Download Development of Benchmarks and Regulatory Commissions

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., nonavailability 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 multibuyer 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:
 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%
)
 Station Heat Rate
-Coal Based plants – 2050 to 2350 kcal/kWh
-Gas plants – 1850 kcal/kWh
 Specific Oil Consumption – 2.0 ml/kWh
 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.
.
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
Total Investments proposed for the year
Total Investments made during the year
2000-01 2001-02 2002-03 2003-04 2004-05 2005-06
2078.72 2233.00 1891.59 1984.99 1613.72 2129.25
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.
Table-2
Item
Controllable
Need for true up
Power purchase
cost
Non-controllable
in case of fuel
increase
FSA
Wages
Controllable
No true-up
Administrative
expenses
Controllable
No true-up
Repairs
Controllable
No true-up
Interest
Controllable
Linked to capitalization
of capital works
Depreciation
Controllable
The Commission through its tariff orders was benchmarking the performance of the
utilities against the best performers or the normative values. The Commission carried out
quarterly review meetings in which the performance was assessed against the targets and
a comparative analysis was being carried out between Distribution Companies. One of
the key steps towards monitoring the performance of the licensees as against the
benchmarks or standards was the independent quality survey initiated by the
Commission. This survey was conducted to assess the performance of the licensee with
respect to quality of supply and customer service. Few of the standards of performance
laid down by the Commission are discussed below:
Standards of Performance
Quality of electricity supplied and customer service are important elements in power
sector reforms. The Commission after detailed discussions with the Licensees and stake
holders laid down Regulations for Licensees’ Standards of Performance. These include
guaranteed and overall standards of performance and related to
1. Restoration of power supply following fuse-off calls, breakdown of lines, failure
of distribution transformers , replacement of fused street light units, street line
faults,
2. Quality of power supply in terms of Voltage fluctuation and improving power
supply without up- gradation of the distribution system and with up- gradation of
the distribution system, and Harmonics
3. Complaints about meters such as checking up correctness of meter, and
replacement of faulty and burnt meters,
4. Connection of LT service and release of supply ,
5. New connection/ additional load for HT and EHT service,
6. Transfer and conversion of services, and
7. Complaints on consumer bills,
8. Reconnection of supply following disconnection due to non-payment of bills.
Specific time limits were prescribed for compliance by the Licensees in respect of these
services and the Licensees were directed to submit monthly reports in the formats
prescribed to the Commission. Licensees were also made liable to pay affected
consumers, compensation as specified by the Commission for Licensee’s failure to meet
the Guaranteed Standards of Performance.
The licensees established Electricity Control and Complaint Centers to register the
complaints of the consumer. As soon as the information on power breakdowns fuse-off
calls was received, they were attended by Electricity Mobile Vans which functioned
round the clock. The Licensees had also established Customer Service centers in each
sub-division to provide one-stop solution for all services like new connection, counseling
on commercial matters, etc. These centres were meant to isolate the O & M
staff/operation engineers from consumer contact at field level and thus avoid corruption
at that level. Customer Service Centre staff with their specialized skills of communication
are better placed to create confidence among consumers. As a result, the consumer
awareness led to new connections being given within two days of application in towns
and cities as against two to three months earlier. The Licensees had also established Data
Billing and Management Centres to review the exceptions and prevent slippages in
billing. These steps have considerably improved customer service in Andhra Pradesh.
Conclusion
As a result of benchmarking and fixation of norms for compliance by the Licensees as
described above, the Licensees’s performance in terms of revenue and quality of supply
have improved significantly as may be seen from the Tables given below:
TABLE-3
2000-01
Percentage
26.03%
of
cross
subsidy
Percentage
74.59%
of Revenue
Percentage
19.44
of subsidy
Transformer 29.07%
failures
Percentage
42.85
time
frequency
(Hz)>48.5
T&D Loss 35.93
reduction
2001-02
23.40%
2002-03
23.90%
2003-04
21.57%
2004-05
18.17%
2005-06
20.88%
75.11%
78.05%
81.51%
83.39%
83.74%
18.85
18.31
15.47
13.50
15.08
19.46%
12.73%
12.53%
--
39.49
60.70
99.11
99.43
--
30.23
29.83
26.57
26.65