11 / 1495.62 / 1321.96

The Commission directed the APTRANSCO to undertake a study through CPRI to estimate the normative losses at the transmission level. Based on the study, the Commission approved the transmission losses of 6.5%. This directive of the Commission helped the licensees to identify and address the commercial losses existing in the transmission system.

Financial Norms and Costs:

1.  Depreciation Norms –. Different depreciation norms were fixed for different items by the Ministry of Power, but the average depreciation rate came to about 6% . Accordingly the Commission allowed 6% as the depreciation norm.

2.  Working Capital Norms- Licensees have always requested for more working capital limits or at least to include the interest on working capital as part of expenditure. As per the provisions of the Sixth Schedule of the Electricity Supply Act ,1948 which laid down the financial principles for power utilities in India, two months stock and one months cash balance was permitted. Licensee however disputed this margin on grounds of lags in receivables. The Commission made clear in its Tariff Order FY2002-03 that a proper lead-lag study of receivables and payables needed to be done and a picture of the requirement of cash flows should be taken into account. Accordingly ,on the basis of the lead-lag study the Commission found that any lag in collection of receivables was a purely transitory phenomenon and directed that the provisions of the Sixth Schedule would be fully implemented by FY2006-07. The decision permitted 2months equivalent of cash and bank balance for the next two years, and then one-half for the third year, coming down to the permissible 1month.

A landmark achievement on the lines of performance benchmarking for distribution companies was formulation of the Long Term Tariff Principles (LTTP), on which a consultative paper was issued and deliberated in state-level and national forum before it was issued as a Commission Order in March 2003. The LTTP Order combines all key tariff and cost principles to improve licensees’ financial and operational efficiency.

As a sequel to the introduction of multi year tariff principles, rules for claw back were drawn up which are given in the table below. Simultaneously the Commission decided to exclude Capital Works in Progress from the rate (capital) base for purpose of fixing the allowable rate of return on the rate base. Directions were issued to lay down the procedures that required to be followed before an investment is taken to the rate base.