Summer Internship Project Report. Analysis of Energy Charges of NTPC Stations and Optimization of Power Purchase Cost for DISCOM

Transcription

1 Summer Internship Project Report On Analysis of Energy Charges of NTPC Stations and Optimization of Power Purchase Cost for DISCOM Under the guidance of Dr. Manisha Rani, Sr. Fellow, NPTI & Mr. RAJEEV CHOWDHURY, Head (Regulatory Affairs) BSES Rajdhani power Limited Submitted By JYOTIRANJAN PRADHAN Roll No- 104 MBA (POWER MANAGEMENT) Affiliated to August 2013

2 DECLARATION I, JYOTIRANJAN PRADHAN, Roll No. 104, student of MBA (POWER MANAGEMENT) at National Power Training Institute, Faridabad hereby declare that the Summer Training Report entitled Analysis of Energy Charges of NTPC Power Stations for Procurement of Fuel Efficient Power & Optimization of Power Purchase Cost for DISCOM" is an original work and the same has not been submitted to any other Institute for the award of any other degree. A Seminar presentation of the Training Report was made on the 3rd September, 2013 on the same and the suggestions as approved by the faculty were duly incorporated. Presentation in charge Signature of the Candidate (Faculty) Countersigned Director/Principal of the Institute ii

3 ACKNOWLEDGEMENT It gives me immense pleasure and satisfaction having completed the project successfully. I take this opportunity to express my sincere gratitude to the people who have been instrumental behind this success. I express my sincere thanks to Mr. Rajeev Chowdhury, Head (Regulatory Affairs) BRPL and Mr. Aditya Pyasi, D.G.M (Regulatory Affairs) for giving me a great opportunity to work in such a dynamic organization and for guiding me in all stages of the project. I am thankful to Mr. Kanishk Khettarpal, Asst. Manager for his guidance and support. I have a deep sense of gratitude and respect for the entire staff of BRPL for sharing their knowledge and for assisting me. Their help has sparked my interest even more. I am indebted to Mr. S.K Choudhary, Principal Director, Mrs. Manju Mam, Director and Mr. Amit Mishra, Asst. Director for providing me an opportunity to do my summer internship at BRPL which was a great learning for me. I would also like to thank my Project In-charge Dr. Manisha Rani, Sr. Fellow, National Power Training Institute for her valuable inputs, assistance and support whenever required. I would like to express my special thanks to my family and friends for their continuous motivation, encouragement and support. Jyotiranjan Pradhan iii

4 EXECUTIVE SUMMARY The DISCOMS of Delhi draw power mostly from various Central Generating stations and State Generating Stations based on long term Power Purchase Agreements. The cost of long term power is being fixed by the Central Electricity Regulatory Commission (CERC) for plants supplying power to more than one State and by the Delhi Electricity Regulatory Commission (DERC) for plants located within the NCT of Delhi and supplying only to distribution utilities in Delhi. A small quantum of power is purchased in the short term during summer months to meet the demand. The purchase/ sale of intra state power and intra state transmission charges are fixed by the DERC. The short term purchases/ sale are through traders, bilateral contracts, banking, and power exchanges at market determined prices. The tariffs of distribution companies are determined by DERC. In the ARR approved by the commission Power Purchase Cost constitutes more than 80% of expenditure. The Commission approves the cost of power procurement after prudence check. Power Purchase cost consists of fixed cost, Variable cost, Fuel Price Adjustment and Transmission charges. In recent times power tariff in Delhi has gone up to 65% tariff mostly due to increase in power purchase cost of DISCOM. Since the power purchase costs vary based upon price(variable charges) and calorific value of fuel (coal /gas) which is reflected in the bills submitted by the generators every month, the entire power purchase cost process becomes unpredictable for the distribution utilities, and hence, uncontrollable in nature. Also, the level of generation from these stations each month determines the per unit impact of fixed charges. In the present scenario when adequate availability of fuel continue to pose a serious challenge for smooth running of thermal power plants, the use of imported coal or blended coal is the only option available for attaining high plant availability, but has led to increase in the energy charges of various central generating stations. However an in depth analysis of energy charges billed various CGS and their Energy Charge Rate dependent on landed price of coal w.r.t. quality of coal shows anomalous increase in the energy charges possibly due to inconsistency in both price & quality of coal used. Hence there is a need for prudence check of energy charges billed by GENCOS which is a direct pass through to DISCOMS and finally the Consumer tariff. iv

5 LIST OF FIGURES FIGURE 1.1 Annual Power Purchase Cost Component in ARR of BRPL..04 FIGURE 1.2 Total Energy charges in Power Purchase Cost of BRPL.05 FIGURE 1.3 Delhi Distribution area of BRPL..09 FIGURE 2.1 Research Methodology followed for data collection...15 FIGURE 3.2 Average Revenue Requirement & Revenue Actually realized for BRPL...29 FIGURE 4.3 Monthly Trend of LPPF & CVPF for BTPS for FY 12 & FY FIGURE 4.7 Monthly Trend of LPPF & CVPF for Unchahar-I for FY 12 & FY FIGURE 4.9 Monthly Trend of LPPF & CVPF for Unchahar-II for FY 12 & FY FIGURE 4.12 Monthly Trend of LPPF & CVPF for Unchahar-III for FY 12 & FY FIGURE 4.15 Monthly Trend of LPPF & CVPF for Farraka TPS for FY 12 & FY FIGURE 4.18 Monthly Trend of LPPF & CVPF for Kahelgaon-I TPS for FY 12 & FY FIGURE 4.21 Monthly Trend of LPPF & CVPF for Kahelgaon-II TPS for FY 12 & FY FIGURE 4.24 Monthly Trend of LPPF & CVPF for NCPP-I for FY 12 & FY FIGURE 4.27 Monthly Trend of LPPF & CVPF for NCPP-II for FY 12 & FY FIGURE 4.30 Monthly Trend of LPPF & CVPF for Rihand-I for FY 12 & FY FIGURE 4.33 Monthly Trend of LPPF & CVPF for Rihand-II for FY 12 & FY FIGURE 4.36 Monthly Trend of LPPF & CVPF for Singrauli TPS for FY 12 & FY FIGURE 4.39 Monthly Trend of LPPF & CVPF for Aravali for FY 12 & FY FIGURE 5.1 Correlation between month wise CVPF & LPPF of stations for FY v

6 FIGURE 5.2 Correlation factor derived between CVPF & ECR of stations for FY FIGURE 5.3 Correlation between month wise CVPF & LPPF of stations for FY FIGURE 5.4 Correlation factor derived between CVPF & ECR of stations for FY FIGURE 5.7 Short Term Power Purchase/Sales Rate for FY to FY LIST OF TABLES TABLE 1.1 Consumer Profile of BRPL & BSES (DELHI Division) TABLE 3.1 Build UP Revenue gap since FY to FY TABLE 3.3 ARR approved & Revenue surplus/deficit for FY TABLE 4.1 Plant wise calculation of ECR & its components for FY TABLE 4.2 Plant wise calculation of ECR & its components for FY TABLE 4.42 Sale/Purchase Quantum & Rate of Short term power from FY 11 to FY TABLE 4.43 Category wise break up of Short Term Power purchase/sale for FY TABLE 5.5 Comparison of Average Rate for FY with Average ECR for FY 12 & TABLE 5.6 Availability of power from New GENCOS for FY vi

7 LIST OF ABBREVIATIONS Act / EA Electricity Act, 2003 ABR Average Billing Rate AT&C Aggregate Technical & Commercial CEA Central Electricity Authority CERC Central Electricity Regulatory Commission DERC Delhi Electricity Regulatory Commission DISCOM Distribution Company GENCOS Generation Companies SGS State generating Stations CGS Central generating Stations DTL Delhi Transco Limited SLDC State Load Dispatch Centre STU State Transmission Utility T&D Transmission & Distribution UI Unscheduled Interchange PPC Power Purchase Cost ARR Average Revenue Requirement ECR Energy Charge Rate CVPF Calorific Value of Primary Fuel LPPF Landed Price of Primary Fuel CVSF Calorific Value of Secondary Fuel LPSF Landed Price of Secondary Fuel GHR Gross Station Heat rate AUX Auxiliary Consumption PPAC Power Purchase Adjustment Cost FPA Fuel Price Adjustment vii

8 TABLE OF CONTENTS ACKNOWLEDGEMENT...iii EXECUTIVE SUMMARY...iv LIST OF FIGURES...v LIST OF TABLES...vi ABBREVIATIONS...vii CONTENTS...viii CHAPTER-1 INTRODUCTION 1.1. HISTORY OF ELECTRICITY IN DELHI CHRONOLOGY OF DELHI PRIVATIZATION CONSUMER PROFILE OF BRPL PROBLEM STATEMENT OBJECTIVES OF THE PROJECT BACKGROUND OF THE PROJECT ORGANIZATION PROFILE About BSES Group BSES Delhi BSES Rajdhani Power Limited (BRPL) Business of the Organization Classification of Supply...10 viii

9 CHAPTER-2 LITERATURE SURVEY, POLICY & RESEARCH METHODOLOGY 2.1. LITERATURE REVIEW Policies & Regulations Determination of Tariff Multi Year Tariff Mechanism Determination of Wheeling Tariff & Retail Supply of Tariff RESEARCH METHODOLOGY Correlation Analysis...16 CHAPTER-3 ENERGY CHARGES DETERMINATION & MYT MODEL 3.1. COMPUTATION OF ENERGY CHARGES BY GENCOS Definitions Components of Tariff Computation and Payment of Capacity Charge and Energy Charge MYT MODEL FOR DISTRIBUTION LICENSEE ATE s directive to SERCs for timely tariff determination Revenue Gap Treatment of Revenue Gap Fuel Price Adjustment Charges...30 CHAPTER-4 RESULTS & DISCUSSION 4.1 RESULTS FROM STUDY OF ECR NTPC STATIONS...33 ix

10 Variation of ECR with LPPF & CVPF FOR FY Variation of ECR with LPPF & CVPF FOR FY Plant wise analysis of LPPF & CVPF for NTPC stations STUDY OF SHORT TERM POWER PURCHASE/SALES...48 CHAPTER-5 CONCLUSION & WAY FORWARD 5.1. CONCLUSION Need for prudence check of Energy Charges billed Surrender of Power from Costly Power Plants Better Scope of Management for Short term Power Purchase & Sales WAY FORWARD LIMITATIONS OF THE PROJECT...55 REFERENCES ANNEXURE x

11 CHAPTER -1 INTRODUCTION 1.1 History of Electricity in Delhi The history of electricity in Delhi dates back to 1905 when M/s John Fleming Company was awarded the license as per Indian Electricity Act, 1903, for generation and Distribution of power in Delhi. Electricity those days was a luxury and the privilege of the high ranking British officials and a few rich people. It was a rare and costly commodity with a perception of being dangerous. In fact, even rich Indian accepted this at a much later stage. M/s John Fleming Company was replaced by the Delhi Tramway and Lighting Company, which was subsequently renamed as Delhi Electricity Supply & Traction Company. In 1939, The Delhi Central Electric Power Authority (DCEPA) was formed to run the services. In 1951, the DCEPA was taken over by the Delhi State Electricity Board, constituted under Indian Electricity (Supply) Act In 1958, Delhi Electricity Supply Undertaking came into existence and was once again converted to Delhi Vidyut Board in In July 2002, Delhi Vidyut Board unbundled into five Successor entities the three distribution companies, a transmission and a holding Company. Two of the three distribution companies have been handed over to BSES, and third to TATA POWER. 1.2 Chronology of the Delhi Privatization February 1999 Delhi Government issues strategy paper outlining its intention to unbundled DVB, creates an independent regulatory entity, and privatizes distribution while protecting employee interests. May 1999 DERC established, it was initially created under an act of the Central Government and then later notified under the state reform act. October 2000 Delhi Electricity Reform Act formalized. In March 2001, the ordinance was given a stronger legal foundation through conversion into an act. Tri-partite agreement between DVB, its employees and the Delhi government, that protects the employment and pension rights of the employees. 1

12 February 2001 Privatization process began with the Request for Qualification. November 2001 Delhi Government issues Request for Proposals, issues a Policy Directive and announces the transfer scheme. February 2002 DERC issues an order that specifies opening loss levels and the initial Bulk Supply Tariff for purchases made by the Discom from the Transco. April 2002 Bids were received. The Cabinet of the Delhi government considers the bids to be unacceptable in present form and creates a Core Committee to explore alternatives including negotiation. June 2002 Privatizations documents were signed with BSES and Tata. July 2002 Date of privatization. June 2003 DERC issues first post-privatization tariff order. 1.3 BRPL CONSUMER PROFILE S.N Particular Unit BRPL(South & West) BSES DELHI 1 Area sq. km Customer Density (As of Mar 13) Cons/sq km Total Registered Customers (As of Mar 13) Million Peak Demand (YTM FY 13)* Delhi peak demand 5642 MW MW Table 1.1: Shows Consumer Profile of BRPL & BSES (DELHI Division) 2

13 1.4 Problem Statement 1. The average power purchase cost of Delhi discoms has been increasing each year due to escalation in fuel prices resulting in increase in the Average Revenue Requirement of the discoms. 2. Increase in ARR has a direct impact on Consumer Tariff. 3. Increase in Regulatory Assets due to difference in Actual Cost of Supply & ARR realized from tariff allowed pose a challenge to financial health of Discoms 1.5 Objectives of Project 1. To understand the day to day business & operations of regulatory department with respect to ARR filings, True up filing and other related aspects of the commission. 2. To optimize the power purchase cost component in the ARR of discoms. 3. To analyze the energy charges & its various components used in calculation of ECR of Central generating stations supplying power to Delhi discoms. 3

14 1.6 Background of Project National Capital Territory of Delhi receives power from central generating stations, state generating stations through the long-term power purchase agreements and short term purchases. The Distribution Licensees procure power from various available sources and supply power to consumers at retail tariffs determined by the Commission. The power purchase cost accounts for about 80% of Annual Revenue Requirement of the distribution licensees(figure 1.1) and includes the cost paid for procurement of power, transmission charges, UI charges, SLDC/ RLDC charges and is netted off with revenue earned from sale of surplus power. FIGURE 1.1: Annual Power Purchase Cost Component in ARR of BRPL ARR Power Purchase Cost Source: ARR Petitions filed by BRPL & True UP Order of DERC The cost of long term power being procured by the distribution licensees is being fixed by the Central Electricity Regulatory Commission (CERC) for plants supplying power to more than one state and by the Delhi Electricity Regulatory Commission (DERC) for plants located within the State of Delhi. The charges for unscheduled interchanges and Inter State transmission charges including RLDC charges are being fixed by the CERC. The charges for purchase / sale of intra state power and intra state transmission charges are fixed by the DERC. The short term purchase/ sale are through traders, bilateral contracts, banking, and power exchanges at market determined prices. Thus, it can be seen that power purchase cost are uncontrollable in nature and are volatile making it difficult to accurately estimate power purchase costs at the time of annual tariff 4

15 fixation. The power purchase cost is beyond the control of distribution licensees and dependent upon following factors: Price of Fuel (Coal /Gas) which are highly unpredictable as has been seen from past few years. Availability of Power from New Sources. Weather conditions such as extreme harsh summers/ cold which have direct impact on the demand. Demand Supply Gap of the power within the country. The divergence in fixing of cost reflective tariffs by Central and State regulators has been one of the main factors for the problems of the Distribution sector, which is now burdened with a cumulative aggregate loss of about Rs. 2 lakh crores due to financially unviable distribution sector. Apart from other things, the crippling financial situation of Discoms has led to inadequate capitalization, depletion of legacy assets and insufficient introduction of technology and IT. It is noteworthy that while the fuel charges are a complete pass through for Generation utilities, the variation is energy charges and resultant power purchase cost are yet to be implemented in line with the orders of Hon ble ATE. There is hardly any prudence check on the energy charges billed by GENCOS. FIGURE 1.2 Total Energy charges in Power Purchase Cost of BRPL FY FY FY FY Power Purchase Cost pf BRPL Energy Charges billes by Gencos Source: ARR Petitions filed by BRPL & True UP Order of DERC 5

16 From the above figure we can estimate that the energy charges for DISCOM is above 60 % of power purchase cost of discoms, thus reducing the energy charges by any means would cause a substantial relief to customers. Further, the distribution utilities are bound by the Hon ble Commission s Regulation of Power Supply to make timely payments while the Generation companies are allowed to delay payments for disputed coal quality and at the same time keep charging for the same delayed payments from the consumers ultimately to be reflected in tariff exercise of discoms. In this context I would like to draw attention towards some of the recent news articles from leading newspapers related to non settlement of dues by NTPC towards Coal India Limited for inferior quality of coal supply. From article published in the Business Line print edition dated June 30, 2013 titled CIL may stop supply to NTPC Plants, NTPC deducted over Rs 1,000 crore worth of payments, payable to the ailing CIL subsidiary, against supplies during the past six months, citing quality issues. Though the coal produced from the mine is graded between G-10 and G-13 in terms of heat value, NTPC claimed that the supplies were of much inferior quality and paid Eastern Coalfields at the rate of the lowest rank coal (G-17). According to The Economic Times article titled Stones in coal cost NTPC over Rs 11,000 crore per year, dated Apr 3, 2013; With such a huge amount of unusable coal, power generation cost goes as high as Rs 5.5 per unit in some cases," said a senior NTPC official. The power generation cost otherwise is around Rs 2-3 per unit when the quality of coal is better."ultimately, electricity consumers pay the price, as all our costs are pass through under the pact,". As per Govt. of India, notification CIL:S&M:GF:Pricing: 1813 dated CIL shifted from existing Useful Heat Value(UHV) based grading and pricing of non-coking coal produced from its subsidiaries to full Gross Calorific Value (GCV) based system. 6

17 GCV based grading system classifies non coking coal into 17 categories based on calorific values(energy content) of coal ranging from 2200 Kcal/kg to 7000 Kcal/kg and above along with a defined price for particular range in each category. NTPC and its subsidiaries requires coal minimum of 3100 Kcal/kg for its operation which are based on sub-critical technology. NTPC which fulfills its fuel requirements based on legally enforceable FSA s from CIL, had refused to pay the amount of Rs 1100 Cr towards ECL alleging that it supplied inferior quality fuel and billed for another grade. Notably NTPC stations of Kahelgaon & Farraka also cater to the power needs of Delhi as per the Long term PPA s act between Delhi Govt. & NTPC. Any increase in cost of generation on account of low fuel quality by these stations would also pass on to the power purchase cost via. Energy charges billed towards discoms including BRPL & hence an increase in consumer tariff. So it is imperative to devise a mechanism in order to have a prudence check on energy bills of GENCOS. In case of Central generation/transmission entities once tariffs are fixed, there is little incentive /penalty to improve on productivity/efficiency norms and they function in a very protected tariff regime where costs are routinely passed on to them. Any benefits in improvement in efficiencies/productivity are entirely retained by these entities whereas in the case of State distribution utilities it is supposed to be passed on to the consumers. While the regulatory regime for the CPSUs is conducive, with little political influence on tariff determination, it is unfavorable for the Distribution utilities where retail tariff determination is a highly politicized issue. As a result, while on one hand Central Public Sector Utilities (CPSUs) in Power sector like NTPC, NHPC, PGCIL, DVC etc are showing enviable profits, the state distribution utilities are becoming financially unviable. 1.7 Organization Profile About BSES Group BSES is the leading private sector power utility company in the country. BSES Limited is India's premier utility engaged in the distribution of electricity. Formerly, known as Bombay Suburban Electric Supply Limited, it was incorporated on 1st October 1929, for the distribution of 7

18 electricity in the suburbs of Mumbai, with a pioneering mission to make available uninterrupted, reliable, and quality power to customers and provide value added services for the development of the power and infrastructure sectors. 1. BSES s total consumer base is over 5 million covering substantial areas of Delhi, Goa, Orissa and Mumbai. 2. Distribution area spans about 1.24 lakh sq. km covering an estimated population of 45 million. 3. Nearly 16,000 million units of electricity billed to industrial, commercial and residential consumers with distribution capacity of nearly 6,000 MW. With 7 decades in the field of power distribution, the Electricity Supply Division of BSES has achieved the distinction of operating its distribution network with 99.98% on-line reliability and has a distribution loss of only 11.6%. BSES is amongst the first utilities in India to adopt computerization in 1967 to meet the increasing workload. With a view to optimally utilize trained manpower and expertise in the field of power, the company commenced contracting activities in 1966 by undertaking turnkey electrical contracts, thermal, hydro and gas turbine installations and commissioning contracts, transmission line projects etc. BSES set up its own 500 MW Thermal Power Plant and the first 2 x 250 MW units of Dahanu Power Station were synchronized and began commercial operation during A dedicated 220 kv double circuit transmission line network with three 220 / 33kV receiving stations have been installed to evacuate the power to the distribution area of the Company. BSES through international competitive bidding acquired an equity stake of 51% in three of the four Distribution Companies of Orissa BSES Delhi Following the privatization of Delhi s power sector and unbundling of the Delhi Vidyut Board in July 2002, the business of power distribution was transferred to BSES Yamuna Power Limited (BYPL) and BSES Rajdhani Power Limited (BRPL). These two of the three successor entities distribute electricity to lakh customers in two thirds of Delhi. The Company acquired 8

19 assets, liabilities, proceedings and personnel of the Delhi Vidyut Board as per the terms and conditions contained in the Transfer Scheme BSES Rajdhani Power Limited (BRPL) BRPL distributes power to an area spread over 750 sq. km with a population density of 2192 per sq. km. It s over lakh customers are spread over 19 districts across South and West areas including Alaknanda, Khanpur, Vasant Kunj, Saket, Nehru Place, Nizamuddin, Sarita Vihar, Hauz Khas, R.K. Puram, Janakpuri, Najafgarh, Nangloi, Mundka, Punjabi Bagh, Tagore Garden, Vikas Puri, Palam and Dwarka. Since taking over distribution, BSES singular mission has been to provide reliable and quality electricity supply. BSES has invested over Rs 4500 crore on upgrading and augmenting the infrastructure which has resulted in a record reduction of AT&C losses. In BRPL area AT&C losses have been reduced from 51.2% to 18.09% in FY based on new norms (MYT Regulations, 2011) & propose to reduce it further to 16.43% by FY 13-14, a reduction of 34.7%. FIGURE 1.3: Delhi Distribution area of BRPL. 9

20 Business of the Organization: Delhi Supply Division Caters to an area of 950 sq. kms Supply Area covers South Delhi, East Delhi, West Delhi and Central Delhi. Consumers include houses, residential complexes, high rise buildings, commercial Complex medium and large industrial houses, government establishment like Airport, Worship places, Milk Dairy, Mother Dairy and Municipal Hospitals, Sewerage projects etc. Caters to more than 33 lakh consumers. 40% reduction in losses post takeover, current loss level 17%. BSES forms 68% of Delhi s demand serving 3800 MW peak demand. Invested close to Rs Cr in last 10 years. Provides highly reliable and continuous supply Classification of Supply The Various categories of consumers served by BSES Rajdhani are as follows:- 1. Domestic connection 2. Non Domestic Low Tension 3. Mix Load High Tension 4. Small Industrial Power (SIP) 5. Large Industrial Power (LIP) 6. Agriculture Connection 7. Street Lighting & Signals 8. Delhi Airport Authority India Ltd (DAIL) 9. Delhi Metro Rail Corporation Ltd (DMRC) 10. Delhi Jal Board (DJB) 10

21 2.1 Literature Review Policies & Regulation CHAPTER-2 LITERATURE SURVEY, POLICIES & RESEARCH METHODOLOGY Electricity Act, 2003 confers the power of Policies & Regulation formulation in hands of regulatory commissions. CERC (Central Electricity Regulatory Commissions) does the same for central agencies and SERCs (State Electricity Regulatory Commissions) is for entities under respective state government Determination of Tariff Section 62 (1) of EA 2003 states that the Appropriate Commission shall determine the tariff in accordance with provisions of this Act for (a) Supply of electricity by a generating company to a distribution licensee: Provided that the Appropriate Commission may, in case of shortage of supply of electricity, fix the minimum and maximum ceiling of tariff for sale or purchase of electricity in pursuance of an agreement, entered into between a generating company and a licensee or between licensees, for a period not exceeding one year to ensure reasonable prices of electricity; (b) transmission of electricity ; (c) wheeling of electricity; (d) retail sale of electricity MYT Mechanism Statutory framework Section 61 of EA 2003 requires the Appropriate Commission to be guided by MYT Principles while specifying the Terms and Conditions for determination of tariff. Clause 5.3 (h) of the Tariff Policy stipulates that: 1. The MYT framework is to be adopted for any tariffs to be determined from April 1, The framework should feature a five-year control period. The initial control period may however be of 3-year duration for transmission and distribution if deemed necessary by the Regulatory 11

22 Commission on account of data uncertainties and other practical considerations. In cases of lack of reliable data, the Appropriate Commission may state assumptions in MYT for first control period and a fresh control period may be started as and when more reliable data becomes available 2. In cases where operations have been much below the norms for many previous years the initial starting point in determining the revenue requirement and the improvement trajectories should be recognized at relaxed levels and not the desired levels. Suitable benchmarking studies may be conducted to establish the desired performance standards. Separate studies may be required for each utility to assess the capital expenditure necessary to meet the minimum service standards. 3. Once the revenue requirements are established at the beginning of the control period, the Regulatory Commission should focus on regulation of outputs and not the input cost elements. At the end of the control period, a comprehensive review of performance may be undertaken. 4. Uncontrollable costs should be recovered speedily to ensure that future consumers are not burdened with past costs. Uncontrollable costs would include (but not limited to) fuel costs, costs on account of inflation, taxes and cess, variations in power purchase unit costs including on account of hydro-thermal mix in case of adverse natural events. Some states have notified MYT Regulations, and many have also issued MYT Orders, namely Maharashtra, Delhi, Andhra Pradesh, and West Bengal. Principles & Objectives of MYT The Commission through these Tariff Regulations aims to meet the following objectives: (a) Continue and improve upon the existing incentivisation framework to reward performance and promote efficiency. (b) Provide regulatory certainty to the investors and consumers by promoting transparency, consistency and predictability of regulatory approaches. (c) Ensure financial viability of the sector to attract investments & safeguard consumer s interest. (d) Develop equitable risk sharing mechanism between utility and consumers 12

23 Determination of Wheeling Tariff & Retail Supply of Tariff In accordance with Terms and conditions for DERC s Determination of Wheeling tariff & Retail Supply of Tariff-2011, the commission shall determine Average Revenue Requirement and (ARR) and Tariff fori) Wheeling business & ii) Retail supply business Principles for Determination of ARR ARR for Wheeling Business The Aggregate Revenue Requirement for wheeling Business of the Distribution Licensee for each year of the Control Period shall contain the following items; I. Operation & Maintenance expenses; II. Return on Capital employed; III. Depreciation; IV. Income Tax; V. Interest on consumer security Deposit; VI. Less: Non Tariff Income; VII. Less: Income from other business; and VIII. Less: Income from wheeling of electricity. ARR for Retail Supply of Business The Aggregate Revenue Requirement for Retail Supply Business of the Distribution Licensee for each year of the Control Period shall contain the following items; I. Cost of Power Procurement; II. Transmission & Load Dispatch charges; III. Return on Capital employed; IV. Operation & Maintenance expenses; V. Depreciation; VI. [Income Tax; VII. Interest on consumer security Deposit; 13

24 VIII. Less: Non Tariff Income; IX. Less: Income from other business; and X. Less: Receipts On account of Cross Subsidy Surcharge and additional surcharge for open access customers. Cost of Power Procurement i) Quantum of Power Purchase The commission approved category wise sales forecast shall be applied along with distribution loss trajectory foe estimating the Licensees power procurement requirement for each year of control period. ii) Distribution Licensee shall be allowed to recover the net cost of power it procures from the sources approved by the commission, viz-intra-state and inter state Trading Licensees, Bilateral purchases, Bulk suppliers,state generators,independent Power producers, Central generating Stations<non-conventional energy generators, generation business of the distribution licensee and others, assuming maximum normative rebate available fr4om each source of payment of bills through letter of credit on presentation of bills for supply to consumers of Retail Supply Business; a. Provide that the Distribution Licensee shall propose the cost of Power Procurement taking into account the fuel adjustment formula specified for the generating stations and net revenues through Bilateral exchanges and Unscheduled Interchange(UI) transactions; b. Provided further that where the Licensees utilizes a part of power purchase approved or bulk supply allocated or Contacted for the Retail Supply business, the Distribution licensee shall provide an Allocation Statement clearly specifying the cost of power purchase that is attributable to such trading activity. iii) While approving the Power Purchase, the commission shall determine the quantum of power to be purchased from various sources in accordance with the principles of merit order schedule and dispatched based on ranking of all approved sources of supply in their order of their variable cost of purchase. All power purchase shall be considered legitimate unless it is established that the merit order principle has been violated or power has been purchased at an unreasonable rates or the power procurement guidelines as laid down by the commission from time to time has not be followed. 14

25 iv) To promote economic procurement of power as well as maximizing revenue from sale of surplus power the commission may evolve an appropriate mechanism to incentivize/penalize the Distribution Licensee. v) The renewable purchase obligation shall be as per the order issued by the commission from time to time. 2.2 Research Methodology Study of regulations & orders of CERC for Tariff Determination for CGS & DERC for determination of ARR for Discoms Study of ARR petitions & Tariff orders of BRPL for analyzing Power Purchase Cost Calculation of ECR of various CGS from actual generation bills rose to BRPL for FY12 & 13 Correlation analysis between LPPF & CVPF & ECR of NTPC Stations Plant wise quantitative analysis for determining irregularities in energy charges & increase in PPC of BRPL FIGURE 2.1 Research Methodology followed for data collection 15

26 2.2.1 Correlation Analysis The correlation measures the strength of the linear relationship between numerical variables, for example, the height of men and their shoe size or height and weight. Pearson s Correlation is used in case of quantitative variables and is denoted by letter (r). In these situations the goal is not to use one variable to predict another but to show the strength of the linear relationship that exists between the two numerical variables. The strength of linear association between two numerical variables in a population is determined by the correlation coefficient, whose range is -1 to +1. Graphically the greater the density of the points around the line, the greater the strength of the Correlation between two variables. In example I, the correlation is high; in example II, the correlation is low. 16

27 CHAPTER -3 ENERGY CHARGES & MYT MODEL 3.1. COMPUTATION OF ENERGY CHARGES BY GENCOS FOR TARIFF DETERMINATION Definitions a. 'auxiliary energy consumption' or 'AUX' in relation to a period in case of a generating station means the quantum of energy consumed by auxiliary equipment of the generating station, and transformer losses within the generating station, expressed as a percentage of the sum of gross energy generated at the generator terminals of all the units of the generating station; b. beneficiary in relation to a generating station means the person purchasing electricity generated at such a generating station whose tariff is determined under these regulations; c. declared capacity or DC' in relation to a generating station means, the capability to deliver ex-bus electricity in MW declared by such generating station in relation to any time-block of the day or whole of the day, duly taking into account the availability of fuel or water, and subject to further qualification in the relevant regulation; d. 'design energy' means the quantum of energy which can be generated in a 90% dependable year with 95% installed capacity of the hydro generating station; e. gross calorific value or GCV in relation to a thermal generating station means the heat produced in kcal by complete combustion of one kilogram of solid fuel or one litre of liquid fuel or one standard cubic meter of gaseous fuel, as the case may be; f. `gross station heat rate or GHR means the heat energy input in kcal required to generate one kwh of electrical energy at generator terminals of a thermal generating station; g. installed capacity' or 'IC means the summation of the name plate capacities of all the units of the generating station or the capacity of the generating station (reckoned at the generator terminals), approved by the Commission from time to time; h. 'plant availability factor (PAF)' in relation to a generating station for any period means the average of the daily declared capacities (DCs) for all the days during that period 17

28 expressed as a percentage of the installed capacity in MW reduced by the normative auxiliary energy consumption i. 'scheduled energy' means the quantum of energy scheduled by the concerned Load Despatch Centre to be injected into the grid by a generating station over a day ; j. scheduled generation or SG' at any time or for any period or time-block means schedule of generation in MW or MWh ex-bus, given by the concerned Load Despatch Centre; Components of Tariff. The tariff for supply of electricity from a thermal generating station shall comprise two parts, namely, capacity charge (for recovery of annual fixed cost consisting of the components specified to in regulation 14 ) and energy charge (for recovery of primary fuel cost and limestone cost where applicable)as per CERC s Terms and Conditions of Tariff,2009 regulations. The annual fixed cost (AFC) of a generating station or a transmission system shall consist of the following components (a) Return on equity; (b) Interest on loan capital; (c) Depreciation; (d) Interest on working capital; (e) Operation and maintenance expenses; (f) Cost of secondary fuel oil (for coal-based and lignite fired generating stations only); (g) Special allowance in lieu of R&M or separate compensation allowance, wherever applicable Computation and Payment of Capacity Charge and Energy Charge for Thermal Generating Stations 1) The fixed cost of a thermal generating station shall be computed on annual basis, based on norms specified under these regulations, and recovered on monthly basis under capacity charge. The total capacity charge payable for a generating station shall be shared by its 18

29 beneficiaries as per their respective percentage share / allocation in the capacity of the generating station. 2) The capacity charge (inclusive of incentive) payable to a thermal generating station for a calendar month shall be calculated in accordance with the following formulae : i) Generating stations in commercial operation for less than ten (10) years on 1st April of the financial year : AFC x ( NDM / NDY ) x ( x PAFM / NAPAF ) (in Rupees); Provided that in case the plant availability factor achieved during a financial year (PAFY) is less than 70%, the total capacity charge for the year shall be restricted to AFC x ( / NAPAF ) x ( PAFY / 70 ) (in Rupees). ii) For generating stations in commercial operation for ten (10) years or more on 1st April of the year: AFC x ( NDM / NDY ) x ( PAFM / NAPAF ) (in Rupees). Where, AFC = Annual fixed cost specified for the year, in Rupees. NAPAF = Normative annual plant availability factor in percentage NDM = Number of days in the month NDY = Number of days in the year PAFM = Plant availability factor achieved during the month, in percent: PAFY = Plant availability factor achieved during the year, in percent (3) The PAFM and PAFY shall be computed in accordance with the following formula: N PAFM or PAFY = x Σ DCi / { N x IC x ( AUX ) } % 19

30 i = 1 Where, AUX = Normative auxiliary energy consumption in percentage. DCi = Average declared capacity (in ex-bus MW), subject to clause (4) below, for the ith day of the period i.e. the month or the year as the case may be, as certified by the concerned load dispatch centre after the day is over. IC = Installed Capacity (in MW) of the generating station N = Number of days during the period i.e. the month or the year as the case may be. Note : DCi and IC shall exclude the capacity of generating units not declared under commercial operation. In case of a change in IC during the concerned period, its average value shall be taken. (4) In case of fuel shortage in a thermal generating station, the generating company may propose to deliver a higher MW during peak-load hours by saving fuel during off-peak hours. The concerned Load Despatch Centre may then specify a pragmatic day-ahead schedule for the generating station to optimally utilize its MW and energy capability, in consultation with the beneficiaries. DCi in such an event shall be taken to be equal to the maximum peak-hour expower plant MW schedule specified by the concerned Load Despatch Centre for that day. (5) The energy charge shall cover the primary fuel cost and limestone consumption cost (where applicable), and shall be payable by every beneficiary for the total energy scheduled to be supplied to such beneficiary during the calendar month on ex-power plant basis, at the energy charge rate of the month (with fuel and limestone price adjustment). Total Energy charge payable to the generating company for a month shall be: (Energy charge rate in Rs./kWh) x {Scheduled energy (ex-bus) for the month in kwh.} (6) Energy charge rate (ECR) in Rupees per kwh on ex-power plant basis shall be determined to three decimal places in accordance with the following formulae: 20

31 a) For coal based and lignite fired stations ECR = { (GHR SFC x CVSF) x LPPF / CVPF + LC x LPL } x 100 / (100 AUX) (b) For gas and liquid fuel based stations ECR = GHR x LPPF x 100 / {CVPF x (100 AUX)} Where, AUX = Normative auxiliary energy consumption in percentage. CVPF = Gross calorific value of primary fuel as fired, in kcal per kg, per litre or per standard cubic metre, as applicable. CVSF = Calorific value of secondary fuel, in kcal per ml. ECR = Energy charge rate, in Rupees per kwh sent out. GHR = Gross station heat rate, in kcal per kwh. LC = Normative limestone consumption in kg per kwh. LPL = Weighted average landed price of limestone in Rupees per kg. LPPF = Weighted average landed price of primary fuel, in Rupees per kg, per litre or per standard cubic metre, as applicable, during the month. SFC = Specific fuel oil consumption, in ml per kwh. (7) The landed cost of fuel for the month shall include price of fuel corresponding to the grade and quality of fuel inclusive of royalty, taxes and duties as applicable, transportation cost by rail / road or any other means, and, for the purpose of computation of energy charge, and in case of coal/lignite shall be arrived at after considering normative transit and handling losses as percentage of the quantity of coal or lignite dispatched by the coal or lignite supply company during the month as given below : Pithead generating stations : 0.2% Non-pithead generating stations : 0.8% 21

32 (8) The landed price of limestone shall be taken based on procurement price of limestone for the generating station, inclusive of royalty, taxes and duties as applicable and transportation cost for the month. (9) The tariff structure as provided in this regulation may be adopted by the Department of Atomic Energy, Government of India for the nuclear generating stations by specifying annual fixed cost (AFC), normative annual plant availability factor (NAPAF), installed capacity (IC), normative auxiliary power consumption (AUX) and energy charge rate (ECR) for such stations. 3.2 MYT Model for Distribution Licensee Uncontrollable & Controllable parameter Regulatory Commission has segregated the costs and performance elements into controllable and uncontrollable based on the ability of the licensee to manage each of them. Uncontrollable Parameters Those parameters which are beyond the control of utility, following are some of the uncontrollable factors (a) Power purchase expenses due to increase in fuel costs and change in sales quantum. (b) Sales quantum & sales mix. (c) Interest expense on long term loan & working capital (d) Increase in expenses due to force majeure such as fire, war, natural calamities, etc. Targets for Controllable Parameters The Commission shall set targets for each year of the Control Period for the parameters that are deemed to be controllable and which include 22

33 (a) (b) (c) (d) (e) (f) (g) AT&C Loss, which shall be measured as the difference between the units input into the distribution system and the units realized (units billed and collected) wherein the units realized shall be equal to the product of units billed and collection efficiency. Distribution losses, which shall be measured as the difference between total energy input for sale to all its consumers and sum of the total energy billed in its License area in the same year. Collection efficiency, which shall be measured as ratio of total revenue realized to the total revenue billed for the same year. Operation and Maintenance Expenditure which includes employee expenses, repairs and maintenance expenses, administration and general expenses and other miscellaneous expenses viz. audit fees, rents, legal fees etc. Return on Capital Employed. Depreciation. Quality of Supply. Operation & Maintenance Expenses (O&M) expenses comprise of costs incurred on a day to- day basis in order to run the business efficiently. These costs include: Employee Cost Employee cost shall be computed as per the approved norm escalated by consumer price index (CPI), adjusted by provisions for expenses beyond the control of the Distribution Licensee and one time expected expenses, such as recovery/adjustment of terminal benefits, implications of pay commission, arrears and Interim Relief, governed by the following formula: EMPn = (EMPb * CPI inflation) + Provision Where: EMPn: Employee expense for the year n EMPb: Employee expense as per the norm 23

34 CPI inflation: is the average increase in the Consumer Price Index (CPI) for immediately preceding three years. Provision: Provision for expenses beyond control of the Distribution Licensee and expected one-time expenses as specified above Repairs and Maintenance Expense Repairs and Maintenance expense shall be calculated as percentage (as per the norm defined) of Opening Gross Fixed Assets for the year governed by following formula: R&Mn = Kb* GFAn Where: R&Mn: Repairs & Maintenance expense for nth year GFAn: Opening Gross Fixed Assets for nth year Kb: Percentage point as per the norm Administrative and General Expense A&G expense shall be computed as per the norm escalated by wholesale price index (WPI) and adjusted by provisions for confirmed initiatives (IT etc. initiatives as proposed by the Distribution Licensee and validated by the Commission) or other expected one-time expenses, and shall be governed by following formula: A&Gn = (A&Gb * WPI inflation) + Provision Where: A&Gn: A&G expense for the year n A&Gb: A&G expense as per the norm WPI inflation: is the average increase in the Wholesale Price Index (WPI) for immediately preceding three years Provision: Cost for initiatives or other one-time expenses as proposed by the Distribution Licensee and validated by the Commission. Mechanism for sharing of gains or losses on account of controllable factors The approved aggregate gain to the Distribution Licensee on account of controllable factor of aggregate technical and commercial (AT&C) losses shall be dealt with in the following manner: a) One-third of the amount of such gain shall be passed on as a rebate in tariff over such period as may be stipulated in the Order of the Commission. 24

35 b) The balance amount, which will amount to two-third of such gain, may be utilized at the discretion of the Distribution Licensee. The approved aggregate loss to the Distribution Licensee on account of controllable factor of aggregate technical and commercial (AT&C) losses shall be dealt with in the following manner: a) Two-thirds of the amount of such loss may be passed on as an additional charge in tariff over such period as may be stipulated in the Order of the Commission. b) The balance amount of loss shall be absorbed by the Distribution Licensee. The gain or loss on account of other controllable factors, unless otherwise specifically provided by the Commission shall be to the account of the Distribution Licensee. Annual Truing-up mechanism The Commission shall review variations in approved values of uncontrollable parameters through an annual truing up mechanism while there shall be no adjustment for variations in controllable items. Annual truing-up shall be carried out for variations due to sales and power purchase costs. Return The principle for providing return to the transmission and distribution licensee has been based on the principle of Return on Capital Employed (RoCE) on a regulated rate base, with the weighted average cost of capital to be determined independently for each year of the Control Period. In case of generating companies, the principle for providing return has been based on the Return on Equity. Sales forecast a) The Commission based on the Licensee s filings, shall examine the forecasts for reasonableness and consistency, and shall approve the sales forecast for each year of the Control Period. b) Sales shall be treated as uncontrollable. The open access transactions shall not form part of sales. Power purchase quantum and cost for any Financial Year shall be computed on the basis of AT&C loss targets and the estimated sales. 25

36 Capital Investment - The Commission shall approve capital investment plan of the Licensees for the Control Period commensurate with load growth, distribution loss reduction and quality improvement proposed in the Business Plan. The investment plan shall also include corresponding capitalization schedule and financing plan. Quality of Supply and Customer Service - The quality of supply and the customer service parameters shall be monitored as per the norms to be prescribed by the Commission separately from time to time. a) Voltage fluctuations: Licensee shall maintain voltages at the point of commencement of the supply to a consumer within the limits stipulated by the commission. b) Meter complaints : The licensee shall perform the following meter related activities subject to the provisions provided in the Supply Code and other associated regulations and codes specified by the commission. Other parameters of quality of supply should be followed as per the instruction by the commission. Some of the parameters are listed below:- 1. Operation of call center 2. Restoration of supply 3. Shifting of meters/service lines 4. New connections/additional load 5. Transfer of ownership and change of category 6. Temporary supply of power 7. Consumer bills complaint 8. Disconnection of supply 9. Reconnection of supply following disconnection due to non-payment of bills 10. Street Light faults Reliability Indices The Commission shall impose a uniform system of recording and reporting of distribution system reliability performance. The same reliability indices shall be imposed on all licensees under that commission. The performance target levels set by the Commission shall be unique to 26

37 each licensee to be based initially on the historical performance of licensee. The licensee shall compute the following distribution reliability indices:- a. System Average Interruption Frequency Index (SAIFI = Total number of sustained interruptions in a year / Total number of consumers b. System Average Interruption Duration Index (SAIDI) = Total duration of sustained interruptions in a year / Total number of consumers c. Momentary Average Interruption Frequency Index (MAIFI) = Total number of momentary interruptions in a year / Total number of consumers Contingency Reserve The Commission has also created a Contingency Reserve (CR) for each licensee at the start of the Control Period for minimizing the impact of uncontrollable factors on retail tariffs and ensures tariff stability across the Control Period. Income Tax Income Tax, if any, on the Licensed business of the Distribution Licensee shall be treated as expense and shall be recoverable from consumers through tariff. However, tax on any income other than that through its Licensed business shall not be a pass through, and it shall be payable by the Distribution Licensee itself. The income tax actually payable or paid shall be included in the ARR. The actual assessment of income tax should take into account benefits of tax holiday, and the credit for carry forward losses applicable as per the provisions of the IT Act 1961 shall be passed on to the consumers. Non-Tariff Income All incomes being incidental to electricity business and derived by the Licensee from sources, including but not limited to profit derived from disposal of assets, rents, delayed payment surcharge, meter rent (if any), income from investments other than contingency reserves, miscellaneous receipts from the consumers and income to Licensed business from the Other 27

38 Business of the Distribution Licensee shall constitute Non-Tariff Income of the Licensee ATE s directive to SERCs for timely tariff determination The Appellate Tribunal for Electricity (ATE) issued a judgment in its order dated 11 November 2011 and in its judgment has directed all SERCs to initiate suo-moto proceedings for tariff determination in case of delays by the utilities in filing their tariff petitions. The key features of ATE s directive are mentioned below: 1. It should be the endeavor of every State Commission to ensure that the tariff for the financial year is decided before 1st April of the tariff year, for which tariff petition should be filed by the end of November of the previous year. Truing-up should also be an annual exercise. 2. In the event of any delay in filing the ARR, truing-up and Annual Performance Review, one month beyond the scheduled date of submission of the petition, the State Commission must initiate suo-moto proceedings for tariff determination. 3. The recovery of the Regulatory Asset (RA) should be time-bound and within a period not exceeding three years at the most and preferably within the control period. The carrying cost of the RA should be allowed to the utilities in the ARR of the year in which the RA are created to avoid the problem of cash flow to the distribution licensee. 4. Fuel and Power Purchase cost is a major expense of the distribution company, which is uncontrollable. The Fuel and Power Purchase cost adjustment should preferably be on a monthly basis but in no case exceed a quarter. Any State Commission that does not already have such a formula/mechanism in place must put in place such a formula/ mechanism within 6 months of the date of this order Revenue Gap The gap between tariff and cost has increased over time, as in FY , there was a need to increase the tariff by about 22% in all categories to recover cost. This is primarily because of mounting regulatory assets & fuel price driven costs -the largest component of the cost of supply have grown quite significantly in the recent past. 28

39 TABLE 3.1 Build UP Revenue gap since FY to FY Revenue Gap BRPL BYPL TPDDL TOTAL UPTO FY (611.50) (351.10) (936.67) FY (1,068.70) (532.58) (741.46) (2,352.11) FY (as approved by commission) FY (Projected by DISCOMs) FY (Projected by DISCOMs) (1,545.72) (1,120.93) (963.61) (3,630.26) (4,233.00) (2,216.00) (1,783.00) (8,282.00) (1,779.00) (1,690.00) (885.00) (4,354.00) Total Revenue Gap (9,237.39) (5,533.58) (4,734.17) (19,505.04) SOURCE: Statutory advice of DERC dated The table below gives the revenue gap built due to difference between the ARR claimed by BRPL & Revenue actually realized from the prevalent tariff philosophy as approved by commission for respective year. FIGURE 3.2 Average Revenue Required & Revenue Actually Realized by tariff for BRPL FY FY FY FY FY ARR of BRPL Revenue available from Tariff Revenue (Gap)/ Surplus Source: ARR approved FY 13-14, Review of FY & True Up order FY-10, 11,12 of BRPL 29

40 Treatment of Revenue Gap In order to meet this revenue gap, DERC has decided to continue with a surcharge of 8% on partial liquidation of accumulated deficit and meeting of carrying cost of the past deficit of three DISCOMs BRPL, BYPL & TPDDL. TABLE 3.3 ARR approved & Revenue surplus/deficit for FY Particulars BRPL BYPL TPDDL TOTAL NDMC ARR claimed 7, , , , , ARR approved 6, , , , , Revenue at existing tariff excluding 8 % surcharge 6, , , , Revenue(gap)/surplus (40.13) (115.48) Surcharge , Total (gap)/surplus 1, , (115.48) SOURCE: DERC s Press Release Tariff orders of DISCOMs during FY Fuel Price Adjustment Charge Any fluctuation in the cost of fuel is a pass through for the generator through a fuel price adjustment formula and is payable by the distribution licensees in their monthly bills. However, power purchase cost being uncontrollable, in nature, is pass-through to the consumers but the difference in actual cost of procurement of power and the estimated cost of purchase of power gets trued up only after 2 years. The time lag of two years puts additional burden on consumers by way of interest charges which have to be borne by the consumers, additionally. The DERC vide its Order dated August 26, 2011 in Petition Nos 22/2010, 23/2010 and 24/2010 has given the Fuel Price Adjustment mechanism on quarterly basis for thermal power generating stations having long-term PPAs with distribution licensees of Delhi. The Distribution licensee is allowed to adjust the difference between the actual variable fuel cost and variable fuel cost approved in the Tariff Order for the financial year on a quarterly basis, in respect of thermal power stations having long term power purchase agreements. 30

41 a. The Fuel Price Adjustment would be done according to the formula given below: Where, VC = Variable Cost/Charges billed by the generating companies for the concerned power station for the relevant period Average Rate of FPA nth Qtr. (Rs. /Kwh) = Avg. VC (n-1) th Qtr. (Rs. /Kwh) Avg.VC (Base) (Rs. /Kwh) Avg. VC (n-1)th Qtr (Rs/kWh) = V.C. per unit in (n-1)th Qtr x units procured from respective Thermal plants in (n-1)th Quarter Total units procured from all thermal stations in (n-1) th Quarter. b. The percentage increase on account of FPA will be applied as a surcharge on the total energy charges (excluding fixed charges, theft bills, arrears, LPSC, E. Tax etc.) billed to a consumer of the utility c. The FPA calculated for any quarter shall be applied prospectively for 3 months after approval is received from the Commission. d. In view of the fact that FPA computed for any quarter will be applied after a time delay for a subsequent 3-month period, there would necessarily be a difference between the actual fuel cost increase and the recovery by the distribution utility through the quarterly 31

42 adjustments. The difference will be adjusted at the time of annual True-up undertaken by the Commission for that year. e. This Fuel Price Adjustment (FPA) formula shall remain applicable till it is amended, reviewed, revised or otherwise amended. The Commission via Press Release during Tariff orders of DISCOMs during FY informed that the prevailing Tariff for Fy includes 3 % to 4.5 % of PPAC in tariff for all category of consumers. 32

43 CHAPTER-4 RESULTS & DISCUSSION 4.1 RESULTS FROM STUDY OF ENERGY CHARGE RATE OF NTPC STATIONS The correlation values derived from the comparison of various pit /non pit head stations from April 2011 to March 2012: S.No. TABLE 4.1 Plant wise calculations of ECR & its components for FY FY SHR (Kcal/kWh) Avg. ECR (Rs./kWh) 1 Non Pit BTPS Non Pit Unchahar-I Non Pit Unchahar-II Non Pit Unchahar-III Non Pit NCPP-I Non Pit NCPP-II Non Pit Aravali Pit head Farraka Pit head KHTPS-I Pit head Rihand-I Pit head Rihand-II Pit head Singrauli Pit head KHTPS-II SOURCE : Actual bills raised by various power plants to BRPL in FY The correlation values derived from the comparison of various pit /non pit head stations from April 2012 to March 2013: S.No. Pit Head /Non Pit Head Correlation b/w LPPF & ECR TABLE 4.2 Plant wise calculations of ECR & its components for FY Pit Head /Non Pit Head Station Name Station Name SHR (Kcal/kWh) Avg. CVPF (Kcal/Kg) Avg. CVPF (Kcal/Kg) Avg. LPPF (Rs./Kg) FY Avg. LPPF (Rs./Kg) Avg. ECR (Rs./kWh) Correlation b/w CVPF & LPPF Correlation b/w CVPF & LPPF Correlation b/w LPPF & ECR Correlation b/w CVPF & ECR Correlation b/w CVPF & ECR 1 Non Pit BTPS Non Pit Unchahar-I Non Pit Unchahar-II Non Pit Unchahar-III Non Pit NCPP-I Non Pit NCPP-II Pit head Farraka Pit head KHTPS-I Pit head Rihand-I Pit head Rihand-II Pit head Singrauli Pit head KHTPS-II SOURCE : Actual 1st bills raised by various power plants to BRPL in FY

44 Plant wise Statistical analysis of components of Energy Charge Rate using Pearson s Correlation (Refer to ANNEXURE I for Plant wise details of ECR components) BTPS The FIGURE 4.3 below shows the variations in price of coal for the calorific value of coal used in respective months: FIGURE 4.5 Correlation for ECR & CVPF FIGURE 4.6 Correlation for ECR & LPPF Inference:. In FY the calorific value of coal varied from 2754 kcal/kg in Sep-11 to a maximum value of 3300 kcal/kg in May-11.Within a year we observe that during Apr-11, for CVPF of 3258kcal/Kg,the LPPF charged was Rs 3.22/Kg while the next year during Apr-12 the LPPF rose to Rs 4.1/Kg for almost the same CVPF of Coal. As a result ECR too rose above Rs 4/unit. 34

45 On UHV basis the quality remained within the range of F Grade throughout the FY12 & FY 13. UNCHAHAR-I The Figure 4.7 below shows the variations in price of coal for the calorific value of coal used in respective months: - FIGURE 4.8 Correlation between ECR & CVPF FIGURE 4.9 Correlation ECR & LPPF Inference: From the trend & correlation we find that very little correlation between LPPF & CVPF was established during FY-12 & 13 due to fact that both E & F grade as on UHV basis of fuel 35

46 was used. The minimum ECR was Rs 1.89/Unit during Apr-11 and rose to Rs 2.57/Unit during Jun-12. UNCHAHAR II The FIGURE 4.9 below shows the variations in price of coal for the calorific value of coal used in respective months: Figure 4.10 Correlation between ECR & CVPF Figure 4.11Correlation between ECR & LPPF 36

47 UNCHAHAR III The FIGURE 4.12 below shows the variations in price of coal for the calorific value of coal used in respective months: Figure 4.13 Correlation between ECR & CVPF Figure 4.14 Correlation between ECR & LPPF Inference: From the trend between LPPF & CVPF we find that both E as well as F grade of coal was used durimg FY 12& FY 13 for Unchahar-I, II & III. However the correlation between ECR & CVPF was negative as desired in FY 12 & 13 which shows good linearity between both the components & less fluctuation in calorific value of coal if landed price is kept constant. The 37

48 average CVPF for all three stations was around 3365 kcal/kg for which average LPPF was charged at Rs. 2.70/kg and the average ECR calculated was Rs 2.20/Unit. FARAKKA TPS The FIGURE 4.15 below shows the variations in price of coal for the calorific value of coal used in respective months: Figure 4.16 Correlations between ECR & CVPF Figure 4.17 Correlation b/w ECR & LPPF 38

49 Inference From the graph, we can observe that for CVPF of Coal about 3600 kcal/kg, the landed price charged varies widely. For a CVPF of about 3600 kcal/kg the price was Rs 5.4 /kg in the month of Jun 11 whereas another higher variety of coal at around 3900kcal/kg fetched Rs 4.6/kg in the month of April 11.In another case, a variety of coal at 3600kcal/kg is charged at two different prices in the month of Sep 11 & Oct 11at Rs 5/kg & Rs 4.3/kg respectively. For FY 12 F grade coal was used towards the end of the year but for FY -13, F grade of coal was used throughout the year. However the correlation between ECR & CVPF was found to be negative when ideally it must have been as close to -1. This is because use of higher grade of coal during FY 12 & 13 did not bring any benefit in reducing ECR of station, rather in FY 12 the average ECR was Rs.3.37/Unit when average CVPF was 3500kcal/Kg. While in the FY 13, the average ECR was Rs 2.49/Unit, despite of using low calorific value of fuel at an average of 3000kCal/Kg. 39

50 CVPF (kcal./kg) KHTPS- I The FIGURE 4.18 below shows the variations in price of coal for the calorific value of coal used in respective months: FIGURE 4.19 Correlation between ECR & CVPF ; FIGURE 4.20 Correlation between ECR & LPPF Correlation between ECR & CVPF for KHTPS-I for FY 12 & FY ECR (Rs./kWh) 40

51 KHTPS-II The FIGURE 4.21 below shows the variations in price of coal for the calorific value of coal used in respective months: FIGURE 4.22 Correlation between ECR & CVPF; FIGURE 4.23 Correlation between ECR & LPPF Inference for KHTPS-I & II: From the monthly trend of CVPF & LPPF we find that in FY-12 the LPPF was higher compared to FY-13 for the same CVPF of coal i.e. average of kcal/kg. As a result ECR for both the stations were high for FY-12 than FY

52 Average ECR for KHTPS-I was Rs 2.72/Kg in FY 12 & in FY 13 was Rs.2.14/Kg.Average ECR for KHTPS-II was Rs 2.57/Kg in FY 12 & in FY 13 was Rs.2.02/Kg. The negative correlation between ECR & CVPF suggests that increase in calorific value of fuel did not result in decrease in ECR, since the advantage of having low ECR by using better CVPF of coal was offset by comparatively higher prices charged for nearly same grade of primary fuel used. NCPP-I The FIGURE 4.24 below shows the variations in price of coal for the calorific value of coal used in respective months: FIGURE 4.25 Correlation between ECR & CVPF ; FIGURE 4.26 Correlation between ECR & LPPF 42

53 Inference From the trend we can figure out that the price of coal month wise continued to remain above Rs4/Kg from June -11 although the quality if coal used decreased from 4000kCal/Kg to 3500kCal/Kg. NCPP-II The FIGURE 4.27 below shows the variations in price of coal for the calorific value of coal used in respective months: INFERENCE From the trend line between CVPF & LPPF, we find that there exists a negative correlation for FY , due to the fact that the prices remained above Rs 4. /Kg from June -11 onwards throughout even if the calorific value of the coal varied to low levels for rest of the year i.e. below 4000kCal/Kg. 43

54 FIGURE 4.28 Correlation between ECR & CVPF; FIGURE 4.29Correlation between ECR & LPPF Inference for NCPP-I & II: The correlation between LPPF & CVPF for FY-12 was negative or least positive. This is because the fuel of a given Calorific value has been charged differently during the year. For instance a 4000 kcal/kg of coal was charged at Rs 3.4/Kg during Apr-11 & within two months the same coal was priced at Rs.4.4/kg, an increase in landed price by 30%.In another case during FY-13, a lower calorific value of fuel at 3753kCal/kg was priced at Rs 4.59/Kg in Jun-12. RIHAND-I The FIGURE 4.30 below shows the variations in price of coal for the calorific value of coal used in respective months 44

55 FIGURE 4.31 Correlation between ECR & CVPF FIGURE 4.32 Correlation between ECR & LPPF RIHAND-II The FIGURE 4.33 below shows the variations in price of coal for the calorific value of coal used in respective months: 45

56 FIGURE 4.34Correlation between ECR & LPPF FIGURE 4.35 Correlation between ECR & CVPF The trend line between CVPF & LPPF shows a comparatively higher price charged i.e. above Rs2.5/Kg for lower grade of coal in August &September than April & May. Inference for Rihand I &II: Both the stations used E grade UHV of coal which was around Kcal/Kg. The average LPPF for the same was Rs. 1.93/Kg for both the stations during FY11-12 & Rs 1.49/Kg for FY Average ECR for both the stations in FY 12 was Rs 1.45/Unit & in FY13 Rs 1.13/Unit, the lowest amongst all NTPC stations. SINGRAULI The FIGURE 4.36 below shows the variations in price of coal for the calorific value of coal used 46

57 FIGURE 4.37 Correlation between ECR & CVPF FIGURE 4.38 Correlation between ECR & LPPF Inference: The higher negative correlation between ECR & CVPF shows the cost advantage of using higher quality of fuel resulting in lowering the ECR. The average ECR for FY11-12 was Rs. 1.32/Kg & for FY was Rs 1.08/Kg, being the cheapest source of power for the DISCOM. ARAVALI The FIGURE 4.39 below shows the variations in price of coal for the calorific value of coal used in respective months: 47

58 LPPF (Rs./Kg) FIGURE 4.40 Correlation between ECR & CVPF FIGURE 4.41 Correlation between ECR & LPPF Correlation between ECR & LPPF for Aravali for FY 12 & FY ECR (Rs./kWh) EC 4.2. ANALYSIS OF SHORT TERM PURCHASE/SALE OF POWER THROUGH VARIOUS SOURCES The short purchases/ sales are through traders, bilateral contracts, banking, and power exchanges at market determined prices. As regards the Short Term Power Purchase Cost of BRPL, it was observed that the power was procured at a higher rate while the same was sold in short term markets at a lower rate during surplus sale of power. TABLE 4.42 Sale/Purchase Quantum & Rate of Short term power from FY to FY Year Short Term energy purchase (MU) Short Term Purchase (Cr.) Short Term Power purchase (Rs./unit) Surplus Sales (MU) Short Term power sales (Cr.) Surplus Power Sales (Rs./Unit) Net Power Purchase Rate incl. Interstate & Intrastate charges (Rs./Unit) SOURCE: True Up order for FY & 11-12, ARR approved for FY &

59 From the above table, it is observed that a gap of Rs. 1.91/unit for FY 10-11, Rs.0.68/unit for FY & Rs. 0.99/unit for FY was incurred due to procurement & then sale of surplus power in short term markets. The category wise purchase & sales figures for FY in the table below shows that sale of power through Bilateral (IEX) & Banking mechanism involved higher units of about 2000 MU s with a gap of Rs 0.70/Unit. This resulted to the rise in net energy cost of power procurement to Rs 4.19/Unit (after considering surplus sale of 773 MU at Rs 3.23/Unit) from Rs 4.02/Unit (after considering short term purchase at Rs. 3.91/Unit) in FY Table 4.43 Category wise break up of Short Term Power purchase/sale for FY FY Power Purchase from other sources Power Sold to other Sources PARTICULARS MU Rs Cr. Rs./Unit MU Rs Cr. Rs./Unit Intra State Power BILATERAL / IEX Banking UI TOTAL SOURCE: True Up Petition for FY However, it is notable that the quantum of short term purchase has been reduced significantly over the years & has been proposed to be nil for FY This is due to increase in quantum of long term procurement of power from new additional units from Central as well as State Generating Stations approved by respective commissions. The DERC has approved the sale of 2501 MU s of surplus power by BRPL for FY and has assumed the rate for the same at Rs 4.00/Unit. If this rate as per DERC is considered, the Net power purchase cost (after sale of surplus power) can be reduced provided the average purchase rate of both existing & new Central/State GENCOS is less than Rs 4/Unit. 49

60 CHAPTER -5 CONCLUSION & WAY FORWARD 5.1 CONCLUSION Need for prudence check of Energy Charges billed It is imperative to perform the prudence check of Energy Charges billed by the generation companies. An analysis of energy charges billed by generating companies shows that there is a hardly any correlation between the Landed price of primary fuel (LPPF), Calorific value to primary fuel (CVPF) and the resultant Energy Charges billed. In general, the correlation between the Landed Price of Primary Fuel (LPPF) and Calorific Value of Primary Fuel (CVPF) should be high for a particular plant. But the analysis of the same proves to be otherwise. The correlation for most of the Central Generating stations supplying power to Delhi is insignificant and even negative for some. The correlation values derived from the comparison of CVPF & LPPF of various pit /non pit head stations are found to be as per the following figure 5.1; Figure 5.1 Correlation between month wise CVPF & LPPF of stations for FY

61 From the Figure 5.1, we find that correlation coefficient is significantly less or negative for various stations. Ideally the coefficient should attain nearest possible value to 1, but the lower levels or negative values signifies that possibility of price charged for the coal used at a constant station heat rate is inconsistent with the quality of coal used. The correlation is negative for NCPP-II & Singrauli power stations. Thus the price charged in LPPF component for computation of ECR is either higher for lower grade of coal or differs widely from station to station for the same grade of coal used. The correlation values derived from the comparison of CVPF &ECR of various pit /non pit head stations from March 2011 to April 2012 are found to be as per the following figure; Figure 5.2 Correlation factor derived between CVPF & ECR of stations for FY As per CERC s guidelines for the calculation of energy charge rate, ECR of stations, the ECR varies inversely proportional to the CVPF used at a fixed station heat rate (SHR). Thus the correlation factor should be as close as possible to -1. But from the analysis we find that (r) is positive for BTPS, Farraka, KHTPS-1, & KHTPS-2. This indicates fluctuations in the landed price of coal used for calorific value within a particular range. 51

62 Figure 5.3 Correlation between month wise CVPF & LPPF of stations for FY From the figure 5.3, we find that correlation coefficient is significantly less or negative for various stations. Ideally the coefficient should attain nearest possible value to + 1.The correlation shows high irregularities in price & grade if primary fuel for BTPS, Unchahar I, II, III & Singrauli. Thus the price charged in LPPF component for computation of ECR is either higher for lower grade of coal or differs widely from station to station for the same grade of coal used. Figure 5.4 Correlation factor derived between CVPF & ECR of stations for FY

63 As per CERC s guidelines for the calculation of energy charge rate, ECR of stations, the ECR varies inversely proportional to the CVPF used at a fixed station heat rate (SHR). Thus the correlation factor should be as close as possible to -1.But from the analysis we find that (r) is positive for NCPP-I, II, Farraka, KHTPS-I, II. This indicates fluctuations in the landed price of coal used for calorific value within a particular range Surrender of Power from Costly Power Plants The total quantum of energy requirement at the distribution periphery for FY approved for FY on the distribution loss at 12.89% is MU. Of this, the total share contributed by various CGS of NTPC is 75% and amounts to 8827 MU. A major share of which belong to APCPL, BTPS, NCPP-I & II procured at an average rate of Rs 5.9/Unit, Rs 4.74/Unit, Rs.4.06/Unit & Rs 4.41/Unit respectively, which are the costliest source of power amongst Non Pit Head stations. Similarly, Farraka and KHTPS-I & II continue to be costliest source of power delivering to Delhi at Rs 3.5/Unit, Rs 3.27 & Rs 3.26/Unit respectively, despite of being Pit head stations and are at par with the average rate of power purchase of some of the non pit head stations.(refer to Table 5.5) TABLE 5.5 Comparison of Average Rate for FY with Average ECR for FY 12 & 13 Sl No Pit/Non Pit NTPC Stations BRPL's share FY 14 (MU) Average Rate FY (Rs./Unit) Average ECR for FY (Rs./Unit) Average ECR for FY (Rs./Unit) 1 Non Pit BTPS Non Pit NCPP - DADRI Non Pit DADRI EXTENSION Non Pit APCPL Non Pit UNCHAHAR - I Non Pit UNCHAHAR - II Non Pit UNCHAHAR - III Pit Head FARAKKA Pit Head KAHALGAON - I Pit Head RIHAND - I

64 11 Pit Head RIHAND - II Pit Head SINGRAULI Pit Head KAHALGAON - II SOURCE: ARR order for FY & Actual bills rise to BRPL for FY 12 & 13 Thus it is necessary to reconsider the quantum of power purchased from costly stations & surrender the power wherever alternative a source of power is feasible Better Scope of Management for Short term Power Purchase & Sales Since earlier it was observed that the short term sales through various sources were at a lesser rate than the short term purchase rate in the past 3 years, it is necessary to have adequate banking arrangements & less UI mechanism for sale of surplus power at a comparatively higher rate. FIGURE 5.7 Short Term Power Purchase/Sales Rate for FY to FY SOURCE: TRUE UP order of FY 10-11, 11-12, ARR OF FY 13-14, Review OF FY As per DERC order on ARR of BRPL for FY , the commission has approved that no additional purchase o power is required from short term transactions. However the commission s assumptions on sale of surplus units at Rs 4/Unit is challenging since past trend shows power sales at a lower rate in short term markets. 5.2 WAY FORWARD Alternative sources of power from new or existing stations must be looked for future requirements subject to availability & technical constraints. The commission vide its order on ARR for FY has approved the quantum of 1001 MU from GENCOS for supplying power to BRPL as per Table given below; 54