It is a pleasure to submit herewith the Part I of the report of the Energy Review Committee. This report pertains primarily to the issues pertaining to the Dabhol Power Company.

The Committee would like to place on record the co-operation and help extended by the Government of Maharashtra, Maharashtra State Electricity Board and by the IDFC during the preparation of the Report.

The Committee recommends that in view of the critical importance of the issues involved, the Report be made public in its entirety at the earliest.

(Dr. E.A.S. Sai-ma) Member

(Shri Deepak Parekh) Member

(Dr. Raiendra K. Pachauri) Member

____________________________________________________________________________________

8.5 Rc-cxamine PPAs with All Other IPPs in accordance with a Least-Cost Plan

Following the new power policy announced by the Government of India (Gol) in 1991, and subsequent notifications thereof, several new independent power projects (IPPs) have been and are in the process of being set up in the State of Maharashtra. These include, inter alia, the project of Dabhol Power Company (DPC) of 2184 MW, Central India Power Company (CIPCO^ of 1082 MW, and Reliance Patalganga Power Limited (RPPL) of 447 MW and liquid fuel projects aggregating 1219 MW. A detailed list of such projects is provided in Annex 1. In addition MSEB has granted No-Objection Certificates (NOCs) to a number of captive and cogeneration projects. However, the entire position of demand and supply of electric power appears to have undergone a change in the last five years. This may either be a temporary aberration or a more permanent phenomenon, but since liabilities under power purchase agreements (PPAs) typically executed with IPPs are expected to persist over periods as long as 20 years, a general review of the power situation as well as a specific review of particular IPPs, their financial implications and effect on power supply situation has become necessary. Concomitantly, there is considerable concern regarding the financial health of the Maharashtra State Electricity Board (MSEB). As a matter of prudent governance it is incumbent to evolve a course of action that would be in the larger public interest of the state. Accordingly, the Government of Maharashtra (GoM) constituted an Energy Review Committee to examine some of these issues.

The Energy Review Committee was constituted through Resolution No. PSP 2001/CR3448/NRG-2, dated February 9, 2001, which is reproduced at Annex 2a. The terms of reference of the Committee are as follows:

b) To examine the cost of power supplied by DPC and the distribution of power losses

Further, by its Resolution No. PSP 2001/CR3448/NRG-2 dated March 9, 2001 (which is reproduced at Annex 2b), in accordance with item (e) above, the Government of Maharashtra has referred to the Committee the following additional terms of reference:

1. To examine the situation of present availability and actual supply of electricity within Maharashtra. Also to estimate State's requirement of power for the next 10 years and suggest measures to meet the requirement of power.

2. To review the tariff presently charged by Maharashtra State Electricity Board to various categories of consumers for generation of electricity from various sources, total realisation from billing, electricity distribution and to examine the impact on MSEB. Also to suggest measures to improve financial position of MSEB.

3. Evaluate and review Dabhol Power Project, review any and all of its clearances, tariff and all aspects in the context of the relevant laws and notifications as may be applicable at any specific time.

4. Suggest appropriate measures to ensure that the interests of the State, Maharashtra State Electricity Board and electricity consumers of the State of Maharashtra are properly and adequately considered, evaluated and safeguarded.

5. Negotiate with Dabhol Power Company on behalf of State Government and Maharashtra State Electricity Board for lowering the tariff, capital cost and all other aspects of the Dabhol Power Company.

At the outset, the Committee decided to demarcate the terms of reference in two parts, viz.

I The overall demand and supply of electric power in the Maharashtra and issues relating to IPPs and PPAs in general, and in particular, the agreement with DPC and the financial implications thereof and the recommendations relating to these areas.

II. The broad future course of action for reforms in the State's energy sector. This will address item (d) of the original terms of reference, as well as items (1), (2) and portions of item (4) of the additional terms of reference.

This report is limited to the first part of this demarcation of the terms of reference. The Committee, for reasons mentioned below, did not directly address some of the terms of reference.With respect to DPC, the Committee is concerned that there are numerous infirmities in the process of approvals granted in the project, which bring into question the 'propriety of the decisions. However, this Committee does not consider itself the proper forum to investigate these matters. Though the Committee has been given certain additional terms of reference, specifically, item (3) of Resolution No. PSP 2001/CR3448/NRG-2 dated March 9, 2001, any such investigation will require an in-depth probe, recording of evidence on oath, and calling for relevant records pertaining to the project both in the state government as also Government of India and their agencies such as MSEB, cea, FIPB, etc. The Committee's recommendation on this matter is given in Chapter 8. However, while the development of DPC has been fraught with infirmities, its existence cannot be wished away. Action needs to be taken to address certain urgent and critical issues pertaining to the DPC project so as to bring down the cost of power. In this, the Committee is of the view that negotiations with DPC for lowering the tariff, capital cost and all other project related aspects would be best carried out between parties that are signatory to the various agreements after a clear political mandate is evolved on the submission of this report of the Committee. During discussions held with DPC, it has also indicated its willingness to renegotiate the tariff and sort out other critical project related issues with the relevant parties viz. MSEB, GoM and Gol together at a common forum. In light of the aforesaid, the Committee is of the opinion that it would not be appropriate for the Committee to address item (5) of the additional terms of reference. Instead, the Committee, aware of its responsibilities in this behalf, and in part fulfilment of item (4) of the additional terms of reference, has laid out/certain broad guidelines and indicative directions for the re-negotiation of contracts pertaining to the project.

Dr. Kirit S. Parikh, a member of the Committee, was unable to attend meetings due to prior commitments and hence regretted his inability to associate himself with the first part of the report. His letter is reproduced in Annex 3a. Details regarding the dates of the meetings held by the Committee and a list of individuals with whom the Committee held discussions is given in Annex 3b. A number of representations were also received in response to the Press Note issued by the Committee calling for suggestions and comments. The Committee in its deliberations carefully considered these responses, a list of which is provided in Annex 3c. The Committee thus attempted to make its deliberations as transparent and participatory as possible.

The Committee, soon after its constitution, requested the Ministry of Power (MoP), Government of India (Gol), by a fax, to send their representative? as also the representative of Central Electricity Authority (CEA) to join in the deliberations of the Committee as members. There was no response to this communication. Subsequently, the Committee also invited representatives from relevant departments of Gol, viz.. Ministry of Power, Central Electricity Authority and Department of Economic Affairs, Ministry of Finance to participate in the discussions of the Committee on March 9, 2001. A reply was received from MoP dated March 15, 2001, nominating two persons, who would attend the meetings of the Committee as observers. However, since the Committee had by then substantively concluded its deliberations on Part I of the report, it was decided to inform Gol suitably.

This Report has 8 chapters. Chapters 2 and 3 provide a brief overview of the current state of MSEB and a review of the overall demand and supply of electric power in the State, with particular emphasis on the impact of IPPs. One of the issues discussed here is whether the problems posed by DPC are due to the financial under-performance of MSEB or whether DPC project would be undesirable even if MSEB were in the pink of financial health. The subsequent three chapters focus on DPC. Chapter 4 provides details on DPC; Chapter 5 concentrates on the report of the Negotiating Group-, \\hicli reslructureJ the project in November 1995- and its implementation, and Chapter 6 analyses other critical issues. Chapter 7 explores the sustainability of the DPC project based on the modifications to the terms of various contracts. Chapter 8 contains the recommendations of the Committee. including broad guidelines for re-negotiation of the project.

MSEB has been one of the better performing boards in the country and has, even with the indifferent performance on the T&D front, managed till 1997-98 to consistently earn net revenue surpluses on an accrual basis.

As the analysis in this chapter will show, MSEB has performed reasonably well on the generation front, improving its efficiency considerably. However, it continues to suffer from fuel availability problems for its gas plant at Uran and water availability problems at its Koyna facility, which affects its ability to meet peak and intermediate load effectively.

MSEB's problems lie more in the distribution side of the business. Even though tariffs have been increased regularly, the increase has been unbalanced, with the result that certain customer categories, with excessive tariffs, have b 'n to reduce consumption or go off the grid. Concomitantly, consumers with subsidised tariffs have not tempered their use of power. Consequently, the average realisation has not increased commensurately with the rise in cost of supply. These issues are now being addressed by the Maharashtra Electricity Regulatory Commission (MERC), which envisions the end of cross-subsidy in five years.

The establishment of MERC has also brought the problem of excessive commercial loss, as well as high receivables, into the open. This loss had hitherto been largely disguised as agricultural consumption. While this problem continues, the issues pertaining to DPC have aggravated the financial position of MSEB. As shown later, even with an overnight reduction in loss reduction, MSEB cannot pay for DPC. Neither is the situation improved if there is sufficient additional demand, for it is necessary that the marginal revenue realisation should match the marginal cost of supply. The problem is therefore not just of performance; it is the lack of sufficient demand from relatively higher-tariff categories to absorb nearly 17000 MU of high cost power (at 90% PLF, 2150 MW of base load capacity generate 16950 MU).

Maharashtra accounts for nearly .one-fourth of the gross value of India's industrial sector. Manufacturing and service sectors provide nearly 80% per cent of Maharashtra's income'. It is one of the few states in the country to achieve 100 per cent electrification of its towns and villases, though, as in other st'dtes, a large proportion of its rural households still do not receive electricity. The annual average consumption of electricity per person in the State is considerably higher than the national average². As can be seen in Table 2a below, despite its recent problems, MSEB is one of the better Electricity Boards in the country, with an acknowledged capability in managing a large and complex system.

MSEB has added about 1372 MW since 1995. Over the last five years, from the financial year (FY) 1996 to FY2000, the performance of MSEB's generating stations has steadily improved as shown in Table 2b below. Plant availability has steadily increased from 83.77% to 84.58% and Plant Load Factor (PLF) from 61.24% in 1994-95 to 71.77% in 1999-00, which is however lower than the NTPC average for thermal plants of 80.6% for 1999-00. It would appear that some of the thermal plants are being used to serve intermediate load. MSEB also improved its fuel efficiency, as coal consumption rate (kg/kWh) declined from 0.804 kg/kWh to 0.728 kg/kWh. The oil consumption rate also declined from 4.07 ml/kWh to 2.0 ml/kWh during the same period.

This addition of capacity and improvement in performance, which has been largely due to renovation and modernisation undertaken by MSEB, has exceeded its own expectations at the time when DPC was being considered. In 1993, when the DPC project was under consideration, MSEB expected that there would be considerable slippage in meeting its generation targets and its plants would be beset by fuel shortages, which would significantly onstrain the energy availability from its thermal plants.'"

The performance of the Uran gas turbine based power station (GTPS) has been adversely affected due to declining gas supplies from GAIL, based on declining production at Bombay High. Similarly, the utilisation of the Koyna station is affected due to the existing water use being limited to 67.5 TMC following the Krishna interstate river water dispute award⁴. Both these constraints affect MSEB's ability to meet intermediate and peak loads.

Unlike most other stales, the responsibility for T&D in Maharashtra does not rest fully with MSEB. Its service area excludes the city of Mumbai and parts of Ahmednagar district, where distribution licensees and a Rural Electricity Co-operative provide serviced

The GoM like most other states in the country has pursued a policy of cross subsidy, wherein the agricultural and domestic consumers are subsidised by the commercial and HT consumers. Though small and marginal farmers and persons below poverty line deserve a desree of subsidy, over the last 40 years, many undeserving categories of consumers have got access to the same. Out of 1.30 crore consumers, only 12 lakh H.T. and commercial consumers are not subsidised, i.e., 9 out of 10 consumers of MSEB are subsidised. These 12 lakh consumers represent 43% of energy consumption in the State. Currently, the average tariff realisations for Commercial and HT Industrial categories are Rs. 4.48 and Rs. 3.99 per unit respectively, while the average domestic and agricultural tariff realisations are Rs.1.80 and Rs.0.46 per unit respectively⁶. These tariff levels have to be seen in the backdrop of tariffs paid to DPC. As against a maximum tariff of Rs.4.63 per unit charged by MSEB, the average rate of payment to DPC during May 1999 to December 2000 \yas Rs.4.67 per unit, while, in certain months, DPC tariff cost as much as Rs.8.04 per unit. The high per unit charges of DPC were due to abnormally high fixed charges that are payable regardless of the energy purchased, and was further compounded by a sharp rise in the price of naphtha.

Until 1999, the gap between the average cost of supply and the average realisation (hereafter referred to as the gap) was limited, even though the growth in average realisation had not kept pace with the cost of supply on a year-to-year basis as seen below in Table 2c. Since 1995-96, the subsidy claim actually decreased from Rs. 630 crore in 1995-96 to Rs. 355 crore in 1998-99, until in 1999-2000, it increased nearly five-fold to Rs. 2084 crore due to the sudden increase in the gap by 26 paise per unit, from 15 paise to 41 paise, an increase of 1737o. This increase in the gap was due to a fall in the average realisation by 3 paise per unit and a rise in the average cost of supply by 23 paise per unit.

The increase in the cost of supply is also reflected in the major change in the composition of expenditure over 1995-2000. The share of power purchase costs as a percentage of total expenditure has increased from 30% to 38%, and the share of fuel expenses, incurred due to generation by MSEB plants, has declined from 34% to' 29%. The power purchase cost, which had gradually risen from Rs. 2050 crore in 1995-96 to Rs. 2834 crore in 1998-99. jumped sharply in 1999-2000 by Rs. 1543 crore to Rs. 4377 crore. The billing by DPC, after the commissioning of Phase I, was Rs. 1617 crore. In addition, in order to absorb this power,

MSEB reduced the purchase of lower cost power from TEC, NTPC and other sources. These costs will go up steeply with the commissioning of Phase n from June 2001, as shown below in Table 2d, which shows monthly payments to DPC. The inclusion of energy payments is consequent to the Take-or-Pay (ToP) Gas Supply Agreement, which is explained later in the Report in Section 7.2.6.

The other main increase in expenses has been on account of interest on borrowings, though its share of expenditure has not changed. Borrow ings have increased froni Rs. 3247 crore in 1995-96 to Rs. 6493 croi-e in 1999-2000. Other costs have so far contributed little" to MSEB's precarious financial position. Salary and wages and O&M (Operation and Maintenance) expenses actually grew more slowly than the growth of overall expenditure, at 11.2% and 9.5% per year respectively as compared to 15.12% per year for overal I expenditure.

The impact of DPC on the increase in the overall costs incurred by MSEB is self-evident. The increase in the subsidy claim by Rs. 1729 crore, from Rs. 355 crore to Rs. 2084 crore is substantially due to the increase in the gap, which as was noted earlier, was principally due to the increase in power purchase costs. Table 2e attempts to show this by decomposing the increase in subsidy into its two principal components, viz., the increase in subsidised consumption and increase in the subsidy per unit, i.e., the gap. The expenditure on power purchased from DPC, i.e., 3,871 MU. was Rs. 1,617 crore. If this had been purchased at the average cost of-non-DPC supply of Rs. 1.90 per unit (which could be an unreasonable supposition as there may not have been any power available at that price), the expenditure would have been Rs. 736 crore. In addition, apart from the increase in power purchase costs due to the purchase of DPC power, a portion of the increase in interest costs is also on account of DPC. as a result of debt incurred by MSEB in order to invest Rs. S63 crore in DPC through MPDCL over 1998-99 and 1999-2000. as discussed later in Section 5.4.4.

table 2E: analysis OF increase IN subsidy claim (rs. crore)

Total Increase in Subsidy

Increase Attributable to Rise in Consumption

Increase Attributable to Increase in Gap

Other

Effects

1729

379

1411

-61

Note: The increase in subsidy due to increase in consumption is measured as the old subsidy times the increase in consumption and the increase due to the gap is measured as the increase in gap times old consumption.

The estimated T&D loss, a critical performance parameter, has apparently risen sharply from 17.48% in 1992-93 to 30.56% in, 1999-2000. However, this sudden jump is consequent to the establishment of the MERC, which has made previously misallocated losses more transparent. The increase therefore only serves to reinforce the extent of previous misallocation of commercial losses as unmetered agricultural consumption. The Committee attempted to control for this using 1999-2000 estimates of consumption per irrigation pump (IP) set⁹. Interpolating these estimates for previous years using the estimated number of IP sets, an adjusted T&D loss can be estimated, as in Table 2f below. The actual level of losses would have been still higher had the 2000-01 estimates of consumption per IP set been used. As can be seen. this high level T&D loss. which is estimated as 38.82 % in 2000-01. is a persistent phenomenon and not a sudden deterioration. This is a matter of .grave concern for the Committee and will be discussed in greater detail in Part II of the Report.

It is, however, important to note that the distorted tariff structure is responsible, in no small measure, to such unsustainable T&D losses. The high tariff for H.T. industrial and commercial consumers encourage increased captive generation and theft of power. On the other hand, cheap supply of power to some sections fosters profligacy, which MSEB can ill afford. Physical policing can never be an effective substitute for correct pricing policy. Concerted action is needed to give correct price signals and do away with these distortions. With the setting up of an independent regulator and the requirement of MSEB to file the tariff application before the regulator, MSEB's performance in these areas is now under scrutiny. To this end, it has undertaken a number of steps. While there is substantial scope for improvement, most of these benefits will be realised only in the medium term.

Subsequent to the commissioning of DPC Phase I, the financial deterioration of MSEB has been rapid. While MSEB was in profit in FY 1998-99, it plunged into huge losses (excluding subsidy) of Rs.1681 crore in FY 1999-2000. In FY 2001-02. the uncovered gap, at existing tariff, is estimated to be as large as Rs.3761 crore. Given the rapidly growing cost of power purchase, slowdown in HT consumption, which actually declined by 3.S7f over 1999-2000 to 2000-01. and increasing levels of receivables, the cash available to MSEB to pay its creditors and suppliers has been affected. The Board is now under a severe cash crunch and has defaulted on several of its creditors including DPC during the past year. The dues payable on the revenue account, which were Rs. 2088 crore in 1995-96. have increased to Rs-4245 crore in 1999-2000. The banks that are in the consortium for financing MSEB today view it as a potential "non-performing asset (NPA)" and want to reduce their existing exposure. They are also not interested in enhancing further fund-based and non fund-based limits. One bank has stopped further disbursement of a sanctioned loan for Khaperkheda III and IV power generation projects. Small-scale industries, which supply materials to MSEB, have asked for interest on delayed payments. The prices quoted by suppliers have increased as suppliers load their interest cost while quoting their rates to MSEB.

One consequence of delay in payment to central sector entities such as NTPC, Coal India and Railways is a cut in Central Assistance to State Government by the Central Government.¹⁰This has become an even more immediate prospect with the constitution of an Expert Group to restructure the existing dues of the SEBs, whereby the Gol has expressed firm intention to conduct future transactions on a fully commercial footing. Penalties for delayed payment could be much more severe than what exist today, extending to reduction of power supplies.

MSEB is in serious financial distress. As shown in Box-1, this cannot be remedied even by an overnight reduction in MSEB's T&D Loss by 10,000 MU. i.e., a reduction to 14%". Therefore, while it is true that MSEB's performance on the T&D loss reduction front leaves much to be desired, and the Committee intends to address this issue in full in Part II of the Report, this under-performance is not in itself responsible for the current problems with DPC. which are much more related to the tariff and size of the project itself. With DPC and its own problems of T&D Loss and receivables, MSEB is in a financial crisis. Without DPC and without its problems of T&D Loss and receivables, MSEB could be financially healthv. But even if DPC. especially Phase II, were to be attached to a MSEB without any problems of T&D Loss. it would still manage to drag MSEB back down into financial sickness.

What happens if MSEB actually hu\-. all the Phase II power? Can it really afford it if the realizations arc rationalized and losses are reduced? To understand this. it is useful to do two simple exercises, each of which has ihree parts. In the first par! of the first exercise, all of MSEB's power purchase is from DPC at the relatively reasonable rate of Rs. 4.10 per unit (as submitted by DPC to the Committee), but realisations for existing consumers (grouped into four broad groups of HT and Commercial consumers. Bulk Supply Consumers. Agricultural Consumers and Domestic and Other consumers) remain at current levels. This leads to a deficit of Rs. 4293 crore. In the second part, agricultural realisations are increased to Rs. 1.00 per unit and domestic realisations are adjusted so that MSEB's expenses are fully met (without any return). This implies a raise in average domestic realisation of 193% to Rs. 5.27 per unit from the current realisation of Rs. 1.80 per unit. Finally, in the third part, we ask what if there is an overnight conversion of 10.000 MU of commercial losses into paying consumers (at an average realisation of Rs.2.75). i.e. an overnight additional revenue of Rs. 2750 crore? Domestic realisations would still have to be increased by 58%. So, the problem therefore is not just that of high commercial losses, though it is a major problem. Even if the losses were fixed in the manner above, there would remain a deficit of Rs. 1543 crore. The problem is that there is not enough demand to absorb this power.

In the second part of this exercise, we project an overnight increase in demand of 13,350 MU, equal to DPC Phase II, which is distributed evenly across all non-agricultural consumers, implying an overnight increase in consumption of 36%-. If realisations stay at existing levels, this decreases the deficit to Rs. 3273 crore. In the second part. agricultural realisations are again increased to Rs. 1.00 per unit and domestic realisations a'-e adjusted so that MSEB's expenses are fully met (without any return as before). This implies a lower raise of 1 17% in average domestic tariffs. In the third part, as before there is an overnight conversion of 10,000 MU of commercial losses into paying consumers, i.e. an ove.-night additional revenue of Rs. 2750 crore In this case, finally, domestic realisations do not have to be increased.

This implies that if HT and Commercial realisations remain at their current excessively high levels, agricultural realisations rise to Re. 1.00 per unit. i.e.. double the existing tariff, and

10.000 MU of commercial losses is converted into paving consumption at an average realisation of Rs. 2.75. non-agricultural consumption rises by 36% and agricultural

consumption does not grow then it is possible for DPC to be absorbed without any increase in domestic realisations. However, even this fairy tale is too good to last. As time goes on, DPC tariff will rise and if it were Rs. 4.50 instead of Rs. 4.10, then domestic realisations would have to be increased by 26%.

This chapter looks at the growth in demand for power in the State and the sequence of capacity additions over the last ten years, broadly since the time that the Dabhol project was conceived. The object of this exercise is to obtain a better understanding of the type of capacity addition that is required at this time. It does not, in particular, deal with submissions made by MSEB regarding demand at various points of time in the context of DPC, which will be examined later, in Chapter 6.

Demand growth has been much lower than forecast (Chart 1 shows the change in various EPS forecasts) and, more importantly, it has been quite uneven across different categories. In particular, the growth in the metered HT Industrial category, which is the largest high-tariff group, has been very limited, while agriculture, one of the low-tariff categories, has grown steadily, but perhaps by not as much as originally stated, as a large proportion of commercial losses were misallocated as agricultural consumption. Domestic and commercial consumption has grown the most and this has implications on the load profile of the State. An examination of the load curve for Maharashtra (see Chart 2) reveals around 8000 MW of base load, about 2250 MW of intermediate load that persists for about 15 hours and another 2000 MW of evening peak load that lasts for about five hours. This may change as the share of peaking consumers such as domestic and commercial consumption increase over time. Compared to this load profile, the capacity available is largely base load, where the State would actually appear to be surplus. In addition, its limited intermediate and peaking facilities, such as Uran and Koyna suffer from fuel and water availability respectively. Unfortunately, the capacity addition planned for the State, especially through IPPs viz. CIPCO and RPPL, even apart from DPC, seems ill suited to meet either intermediate or peak load. Indeed both the IPPs have also been contracted for very high PLFs (Plant Load Factor), indicating their position as base load plants. The possibility of absorbing a high level of base load is remote, especially since the growth may be low in base load but relatively higher in peak load. While CIPCO is a pithead coal plant, which may be difficult to reconfigure, RPPL could in principle, at least be reconfigured as a load-following facility. A plant such as Dabhol, described as a base load plant, and RPPL would, in an efficiently run system, be used to meet intermediate and peak loads and therefore have a lower PLF, even if it has higher availability (see Box 2).

What is the relationship between the types of demand, i.e., base load, intermediate load and peak load and the plant load factor? Can a plant needed to meet intermediate load ever have 90% PLF? The answer is NO. In order to understand why. consider the generic depiction of a load curve for Maharashtra, where the base load demand, i.e.. OG is around 8000 MW, intermediate load, i.e., GM, is about 2250 MW for about 15 hours, i.e., BE. from 7 am to 10 pm and the peak demand, MS, is 2000 MW for 5 hours, i.e., CD- from 4 pm to 9 pm. In this depiction, the share of different loads would be as shown in the Table below. This corresponds roughly with the actual share in the state (actual base load demand would be lower as it would fall off further during night).

to meet the base load demand, plants have to be running 24 hours a day, 365 days a year. These are usually coal-fired plants that take a relatively long time to change their load and are relatively inefficient if they are used at partial loads (i.e., if a 500 MW plant is used to generate 300 MW). Such plants run whenever they are available and if they are available more than 90% of the time (which is not usually the case for coal fired plants), they can achieve 90% PLF.

The peak load is usually attributed to evening commercial and domestic demand and is usually met from hydro resources. The PLF for such plants will be quite low, e.g., around 20%, if they meet only the peak load. However, since they usually also meet some intermediate load. actual PLF is higher.

The additional intermediate load comes from commercial and industrial load (industries that do not work three shifts, i.e., close down at night). Load-following plants that can alter the level of their energy output relatively easily, such as gas-fired plants and hydroelectric plants, usually meet this load. Note that a plant that meets this type of load would be utilised at full capacity for only 15 out of 24 hours in a day. i.e.. 62.5^ of the time. However, since the plant will be unavailable for

maintenance for some period of time. its actual PLF will be even lower. Such a plant may however generate a lower level of energy during off-peak hours, i.e., between 10 pm and 7 am, or substitute for a base load plant during maintenance or forced outages and increase its PLF. but it is unlikely to exceed 70%. A plant contracted to meet this load should therefore not be a-sured a PLF higher than 60%. If there are fixed charges, it should be assumed that such charges wouij be recovered over thislower level of energy output and the tariff per unit should be calculated accordingly.

The consumption of energy in the MSEB system at 41,982 MU during 1999-2000 is the highest among SEBs- If one adds 18,478 MU of technical and commercial losses, the gross energy consumption rises to 60,460 MU. This gross energy requirement has increased at a CAGR of about 5% p.a. during the period 1995-2000, which is slower than the all India average of 5.1% from 1995-1999, largely due to poor growth in the industrial sector.

A consumer category-wise analysis for MSEB, provided in Table 3a below, shows that in (FY) 1999-00, industrial HT consumers form the biggest segment, consuming 39% of the total energy. Adjusted Agriculture is the next biggest segment with a consumption of 24.5% (in 2000, agriculture and adjusted agriculture are the same). The other major categories are domestic (15.4%), bulk supply to licensees (8.5%) and commercial (3.3%). In this period, while domestic consumption rose over by 9.9% per year and (adjusted) agriculture rose steadily by 4.4%, HT industrial rose only by about 2.9% p.a., and that too mostly in 1999-2000. Commercial consumption did grow significantly but it still forms only a small share. Thus, low tariff consumer categories have grown, while the higher tariff categories have not.

It is useful to contract. this trend. with the past projections of MSEB. which had estimated that the demand of electricity would grow at 8% and the peak load demand by 1.000 MW every year.

Even The CEA (l5th Electric Power Survey) which had estimated the peak load demand for Maharashtra at the end of 9th Five-year Plan, i.e. 2001-02 to be about 13,147 MW and 18.300 MW by 2006-07, subsequently revised in the 16^th EPS to 12,472 MW by 2001-02 and 14.906 MW by 2006-07. Chart 1 provides a graphical depiction of these projections, along with actual demand. Table 3b below shows energy demand and peak demand in Maharashtra.

The load profile for the MSEB system, for the day (November 21. 2000) on which the highest

demand was registered in the MSEB system, is given in Chart 3. The peak demand registered during the day was 10,473 MW. This load was fully met. A careful analysis of the load profile indicates a base load of about 6,700 MW, and intermediate and peak load of 1500 MW each. The intermediate load persists for 15 hours while peak load lasts only for 4 hours.

In addition to MSEB demand, there is substantial demand from the licensees in Maharashtra, who serve its major urban centres. The load profile of Maharashtra is given in Chart 2 for the same day as MSEB. The licensees add between 1500 MW to 2000 MW over the day without significantly affecting the load profile, though the peak demand does appear to persist a little longer, for about five hours. Maharashtra thus has about 7800 MW of base load, about 2250 MW of intermediate load that persists for about 15 hours and another 2000 MW of evening peak load. An examination of the residual load profile for Mumbai also shows a sharp two-hour dip in the evening, where it can provide some relief to MSEB during peak hours.

Maharashtra planned to increase the installed capacity in the state (including licensees). which was 11.582 MW in 1994-95. to 17,050 MW by 2002 and 21:161 MW by 2005, an increase of over 9000 MW. As against this, actual capacity today stands at 14,672 MW¹². The mix is given below in Table 3c. Chart 4 overlays this capacity mix on the load profile of the state assuming average capacity factors. As stated earlier, this load was fully met. The over supply of base load capacity and the relative shortage of intermediate load and peak capacity is quite evident. Unfortunately, it is precisely in these areas that MSEB has binding operational limitations with respect to its gas and. hydro plants. The additions to capacity in Maharashtra therefore need to be evaluated based on whether they have the potential to ** alleviate this shortage of capacity to meet intermediate and peak load demands. Furthermore, as seen in Box 2. it should be reiterated that if capacity were being contracted for these loads, the expected PLF of these plants would be much lower than 90%. and may not even exceed 70%.

Several power projects are under development. Of these. DPC Phase II. Koyna (hydro) and Khaperkeda (coal) of MSEB and Vindhyachal of NTPC arc under construction. Their aggregate capacity is 2434 MW, of which DPC alone is 1444 M\V, and are all expected to be commissioned before 2003. In addition, there are two IPPs, viz.. Central India Power Co. Ltd. (CIPCO) at Bhadravati and Reliance Patalganga Power Pvl. Ltd. (RPPL) at Patalganga and other captive cogeneration and liquid fuel projects. The seven liquid fuel projects aggregating 1219 MW were meant for MIDC areas and were awarded on an international competitive bidding basis. MSEB has also granted No-Objection Certificates (NOCs) for 233 captive and non-conventional projects aggregating 2411 MW, of which 117 projects with a capacity of 842 MW have been commissioned.

CIPCO, one of the original 8 'fast-track' counter-guarantee projects, is proposed as a 1082 MW coal based power plant near the Baranj mines. Following a MoU between the Ispat group, Alstom, USA (then known as GEC Alstom) and Electricite de France (EdF), Lspat entered into a MoU with MSEB in 1993 for setting up the power plant and GoM approved the project in January 1996. The PPA with MSEB was signed in August 1998 along with the counter guarantee agreement. MSEB has undertaken to purchase the power generated by the plant at 87% PLF. CIPCO expects to take 43 months to complete the project. RPPL, promoted by Reliance Industries Ltd. (RIL), is proposed to be a 447 MW plant fuelled by liquid fuel/naphtha/natural gas. MSEB's obligation is to purchase power at 90% PLF''\ The project was originally supposed to be located at Nagothane. The project was awarded in December 1994 to RIL, after a process of evaluating bids that took about 4 years and in January 1995, RIL requested for a change of location from Nagothane to Patalganga on the grounds of availability of land and shorter completion time. This was granted in October 1995. RPPL expects to come on line 27 months after financial closure.

Based on the discussion above it is clear that. as structured, neither of the two IPPs would be able to match the load requirements of Maharashtra. as both are structured as base load plants, with high PLF. The other projects will be considered in Part II of the Report.

This chapter provides brief details about DPC, with an accompanying chronology of events. As can be seen, the project is not just a power project, but a complex intermeshing of power, LNG supply, shipping and port projects put together. The other projects can have value independent of the power project.The nature of the project has changed over time, as it has proceeded from the MoU stage to the implementation of Phase II of the project, with a take or pay LNG commitment. With few exceptions, as is pointed out here: the changes have been to the detriment of MSEB. As the chronology of the project makes clear, a number of critical decisions appear to have been taken without full consideration of the issues involved.

In 1992-93, the financial position of Gol, especially relating to foreign exchange reserves, was precarious and it took a deliberate decision to attract foreign private investment in the power sector in the country. For this, a high level delegation consisting of Gol officers, headed by the Cabinet Secretary and including the Secretaries of Power and Finance, along with representatives of the Tate Group and Calcutta Electric Supply Corporation (CESC) visited Europe and USA and held several meetings with potential investors. Enron was one of the parties who had met the above delegation and expressed an interest in investing in India. The Gol suggested the name of Enron Corporation to GoM, and took active interest in the signing of the initial MoU. In the course of negotiations that took place thereafter, several high level meetings both at the Gol and State Government level were held to finalize steps to be taken in a largely uncharted area, as shown in the list of events associated with the project, given in Annex 5. The GoM appointed a Task Force consisting of Secretaries of various Departments and headed by the Chief Secretary, to discuss the project at every step and also took the help of international consultants. Decisions with respect to foreign exchange clearances and tariff deviations and statutory clearances were referred to the Gol and the Foreign Investment Promotion Board (FIPB) as required under law. One major support provided by Gol was the counter-guarantee, which was initially granted on September 15, 1994 and then subsequently renewed on May 28. 1996, on the last day of the brief 13-day tenure of the then Government since changes in the PPA needed revalidation of the counter guarantee without which the financial institutions were not willing to revive Phase I financing agreements. The then government justified the extension of the counter guarantee as resulting in avoiding delay costs of $ 25,000 per day (approximately Rs.43 crore per year at today's exchange rates)¹⁴. It bears noting that in the initial MoU with DPC, it was explicitly stated:

"even- effort will be made to avoid guarantees from Government of India to lender”.

The Dabhol Power Company (DPC) is a private unlimited liability company incorporated in India as an Independent Power Producer (IPP) to establish a combined cycle gas / naphtha / distillate fired power plant of 2184 M\V capacity in two phases. Its shareholders are Enron Corp., USA (Enron), Bechtel Enterprises Inc.. USA (Bechtel) and General Electric Company, USA (GE) and MSEB. DPC has entered into a Power Purchase Agreement (PPA) with MSEB for sale of power on Build, Own and Operate basis (BOO) for a period of 20 years. The project is to be fuelled by Liquefied Natural Gas (LNG), imported from Oman. in specialised vessels. The LNG is then unloaded at Dabhol port, and then re-gasified for use at the Re-gasification facility, all of which was to be built by DPC. However, each of these projects can potentially stand on their ow n. Thus, at the outset, it would be useful to separate the "project" into its distinct components, not counting the community facilities, each of which can be said to be a project in itself. Indeed, there is a separate tariff line for recovering the fixed cost associated with each of them,- i.e., a Capital Recovery charge for the power plant, a Re-gasification charge for the re-gasification facility and a Shipping and Harbour Charge for recovering the costs of the shipping charter and the marine facilities.

The power plant itself has two phases. The first phase of the power plant comprises a 695 MW plant fuelled by naphtha or distillate, with an additional peaking capacity of 45 MW, i.e., a total capacity of 740 MW. This was commissioned in May 1999. As part of Phase IL currently under construction, DPC is presently increasing the power generating capacity from 740 MW to 2184 MW (including a peaking capacity of 34 MW). by addition of two power blocks with an aggregate net capacity of 1,444 MW. After completion of Phase II, the entire power plant would be capable of running on liquefied natural gas (LNG) as well as liquid fuels like naphtha and distillate. This project can potentially (a'l lOO^r PLF) generate 19132 MU of energy. In December 1995, as part of agreements reached with the Negotiating Group (which is discussed in the following chapter). DPC agreed to reduce the capital cost of power plant project to $ 2,007 million as confirmed in their letter to MSEB dated April 8. 1996.

LNG needs, to be vaporised (re-gasified) into natural gas before firing in the gas turbines. Phase II thus includes the construction of a LNG re-gasification facility, i.e., fuel unloading terminal, 3 specially designed LNG storage tanks and the LNG vaporisers. The facility will have the capacity to process 5 million metric tonnes of LNG, of which approximately 2.1 million will be used to meet the power project's requirements for natural gas.

The marine facilities include a LNG jetty, dredging of an approach channel and turning basin for the LNG tankers, berthing at the jetty and the construction of a breakwater. The cost of setting up the Re-gasification and Marine facilities was stated by DPC to be USS 494 million in the letter referred to above.

DPC also has a separate 20-year shipping time charter with Mitsui O.S.K. Lines, Japan for LNG transportation, which involves chartering the use of the LNG tanker, S.S. Laxmi, dedicated to DPC, which costs approximately $ 98,000 per day. Recent news reports of bids for the charter of a similar ship by Petronet LNG indicate a price of about $70,000 per day.

DPC has long-term fuel supply agreements with Oman LNG and Abu Dhabi Gas Liquefaction Co. Ltd. (ADGAS), for 1.6 million tonnes and 0.5 million tonnes (a total of 2.1 million tonnes), with take or pay commitments of 90% and 75^ respectively. These contractual obligations were passed through lo MSEB. transferring the responsibility for paying for approximately 1.8 million tonnes of LNG even if it is not consumed. The 1.8 million tonnes represents the take or pay commitment associated with the two LNG contracts.

Apart from the power plant, all the LNG related facilities have significant alternative uses. Th'.' re-gasification facility is for 5 mmtpa of LNG whereas the power plant would require only 2.1 mmtpa of LNG. Although the power project will consume only 40% of the output of the facility and that too only if it is dispatched at 73% PLF, the entire cost of the LNG facility is loaded on the power project (This will become clear in the next Chapter). If there were a separate special purpose vehicle (SPV) for the purpose, this facility could be marketed to other buyers of gas, distinct from the power project. That such buyers exist is demonstrated by Enron's own MetGas initiative and by Petronet LNG's project plans. Of course, the fact that the facility is fully paid for does diminish the urge to market it to other users. Similarly, the harbour facility can also be used as a common facility, by other importers of LNG, as its capacity is well above what can be used by the power plant. The shipping charter too is not linked inflexibly to the project. The charter can be used for transportation of LNG in the spot market, in case deliveries required for the power plant are reduced. Even with respect to the LNG contract, the current market conditions for spot LNG make it possible to trade LNG on the spot market particularly keeping in view the involvement of Enron in world LNG markets. Therefore, currently, there is scope for a more flexible use of the facilities.

Indeed, the LNG related facilities were not always integrated with the power plant. At the start of discussions relating to the project, the MoU between MSEB / GoM and Enron envisaged a separate fuel facility. The letter from Gol to DPC dated February 3, 1993 conveying its approval for the project also specifies that the project would be implemented by two separate businesses - power plant venture and a fuel supply venture. However, the CEA clearance was obtained for a combined project. The Negotiating Group insisted on separating it, and D.PC agreed to de-link the LNG related facilities from the power project. However, when CEA informed DPC that de-linking LNG facility from the power project was a major modification and as such the power project would have to be re-examined by the CEA, MSEB and DPC agreed to retain the LNG facility within the project. Apart from this alteration, there were many other changes in the project structure, as it evolved, which are detailed in Table 4a. A schematic representation of action taken by the various Gol and GoM agencies in regard to the DPC project is highlighted in Table 4b.

This chapter examines the report of the Negotiating Group, which restructured the project in November 1995, and the extent to which its recommendations were implemented, when the contracts were actually renegotiated.

The committee finds that the Renegotiating Group made several recommendations that would result in reducing the cost of Dabhol power to the consumer. These include removal of the escalation clause in the tariff, limiting the foreign exchange risk, limiting the fuel off take risk and the allocation of the " standstill costs ". While some of these recommendations have been adopted, there are some that have not been followed through. The committee also felt that the Group might have been misinformed as to the impact of these recommendations on the tariff, given the manner in which the contracts were restructured and submissions were made to the Group. In addition, some of the implications of this restructuring are also not reflected in the submissions by the MSEB later on in the process of clearances for Phase II, which are discussed later in Chapter 6.

The non-availability of any details regarding the negotiation process, which are limited to the "Suinman' Report of the Negotiating Group" (hereafter the Summary Report), makes it difficult to explore the rationale of their suggestions in greater detail. It is a matter of some concern that deliberations that formed the basis for a decision by the GoM to support a project that was potentially a liability for the State to the extent of around Rs. 6000 crore a year (at today's exchange rates) should be recorded in so summary a fashion. Be that as it may, the net impact of the negotiation process, whether or not the Group desired it in that manner, was to proceed onward to developing Phase n, viz., a 2184 MW LNG fired station, contractually (though not necessarily technically) designed for base load operations, with a take-or-pay LNG and fixed capacity charges liability.

It is this project that confronts us today. The chapter concludes with a brief description of the developments in DPC since Phase I was commissioned in May of 1999. The actual tariff and outgo is contrasted with the projections made in the 'Summary Report'. This provides caution to decision-makers that seek to proceed without a thorough analysis of the consequences under different scenarios.

Subsequent to DPC and Government of Maharashtra agreeing to renegotiate the project, the Government of Maharashtra constituted a Negotiating Group in November 1995 to hold discussions with DPC for the revival of the Dabhol Phase I and II project. The renegotiating committee comprised Mr. N. Tata Rao, former Chairman of Andhra Pradesh State Electricity Board, Mr. S.V. S. Raghavan, former Chairman of Bharat Heavy Electricals Ltd., Dr. Kirit Parikh, Director of Indira Gandhi Institute for Development Research, Mr. T.N.V. Ayyar, financial consultant, Mr. M.P. Pinto, Chairman, MSEB and Mr. Asoke Basak, Secretary, Industries, Energy and Labour Department, Government of Maharashtra.

The GoM constituted this Group through their Resolution No. DPC 1095/CR/2760/NRG 2 dated November 8, 1995 (a copy of the resolution is attached at Annex 6, where it set out the terms of reference for the Group as follows:

The Group was to negotiate with DPC and submit its report to GoM by December 7, 1995. It was actually able to submit its report much earlier, on November 19, 1995 i.e. within eleven days of its constitution.

At the conclusion of deliberations, the Group recommended the following, all of which were agreed to by DPC.

The original cost of the entire project comprising both Phase I and II'was indicated to the Group at US$ 2.83 billion¹⁵. The Group considered the cost of Phase I, which was stated as US S 919.8 million, to be high. DPC also admitted that equipment cost had since declined considerably. Consequently, the Group recommended:

a) Reduction in the cost by US$ 330 million. This reduced the overall cost of the project, including Phase I and II, to US$ 2501 million.

b) Reconfiguration of the plant and an increase in gross (net) output by 201 (169) MW.

DPC also agreed to global competitive bidding of the equipment in Phase II, to be jointly evaluated by DPC and MSEB and to make appropriate adjustments to the tariff for any significant reduction in project cost of Phase II.

It is important to realise that given the manner in which DPC's tariff is structured, a reduction in capital cost has per se, no effect on the tariff and therefore affords no benefit to MSEB. The increase in capacity is mostly due to a design change in the gas turbine¹⁶. This additional MW output did not lead to any significant additional cost to DPC. The Group however considered this a "net benefif, as a "saving in additional capital investment/or additional capacity", which was valued at US$ 253 million.

This is very surprising; as the appropriate interpretation is surely that the initial cost was inefficiently high and therefore overstated. Furthermore, contrary to the impression conveyed, this came at a significant cost to MSEB. since it increased the total fixed charges to be paid by MSEB by about Rs. 250 crore per year at today's prices (about Rs. 170 crore per year at the exchange rate of Rs. 32 to the dollar), i.e., the extra payment that needed to be made as a result of the increased generation from the additional capacity, as shown in Box 4.

This is charge, generate cents, ar x 1000 prescrib entire a renegoti amount present ^

While DPC reduced the amount of capital recovery per unit compared to the original PPA , due to the capital to the removal of the 4% per annum escalation in the capital recovery charge after the onset of Phase II. the increase in plant capacity from 695 to 740 for phase I and 2015 MW to 2184 MW for Phase I & 11 combined increased the financial burden on MSEB due to increased capacity and energy charges

This is because the capital recovery charges for DPC are specified as a fixed lump-sum charge which is determined by multiplying the given per unit charge into energy generated assuming 100% plant load factor. For example, if the capacity 2184 MW, the fixed lump-sum charge would be ( 3c * 2184 * 8760 *1000 / 100) dollars. If the plant's performance is acceptable ie. , it is available at the fixed percentage (86% in monsoon months and 92% in other months) It Receives this entire amount regardless of the actual energy generated. Since as part of the negociation there was increase in the plant capacity from 2015 MW to 2184 MW, this amount increased. The table below gives the effect of these changes by clacualting the net present value of the capacity charge for different discount rates.

As to global competitive bidding, the process was followed only for major equipment and DPC achieved a reduction in cost compared to budget estimates to the extent of about US$ 30 million . It was not followed for other construction contracts and the share of costs that were finally awarded through competitive bidding was less than half, limited to 47.5%.

As to the reduced capital cost of US $ 2501 million, while it was agreed to and was the basis for the reduction in tariff referred to in the next section, and is mentioned in a letter from DPC to MSEB dated April 8, 1996, the subsequent tariff submissions from MSEB and CEA to the Government of India continue to mention the project cost as USS 2828 million. This is not an insignificant error, as the higher project cost increases the normative tariff as per the Gol notification dated March 30. 1992. and helps to show that DPC has a lower tariff by comparison. Thi'.-, is discussed more fully in section 6.4.3.

Based on the reduction of the capital cost of US $ 330 million referred to above, and other changes, such as reconfiguration of the plant to increase capacity and the inclusion of a multi-fuel facility, which are referred to below, the Group recommended:

c) Removal of the 4% escalation in the capital recovery charge from the date of commissioning of Phase II of the project. The present value of this saving in the capacity charge that the consumers would have to pay over the next 20 years would reflect the reduction in capital cost of the project'¹⁹

Based on this the DPC agreed to a levelised tariff of Rs. 1.89 per unit at Rs. 32 to the dollar. at a fuel price (FOB) of US $ 1.95 /mmbtu (million British Thermal Units),j.e., equivalent to a price of $13 per barrel of oil, and at a plant load factor of 90%, i.e., a fixed tariff in dollar terms in terms of the capacity charge. This levelised tariff was compared to the pre-re-negotiation tariff and the levelised two-part tariff under the Gol notification at a discount rate of 17% per annum, which was calculated to equal to Rs. 2.60 per unit and Rs.2.05 per unit respectively²⁰. Note that the Group appears to have found that the pre-negotiated DPC tariff was higher than the Gol tariff, even though it had been earlier shown to be lower as discussed in section 6.4.2.

The Group's recommendations did change the tariff profile considerably as seen in Chart 5. which provides a comparison of the tariff profile before and after the Group's recommendations. As can be seen, the tariff before the negotiation was extremely high. Indeed as the Comptroller and Auditor General of India (CAG) aptly remarked, in its Report for the fiscal year (FY) 1995-96. the escalation should not have been agreed to in the first place. Furthermore, the Group, in its statements regarding the levelised tariff neglected the impact of two very major changes that could have been reasonably expected by any party, viz., depreciation of the rupee and change in fuel prices even though a number of the elements in the tariff were indexed to the dollar or the fuel price index. The LNG price considered at the time of negotiations was linked to a JCC price (linked to crude oil price) of US $ 13/bbl, which was'near its historic low and an exchange rate ofRs.32 to the dollar when the prevalent exchange rate at the time of negotiation was already at Rs. 36 to the dollar, over 10% higher than what was being assumed by the Group. Even the discount rate was based on a level close to the rupee interest rate, when most of the tariff elements were dollar denominated. Despite this, the Summary Report did not provide any sensitivity analysis for different levels of exchange rate, discount rates, fuel prices, and load factors²¹.

The Group decided that the fuel flexibility needed to be addressed for ensuring plant flexibility, to reduce the dependence of DPC on imported fuel and consequently reduce foreign exchange outflow, and additionally minimise environmental impact, which were additional considerations before the Group. It therefore recommended:

d) Conversion of the plant to multi-fuel at an additional expenditure ofUSS35 million, to be borne by DPC, but not charged to the tariff. This was agreed to by DPC.

e) Use of competitively priced LNG for the project by the year 2000, on terms to be negotiated and approved by MSEB. This recommendation was to be taken together with the recommendation to separate the Gas Facility from the project.

Subsequently, in 1998, two LNG agreements were negotiated; one for 1.6 mmtpa (million metric tonnes per annum) and the other for 0.5 mmtpa. MSEB's terms under the agreement compel it to take or pay for 90% of the first contract and 75% of the second. This has the undesirable outcome of converting energy energy charges into fixed charges, regardless of whether 32

energy is availed of. Given the terse nature of" the Summary Report, it is difficult to determine whether the Group anticipated this outcome. However, it may not have been averse to it and may indeed have encouraged'it, by their recommendation of "the acceptance of a 90% load factor for the entire project" stating "MSEB would now have the advantage of additional energy at the reduced tariff as agreed in the revised offer'. At this load level, there is no additional burden induced by the take or pay LNG supply contract.²². As is evident today, the Group was mistaken in its conclusion regarding the need for additional base load energy for MSEB and the LNG supply contract is now another millstone around MSEB\s fragile neck. The separation of the gas facility is discussed later in this Chapter in Section 5.4.6.1.

In order to reduce the impact of foreign exchange fluctuation on the tariff, the Group made

f)Source fuel indigenously as long as reliable fuel sources are available and utilize indigenous naphtha instead of imported distillate as primary fuel

g) Allow MSEB equity participation in DPC. MSEB would pick up 30% equity in DPC at par value and would be entitled to three nominee directors.

In addition, DPC agreed to maximise the Indian component of the project in Phase II by reconfiguring insurance and if possible placing insurance in India, maximising O&M materials and supplies from Indian suppliers, subject to competitive prices, quality and availability. The estimated overall impact was a reduction in foreign exchange outflow for Phase I of approximately Rs.600 crore per year, due to the change in fuel sourcing and a reduction in foreign equity from 100% to 70%, based on the equity sale to MSEB.

Virtually, none of these expectations were fulfilled. The Group appears to have ignored the fact that the tariff structure of DPC would not automatically take these changes into account. As it happened, the tariff structure of DPC remained almost the same (after accounting for the removal of escalation), with only a marginal reduction in the share of the dollar i.e., the "Real Rupee" component. Further, since the domestic naphtha price was linked to import parity, there was no de-linking of the tariff from the dollar due to the use of indigenous naphtha²³.

Neither was there a significant saving in foreign exchange outflow. If anything, the outgo actually increased. First, subsequent to commencement of commercial operation of Phase I, DPC imported naphtha through Giencore International, as the imported naphtha was cheaper than the indigenous naphtha, which was priced on import parity plus other charges' . Further, since Maharashtra Power Development Corporation Ltd.'s (MPDCL) investment in DPC was in dollars and dollar denominated, there was no change in the dollar linkage for the capital recovery charge. Instead, on this account, there has been to date. Rs. 863 crore of outflow in foreign currency due to investment by MSEB in DPC.

As to the rupee component in the project cost, any increase in rupee cost subsequent to financial close, would not result in corresponding benefit being passed on to MSEB, as,according to the tariff structure in the PPA, even if there were any increase in the domestic component, this would not lead to any reduction in the dollar linkage in the tariff.

In response to concerns about environmental safety of the project, DPC agreed to pay reasonable expenses of increased mobile monitoring by Maharashtra Pollution Control Board (mpcb), pay for cost of two additional stationary environmental monitoring stations, plant a total of 150 hectares of trees, consult with Konkan Agricultural University on plans for planting new trees, composition of green belt, etc., provide for regular monitoring of marine life in the vicinity of the discharge point and reduce the stack height from 98m to 50m commensurate with the change in fuel from distillate to Naphtha. DPC also agreed to form a committee composed of local leaders. The committee would provide directions to DPC on employment to the land losers of the project, construct and equip a vocational/technical training centre, construct and equip a 50 bed hospital, construct and equip a secondary school, provide drinking water to the local community and provide details of compensation provided to MLDC for acquisition of land. Most of these were already agreed to by DPC, as a part of a previous High Court Order²⁶ and the Group was mistaken if it thought that these were new concessions extracted from DPC.

The Group discussed two other important issues,viz., separation of the Fuel Venture and the allocation of cost arising from the suspension of the project.

The Group recommended that the re-gasification terminal be structured as a separate fuel venture resulting in a separation of US$ 494 million from the project cost of the power project. This would be chargeable to the fuel cost. While this would increase the cost of the fuel supply, the capital cost of the power plant would decrease and also part of the re-gasification facility cost could be recovered through sale of gas to third parties. MSEB or its nominees would also be considered by DPC for equity in its separate entity for re-gasification facilities and DPC would be provided a bulk purchase discount as compared to other consumers from the re-gasification facility company. As a consequence, a separate Re-gasification charge of 0.0053 cents (17 paise per unit at an exchange rate of Rs. 32 to the dollar, as shown in Box 4 and Table 5A) was specified.

This was not a new idea. In point of fact, this separation was contemplated at the earliest stages of the agreement by Enron itself, in their original MoU and in the Heads of Terms (which is a working draft for discussion) for the PPA. As shown in Box 4 above, the net present value of the agreed upon Re-gasification charge alone, discounted at the generously high rate of 17%. was equal to $ 494 million, which was admitted to be the entire cost of the LNG facility. However, the re-gasification facility is for 5 mmtpa of LNG whereas the power plant would require only 2.1 mmtpa of LNG. This separation was thus used by DPC to load the entire cost of the re-gasification facility on to the power plant although the power project would consume only around 40% of the output of the facility, even at 90% PLF.

In any event, this separation did not take place. CEA in its letter dated 17th April 1996, noted that as a result of the separation of the gas facility, the "proposed changes in the revived proposal become of major nature necessitating re-appraisal by CEA under Section 29 E of ES Act, I948'\ Faced with this opinion, DPC and MSEB decided not to separate the facility. The amended PPA entered into between DPC and MSEB provides for the recovery of the charges for the re-gasification facility on a fixed basis. Though the charge has been shifted from the capacity charge to the variable charge, it is still recoverable as a fixed charge, rather than being based on the delivered fuel, leading to an additional and disproportionate burden on MSEB. In addition, the LNG supply agreement, as mentioned earlier, also includes a substantial take or pay component. In effect, any intention that the Group may have had of converting payment for the fuel facility into a "pay-as-use' basis was effectively nullified. This was done even though MSEB had confirmed to GoM, on April 8, 1996, for onward transmission to CEA that "fuel charges are payable only for the time for which the power is generated". The LNG supply agreement is obviously not structured in this manner.

As brought out later in Chapter 6, this take or pay component also has major implications for merit order despatch since, if all costs on this account have to be treated as sunk costs, there are no variable costs worth the name. On this novel variable cost merit order, therefore. DPC power becomes the cheapest in the system, next only to hydroelectric power! If this becomes an accepted practice then all power plants will sign long term take or pay contracts with their fuel suppliers so that their plants too have low variable cost!

As pan of the negotiations, DPC also agreed to absorb the estimated US$ 175 million of additional costs incurred as a result of the suspension of the project, in return for MSEB absorbing an additional 45 MW of exportable power from Phase I and 169 MW in the combined Phase I and II.

An inspection of the funding pattern subsequent to Phase II funding shows that the overall debt-equity ratio of the project was 70:30, which implied that the funding for Phase II was at a higher debt equity ratio of 76:24. If indeed Enron absorbed the costs of suspension, the debt equity ratio would have been lower than 70:30 since the entire additional $ 175 mn would have come from equity. Consequently, it can be argued that lenders to Phase II have funded the entire suspension period cost. If the project cost, including the cost of suspension were even assumed to be the higher figure of $ 2,880 mn, and not the lower figure of $ 2501 mn, the equity component would be $811.5 mn. plus $ 175 mn., i.e., $ 986.5 mn. which should give rise to a lower debt-equity ratio of approximately 66:34. instead of 70:30. as is actually the case.

The more interesting story is the recovery from MSEB. As already stated in Section 5.4.1, and shown in Box 4, the net present value of the capital recovery charges from this extra energy of 169 MW amounts to nearly $188 mn. As no major additional investment appears to have been required for the increase in capacity, which was achieved as a result of a design change, the additional capital recovery as a result of this extra energy would absorb the entire cost of US$ 175 million. In addition to paying for the suspension costs, to the extent that MSEB agreed to take 30% equity in the project, it also shared the burden of cost overrun due to the suspension of the work in the project, as is evidenced by the subsequent calls on equity.

The Group's negotiations resulted in one benefit, specifically the removal of the escalation clause in the tariff, which gave rise to an unconscionably high tariff in the first instance. On almost all other parameters such as limiting the foreign exchange risk, the fuel off take risk and the allocation of 'standstill costs', i.e., costs incurred during the suspension of the project), the Group's recommendations proved infructuous. The extent of variation from the Group's assumptions and actuality can be seen from the experience of MSEB since the commissioning of DPC Phase I in May of 1999.

DPC has supplied 6048 million units to the MSEB grid from May 1999 to December 2000. The total tariff payments made by MSEB to DPC during the same time period aggregated Rs.2931 crore, an average of Rs. 4.67 per unit, a far cry from Rs. 1.89 per unit. This has been due to .the violation of three assumptions made by the Negotiating Group, whose adoption in the first instance was itself questionable. First, demand has been lower than anticipated, resulting in low dispatch. Since the capacity charges are payable regardless of energy consumed, the tariff is higher at lower levels of dispatch. Second, the rupee has depreciated consistently and now stands at Rs. 46.7 to the dollar as compared to Rs. 32 assumed by the Group and fuel prices, are significantly above the levels assumed by the Group. The price of oil today is around $ 26 per barrel (and had gone as high as $ 35 per barrel last year) as opposed to $ 13 per barrel assumed by the Group. Consequently- far from having "the advantage of additional energy at the reduced tariff', as S. Venkharamanan, former RBI Governor had pointed out soon after the Summary Report was submitted, it would have been far better to expose the "tariff matrix" over the years, spelling out all the assumptions and explaining the sensitivity of tariffs to changes in exchange rates and raw material costs rather than levelising tariffs. It is not helpful to "delude ourselves with continuing exercises which try to show that "costly" power is cheap. Gimmickry ill liefits the process of global isation.'

As it stands, today, even without Phase II, as agreed to during renegotiations, MSEB has consistently defaulted in payments of bills to DPC since December 1999, as shown in Table 5B above, resulting in the invocation of the State Government and Central Government guarantees" . This has resulted in a sub-investment grade credit rating for Maharashtra, below that of states like Andhra Pradesh, Gujarat, Karnataka, Tamil Nadu, Rajasthan, and Punjab.

The Bombay High Court, in writ petition No. 2416 of 1996 in CITU and Abhay Mehta vs. DPC and others, observed the following regarding the renegotiations of the project in 1995:

"But once it [GoM] decided to revive t1ie project, it acted in the very same manner in which its predecessors in office had done. It forgot all about competitive bidding and transparency. The only transparency it claims is t1ie constitution of the negotiating group. Tile speed with which the negotiating group studied the project, made a proposal for renegotiations which was accepted by Dabhol, and submitted its report is unprecedented. The negotiating group was constituted by the Government of Maharashtra on 8''' November, 1995. It was asked to submit its report to the state government by 7^th December 1995. The committee, we are told, examined the project, collected data on various similar other projects as well as internal bids including data on a similar project executed by Enron in the U.K., field considerable negotiations, settled the terms of revival of the project, got the consent of Enron and Dabhol to the same on 15^th November, 1995, just within a week of its constitution, and submitted its exhaustive report along witl-i data and details to t1ie Government of Maharashtra on 19^thNovember, 1995, just 11 days after its formation, much before the 7^th December, 1995 by winch date it was required to submit the same. The speed at wliicli the whole thing was done lyy the negotiating group is unprecedented. Wliat would stop one to say, as was said by the Chief Minister in the context of the original PPA, "Enron revisited, Enron saw and Enron conquered—much more than it did earlier.""

The Dabhol project has generated a lot of controversy in the past and till the date of the constitution of the Committee, there have been a number of public interest litigations filed against DPC on various counts. Even during the tenure of the Committee, fresh petitions have been admitted and are under consideration of the Bombay High Court. However, none of earlier petitions have found favour with the courts. Even the one case that is still pending before the Supreme Court, has been retained because of the conduct of GoM in first filing an affidavit and then disclaiming it. Whenever the history of public interest litigation is written, this will be recognised as one of the failures of the process. One would presume that with such judicial scrutiny, all the issues in the project would have been examined thoroughly. Unfortunately, as shown in this chapter, this is far from true.

The fault does not lie with the courts, but with an inexcusable failure of governance, some of which is documented here. The case against DPC was argued extensively at least in two major writ petitions before the Bombay High Court. In these two critical cases, viz., the Ramdas Nayak case and the CITU²⁹ case, various Government agencies argued forcefully (in the latter instance, the GoM argued against its own previous affidavit) that DPC was in the public interest; that the contract could not have been awarded through competitive bidding but it was negotiated hard and long in order to obtain a beneficial outcome, that the design and size of the project was appropriate, and that the tariff was competitive and below the norms set by the Government of India and that all these issues had been examined by the appropriate authorities as required under law. The various agencies submitting affidavits and arguments to this effect included GoM, MSEB, Ministry of Power, Gol, and the CEA. In both these cases as also several other cases filed against DPC, the Court did not consider it appropriate to intervene. In the Ramdas Nayak case, the Court observed that, "It is well accepted legal position today that judicial review is not an appeal from a decision but a review of the manner in which the decision was made. It is concerned with reviewing not the merits of the decision but the decision making process itself...The duty of the Court in the case of judicial review is to confine itself to the question of legality; rationality' and propriety of the decision-making process...The function of the Court is to see that lawful authority is not abused; while doing so, it should not arrogate itself the task entrusted to that authority...The Courts should not enter into the merits of Government actions, more so, in 40

economic mailers 'unless the same is unreasonable, and is not in public interest....But at the same time the Courts can certainly examine whether a decision making process was reasonable, rational, not arbitrary and violative of Article 14 of the Constitution." The CoiTimiuee believes that this report brings out these very concerns and shows in no uncertain terms that the decision making process followed in this case violated all these salutary principles, i.e., it was neither "reasonable [nor] rational".

This chapter therefore confines itself to examining the "rationality and propriety'¹'¹ of various decisions made at different times with respect to DPC. The Committee is surprised at the breadth of governance failure, which has occurred across time, across governments and across agencies, right from 1992 till as late as 1999 (as shown in Table 4B in Chapter 4). Organs of government at both the Centre and the State level appear to have been remiss in the discharge of their functions. This Chapter will show that every one of the assertions, relating to the benefits from the project, viz., the effectiveness of negotiations, its design and size, the need for power, and the competitiveness of tariff, for both Phase I and Phase II, have proven to be false and indeed, were based, at the time of the assertions, on extremely questionable assumptions.

The Committee, in the short time allocated to it, is unable to determine reasons for this consistent lapse of governance, but is extremely concerned at it. Two members of the Committee, namely Dr. Godbole and Dr. Sarma felt that, prima facie, the manner in which each and every opportunity was exploited by those favouring the entry of DPC at different points of time, against the interests of MSEB, the interests of the Maharashtra consumer and the people of Maharashtra raises doubts about a concerted effort to exercise undue influence at every stage in this project. There are clear lapses of governance in the whole affair of DPC and the Committee- would be failing in its duty if this were not pointed out. However, to establish that there is collusion and exercise of undue influence in a legally sustainable manner, it would be necessary to elicit documentary and other evidence, examine all those concerned and investigate further to get at the truth in this case. Any investigation to determine the cause of these lapses will require an in-depth probe, recording of evidence on oath, and calling for relevant records pertaining to the project both in the state government as also Government of India and their agencies and organisations in order to fix both administrative and political accountability for the actions. Such a responsibility is more

appropriate for a judicial commission, appointed under the provisions of the Commission of Inquiry Act. They accordingly recommend the establishment of a Commission of Inquiry under a sitting or retired judge of the Supreme Court of India. If a case is made out by such a Commission that there was mala fide in the signing of the PPA or securing clearances. GoM may have to proceed legally under the provisions of the Contract Law to modify and / or rescind the contractual commitments suitably. However, the three other members of the Committee, namely Mr. Deepak S Parekh, Dr. R K Pachauri and Mr. V M Lal were of the view that the terms of reference did not provide the Committee with any reason to suggest a Commission of Inquiry. In respect of the Dabhol Power Project, the terms of reference of the Committee as laid down only required the Committee to evaluate and review the Dabhol Power Project, review any or all of its clearances etc. It is open to the Government of Maharashtra or other authorities to set up a Commission of Inquiry, should they find any reason to justify the establishment of such a Commission. The three members mentioned above also expressed their doubts whether such a Commission of Inquiry would serve any useful purpose, given the need for recording the evidence of a large number of those associated with the decision in MSEB, the Government of Maharashtra, the Government of India, and others, particularly since several of those who were involved have retired and may not be easily available. In addition, these members observed that Commissions of Inquiry in India have rarely completed their task within a reasonable timeframe. Therefore, they felt that such a Commission if established could, in fact, only act as a hurdle in the renegotiation of the project as suggested later by the Committee.

One of the persistent issues with DPC has been the lack of competitive bidding. In this matter the Court ruled that a government had every right to enter into a negotiated agreement, i.e., the nature of contracting procedure was squarely in the domain of public policy and that it was up to the Government to decide which method to choose. The GoM had chosen consciously to enter into negotiations, instead of going by the competitive bidding route and it justified this course of action and insisted that it had conducted intense negotiations before signing the contract. Both the justification and the quality of these negotiations are suspect.

As seen in Box 7 below, on the issue of competitive bidding, it was affirmed (by GoM, through MSEB) that this was not relevant, counter-productive and inappropriate. Perhaps the only accurate statement was that it was not unlawful. For reasons detailed below, the Committee finds each of these reasons to be deficient and suspect.

MSEB in its affidavit in the Ramdas Nayak case cited the following reasons for going through a negotiated route as against a competitive bid route.

1. Competitive bidding procedure has no relevance where a private party chooses to set up a project on its own with its own resources.

2. It would have been "counter productive on the part of Gol, GoM and MSEB to invite [the sponsors] to stand in competition' as they were invited to set up plants in India by Gol and Enron, GE and Bechtel were three major companies in the field of'energy, power equipment manufacture and engineering.

3. A competitive tender in a project like this is most "inappropriate" as competitive bids require preparatory exploration and work which is considerably costly and time consuming particularly in the case of power plants. In the present case there was no preparatory exploration of the type for a plant like the one, which Dabhol Power Company is setting up. Again "the competitive bid requires expert knowledge and experience for evaluating the competitive bids, which at present is still not sufficiently up to the mark. For evaluation of such specialised projects, it is also necessary to have knowledge of risk identification and allocation, which is also not sufficiently developed".

4. There is no law which requires that in every case there should be competitive bidding.

GoM said that the "competitive bidding procedure [was] relevant when the Government or public authority [was] either disposing of or purchasing property or services. It [had] no relevance to cases where a private party chooses to set up a project on its own with its own resources" [affidavit by MSEB in Ramdas Nayak dated 25 July 1994, emphasis added]. This depiction of DPC as an investment with no obligation on either the "Government or public authority" to purchase services was patently in error. The GoM resolution extending a guarantee to DPC, dated 10^th February 1994 (copy at Annex 7), clearly mentions that "As MSEB will purchase power from DPC, it has to execute an agreement namely. Power Purchase Agreement ('PPA)"[emphasis added].

This is a very interesting statement, which suggests that "major companies" should not be asked to compete for projects. The Committee believes that the vacuity of such an argument is self-evident and does not merit further consideration.

This is a surprising statement, for it admits that GoM's "expert knowledge and experience" for evaluating bids is "not sufficiently up to the mark" and its "knowledge of risk identification and allocation...is also not sufficiently developed.'' At the same time, however, GoM argues that it has the expertise, experience and knowledge to negotiate a contract. It is apparent to the Committee that if a body is not qualified to evaluate bids, which are submitted on standard terms, it is evidently less qualified to negotiate minute details of a similar project. This dissonance between the two bodies of knowledge as perceived by GoM is inexplicable. If the argument is that the MSEB had engaged international financial and legal advisers to assist it in its negotiations with DPC, the same could have been done with respect to preparation and evaluation of bid documents.

MSEB, in its affidavit in the Ramdas Nayak case, affirmed that: "protracted negotiations and discussions took place between both the parties during the period August 1992 to December 7993". As a consequence of these negotiations, "at 90% power availability the estimated total tariff in 1997 prices, at an exchange rate of Rs.32/- = $1 and distillate price of $4.3/mmhtu will be Rs. 2.40/k\vIT\ The quality of these "protracted negotiations" can be judged by comparing this rate of 7.5 cents per kWh with 7.3 cents per kWh in the original MoU Term Sheet and more significantly, with the prices "proposed by Enron" two months later in the Power Purchase Agreement: Heads of Terms, Draft 4. dated 29 August 1992 (revised), where the tariff structure was to be designed to achieve an "all-in price to MSEB of 6.91 cents per k\\'H (at 1996 prices) assuming a natural gas cost...of US $ 4.9J/inmbtu'' That is, at the start of negotiations, at a higher assumed fuel price, the all-in cost was lower by nearly 0.6 cents per unit (an annual outgo of over S 100 million). The protracted negotiations seem to have led to an increase in price.³⁰

The power project itself is separated into two components. Phase I and Phase II. It has been argued that Phase I was a desirable project while Phase II is the source of all problems. As originally proposed, DPC was a single 2000-2400 MW project, which was later modified to two phases, taking into account, inter alia, the World Banks concerns about absorption of power. Phase I was structured separately to run on distillate, but still as a base load plant, though the need was clearly for intermediate and peak support. But though the obligation to 20 in for the second phase was removed from the PPA, it was always the intention to go in for Phase II, after confirming the loads (which was finally done on Sept. 1998 as discussed in Section 6.3.2.1), and convert the plant to run on LNG, and move away from an undesirable situation where a 695 MW base load plant is fuelled on distillate since the GoM, at that time, disputed the World Bank's demand projections. It affirmed that: "The apprehension of the World Bank that the MSEB power system would add more capacity than needed was also not accurate in view of the shortage of power in Maharashtra and projected increase in demand" (affidavit filed by MSEB in Ramdas Nayak dated 25 July 1994). MSEB's load projection in this matter was contested by the World Bank, as discussed in Section 6.3.1.

Furthermore, not only did Phase I have a high capital cost: the capital recovery component of its tariff was escalated every year, leading to an unconscionably high tariff. It has been argued that the back-loaded tariff was designed to help MSEB absorb the cost of power. However, in this case the initial tariff should have been lower than what was agreed to. The negotiating room in the tariff is seen from the fact that the Negotiating Group was able to remove the entire escalation without any increase in the initial tariff. If the Negotiating Group had not removed the escalation clause in 1995, the DPC tariff going forward would have been even higher than what it is today, especially if the plant is used to meet intermediate loads, as it should be, and consequently has a load factor lower than 90%. Phase-1 was and is a high-cost base load plant with inappropriate fuel and benefits that are in

no way commensurate with its costs. While the size of the initial plant may have been reasonable, the commercial terms and high PLF were completely unreasonable.

MSEB and the state government averred repeatedly before the Courts that this project was intensively negotiated over a long period of 16 months and best possible terms were obtained from the foreign party, namely, Enron. The very first document signed by MSEB with Enron and GE was the MOU, which was signed within 5 days of their coming to India and within 3 days of coming to Mumbai. The Enron team first arrived in New Delhi on 15 June 1992 and the MOU was signed on 20 June 1992. Though the MOU makes it clear that it is not legally binding on the parties, it sets the tone for future negotiations of the project. Interestingly, all main features of the project have basically remained the same throughout the so-called intensive negotiations that ensued after the signing of the MOU. MSEB agreed, in principle, to a LNG-based project of 2000 MW capacity being put up as a base load station without going into the question of the absorption of this large power in Maharashtra system and the cost implications thereof. It agreed to orders for the plant and equipment being placed on GE without going into the comparative costs thereof and without bothering about the international competitive bidding. The contract was to be denominated in dollars, payable in rupees. The only major difference was that the power venture was to include the power plant but not gas facilities, which were to be owned in a separate fuel venture, to be negotiated -separately. Subsequently, this separation was offered as a concession in the renegotiations of the project in 1995 but later on retained as a part of the project to avoid a fresh clearance from CEA.

As mentioned above, DPC has been designed as a base load project, right from inception. The World Bank in its assessment of the project, in 1993, pointed out that "Dispatching] the plant as a base load unit at 80-85% minimum plant factor ...would prevent the. operational ' flexibility- of a combined cycle plant'. As we have seen earlier in Chapter 3, Maharashtra and MSEB need load-following capacity, not for meeting base load but for peak and intermediate load. The situation was the same in 1993. It appears³¹ that the Planning Commission, at the CEA meeting held to consider the project, also observed that from a "system operation point of view it would perhaps be advantageous to consider setting up of pumped storage schemes in the Western region" and that "The backing down of the existing thermal generation capacity in Maharashtra due to this new capacity addition would imply heavy additional economic costs imposed on the power system of MSEB". Furthermore, it appears that at the same meeting one of the representatives of CEA observed that as "per the studies conducted by CEA, Dabhol CCGT plant was not the least cost option... MSEB had other less costly options such as Kaparkheda Unit 3 & 4 (2x210 MW), Kaparkheda-Unit 5 & 6 (2x250MW), Umred TPS-1000 MW, but these schemes were in the preliminary stages." The Committee would like to point out at this stage that if MSEB had made efforts to seriously pursue these projects, they might not have remained in their "preliminary stages".

Regardless of these apprehensions, the CEA found the technical aspects of the scheme "to be generally in order". GoM went ahead with the project as designed. Even though the execution of Phase-11 was deferred, the Phase I project continued to be considered as base load project, and not as an intermediate load project, as evidenced by the calculation of tariff at 90% PLF. If a lower level of dispatch was contemplated, as would be the case for a project designed to meet intermed''ate loads, the estimated PLF would have been lower and the consequently, the associated tariff would have been higher, since the same fixed costs would have been spread over a smaller base.

The Committee is of the opinion that MSEB and GoM erred seriously, based on information available at that time. in proceeding with DPC as a base load project, even when it's capacity was reduced to 695 MW. It has been argued that there were pending applications for power at that time. The World Bank, in their evaluation, considered this and rejected the argument because it was not demonstrated that the load was additional to normal growth, that consumers were willing to pay a higher price as would be needed for LNG power (indeed, its surveys of willingness to pay showed otherwise), that they were willing to defer their demand until DPC came up and whether the load in question was from continuous process industries, justifying a 90% PLF. As the World Bank noted, "tinder [MSEB's] assumption industrial load would double, i.e. grow at an average rate of about 20% for 4 years, compared to CEA's already respectable 8% average annual growth." As it happened, even CEA's growth rate did not materialise (which is not surprising given the past experience shown in Chart 1). Industrial consumption has hardly grown in the past few years, as seen in Chapter 3. The attitude of the CEA in according clearance to this scheme is also questionable, especially given the record of discussions in the meeting. Nowhere in the summary record are the issues relating to the technical design of the project effectively addressed and yet, it was decided that the technical aspects were "generally in order". A detailed discussion of CEA's role is given in the following section.

The 'techno-economic clearance (TEC)' from CEA has been a controversial issue. The in-principle clearance for DPC's project pursuant to sections 29 and 44 of the Electricity (Supply) Act, 1948 (the Act) was issued by MSEB on May 20, 1993. The clearance was granted subject to clearance from the CEA as required under section 44 of the Act. On November 26, 1993, CEA granted its conditional clearance (copy attached at Annex 8), for the project after considering the technical aspects of the scheme³² at its meeting held on November 12, 1993. A day earlier, on November 11, 1993, the Secretary, Ministry of Power appears to have written to the CEA and quoted an extract of the minutes of a Foreign Investment Promotion Board (FIPB) meeting of November 5, 1993 which said, "...Finance Secretary- has observed that the question of the cost of power has been looked into and it has been found that it was more or less in line will] other projects being put up in Maharaslnra". Accordingly, the CEA observed that "The aspects related to import of fuel, foreign exchange rides and deviation from Government of India tariff notification indicating return on equity have been examined by FIPB and the project has been found acceptable by them.'¹'¹

On July 14, 1994, CEA issued another clearance for the project (copy attached at Annex 9) stating that all the conditions had been complied with. However, it reiterated two conditions stipulated earlier, viz., "Phase II of the project could only be taken up after MSEB/ GoM ensures absorption of the entire power including off-peak power in or outside Maharashtra together with the completion of associated transmission system matching with the commissioning schedule of the project." The CEA, as stated in an affidavit by the CEA in the CITU case, considers this to be the "techno-economic clearance" accorded to the scheme, which was based on discussions in a meeting held on 24 June 1994. The minutes of this meeting are not available to the Committee. Furthermore, it is curious that the letter does not mention the word "techno-economic" anywhere, as compared to a clearance given to similar IPP project at the same time (copy at Annex 10). Subsequently, on December 23, 1994, CEA issued a letter to Ministry of Power stating "the cost of power has been found reasonable by the Ministry of Finance, CEA feels that since the cost of power is to be derived from the capital cost, the capital cost of Dabhol project may also be considered reasonable'. In effect, the CEA said that since the Ministry of Finance finds the tariff acceptable, the capital cost is reasonable, which accords greater significance to the role of the tariff, discussed later in Section 6.4. In addition, curiously enough, it makes no reference to the meeting of 24^th June 1994 regarding techno-economic appraisal of DPC mentioned in the CEA's affidavit. Neither dues it mention that the CEA itself finds the cost of power to be reasonable. Thus, it is a moot question whether the CEA discharged the statutory duty cast on it under the Electricity Supply Act adequately. It is not clear from all this whether the economic aspects of the project have been comprehensively evaluated.

Subsequent to the negotiations conducted by the Negotiating Group mentioned in the previous chapter, the CEA received a letter from DPC dated March 7, 1996 intimating certain alterations to the Dabhol project and stating that these alterations were minor as per the first proviso of section 32 of the Electricity Supply Act, 1948. The State of Maharashtra, through Gol, had sought CEA's views in the matter. The matter was deliberated upon by the CEA and the Gol was informed that increase in capacity of plant and use of naphtha in place of distillate fuel in Phase I of the scheme were of minor character but the removal of LNG facility from the scope of the scheme and execution of the same by a separate entity in Phase H of the scheme was of major nature. Subsequently, DPC vide letter dated May 7, 1996 informed CEA that DPC was agreeable to implement the scheme without changes considered as major by CEA viz. the removal of the LNG facility from the project scheme. As a result DPC and MSEB went ahead with the project, without hiving off the LNG facilities and avoided obtaining any fresh clearance required from CEA. It is difficult to comprehend how MSEB agreed to accept the re-integration of the LNG facility, which was not in its own interest. The Committee finds it inexplicable why there was no mention of any reduction in capital cost of the project from $ 2,828 million to $ 2,501 million as agreed to by DPC as mentioned in the Summary Report of the Renegotiating Group, which appears to have been intimated to CEA, as part of its economic appraisal. Neither is there any intimation about the change in the cost of power, due to the renegotiation of tariff, which formed the basis for CEA consideration that "the capital cost of Dabhol project [is] reasonable'". The counter-affidavit by CEA on July 1, 1996 .in the CITU case however states that "since no cost increase [was] involved...fresh formal clearance... [was] not necessary". This only adds strength to the suspicion that the CEA did not consider the economic aspects of the project at all. Indeed, given the non-availability of any official record of the meeting on June 24. 1994 with the Committee, and the nature of this letter dated December 23, 1994. the Committee is doubtful whether the economic aspects of DPC were discussed at all. Therefore, the question as to whether CEA did or did not perform its statutory duty of techno-economic examination remains under a cloud.

The World Bank was asked to review the project by Gol, for possible financing. It reviewed the project extensively and pointed out on April 30, 1993'^ that ''The project [was] not u least-cost choice for base loud power generation compared to Indian coal and local gas. Even if domestic fuels [were] not available, imported coal would be the least-cost option for base-load generation for MSEB with current environmental standards. The unique features of this LNG-bused project...offset LNG's environmental benefits over coal." The current design which would "Dispatch the plant as a base load unit at 80-85% minimum plant factor ...would prevent the operational flexibility of a combined cycle plant, [and] ...the project would add more capacity' than needed to meet the projected load growth in 1998 and would also result in uneconomic plant dispatch". In addition, "substantial adjustment in electricity tariff's would be required to recover cost of the project from the consumers and to safeguard MSEB's financial position...Adjustments limited to special industrial categories would not be sufficient as their capability to continue to cross-subsidize, ijv paying more than the already high cost ofLNG power would be limited".

Subsequently, after further discussions, the World Bank wrote again on July 26, 1993 to "reconfirm [their] earlier conclusion" and stress that the project needed to be reshaped to "serve higher-value intermediate load", and that if the project was being justified on the basjs that "tl-ie existing system [was] projected to decline in efficiency" [and] "most recently discovered slippages in MSEB's ongoing and planned least-cost program", then it was better to take "determined actions ...to reverse this projected deterioration rather than accepting it as a given fact in the analysis of new investments". They even offered to "assist... in further exploring the possibilities to reshape the Dabliol project in direct technical discussions with the project sponsors" [emphasis in original].

Enron was concerned. It wrote to MSEB³⁴ stating, inter alia, "1 recently met with the World Bank and have been following the articles in the India papers. I feel that the World Bank opinion can be cliansed. We will engage a PR firm during the next trip and hopefully manage the media from here on. The project has solid support from all other agencies in Washington. We will get there! We need now to put the PPA behind us" [emphasis added]. MSEB and GoM addressed these objections of the World Bank by emphasising the environmental benefits of gas, reducing the plant size to address issues with plant dispatch and excess capacity and assuring the Gol that there would be power sector reform to adjust electricity tariffs suitably as part of their tripartite agreement entered into between Government of India, Reserve Bank of India and Government of Maharashtra, which states that "during the currency of the Gol Guarantee, necessary restructuring of MSEB will be carried out by the GoM".

However MSEB did not address the critical issue of reshaping the project to meet "intermediate

load", which would have meant that DPC could not be assured a PLF of 90%. As established later in section 6.4.2.6 and 6.4.3.4, if DPC was dispatched as an "intermediate load", then its PLF would have been much lower and it would not have been possible to show that the DPC tariff was lower than the Gol tariff, a critical component of determining whether or not the project was in the public interest.

In retrospect, all the concerns of the World Bank proved well founded. Reform did not occur, the cost was too expensive and the system has not been able to absorb the capacity, even of Phase-1. In hindsight, it is always easy to argue that the decisions made at that time were not justified, but in this case these issues were raised and dismissed at the time the original decision was made.

As already mentioned, the GoM'.s submission at the start of the project regarding the need for power was flawed to the extent that it failed to distinguish between different types of load. This led to an inappropriately high PLF of 90% being taken for purposes of calculating per unit tariff. In 1993, however, based on the past growth of consumption and load, it was possible to argue that a 695 MW plant could be absorbed into the system. This, however, completely omitted any consideration as to whether there was a demand for power at the price that was expected to be charged by DPC. The growth of relatively high-tariff consumers and the prevailing electricity tariffs and the scope for their increase to absorb the

increased cost of DPC power was not analysed even though the World Bank did point out the

f possible fallacies in the demand forecasts, as mentioned above in Section 6.2. Tariff reform

was limited to the pious assurance given by GoM in the tripartite agreement with RBI and Gol that it would carry out necessary restructuring of MSEB including maintaining a ROR of 3% on net fixed assets and a receivable and payable position of 3 months from FY 1998-99 onwards. It is also interesting that the base load demand analysis at that time by DPC used a capacity availability factor (CAF) of 58%, as used by CEA, when MSEB's own plants had a PLF at around 65% which has since increased to at least 72% (regardless of how availability is measured, it will at least equal PLF). The question here is not whether the assumption of 58% could be justified by appealing to CEA norms, it is rather a question of what was the prudent commercial assumption with respect to efficiency of MSEB's plants- Indeed, even if a CAF of 65% is used, there would be a 11% reduction in capacity needed, over 1200 MW in 1997-98 using the 14^th EPS, and more if one used MSEB's own inflated estimates. At a CAF equal to the current PLF of 72%, this reduction is 19% and over 2200 MW in 1997-98.

However, this mistake pales in comparison to the assurance given by MSEB, on September 2, 1998, that there was sufficient demand to absorb the power from Phase II. As mentioned earlier, the CEA clearance to DPC stipulated that "Phase II of the project could only be taken up after MSEB/GoM ensures absorption of the entire power including off-peak power in or outside Maharashtra together with the completion of associated transmission system matching with the commissioning schedule of the project.'''¹ In response to a letter from DPC on the demand supply position in the MSEB system, MSEB replied, establishing that there was sufficient demand. A detailed discussion is in order to establish the nature of this error.

The MSEB demand projections for justifying the requirement of Dabhol was on the basis of the 15th EPS. The actual consumption in 1998 was higher than the estimate in the 15'¹¹ EPS by 4.4%. MSEB therefore replaced the base year EPS estimate with the higher actual consumption and applied the EPS growth rates to this higher base. On the face of it, perhaps justifiable, until one looks at the growth of demand in the past. As shown in Chart 6a and 6b, the actual growth in demand in the MSEB system in the years immediately before 1998 were actually much lower than the 15^th EPS estimates.' Indeed, there is a sharp slowdown in growth in 1996. This slowdown was completely ignored. While the actual consumption in 1998 was indeed about 4.6% higher than estimated by 15^thEPS, the trend growth rate was actually much lower (2% in 1997 and 5% in 1998) than estimated by the 15^th EPS (8% in 1997 and 8% in 1998). As compared to the growth of 2% and 5% in the previous two years, MSEB estimated an immediate return to earlier growth rates of 8 to 9% per annum. As can be seen in the Chart 6a, the actual increase in consumption in 1997 and 1998 were only 1173 MU and 2538 MU respectively, while the projections assumed additional consumption in the range of 5000 MU to 6000 MU per year, over double the recent growth. Based on these extremely over-optimistic assumptions, MSEB stated "there is sufficient projected base load demand for power in the state to justify Phase II of the Dabhol project, even at a 90% dispatch" [emphasis added]. This was stated without an analysis of the load curve. Indeed, MSEB in its projections before the Committee has submitted that their current expectations are that consumption in 2004-05 will be around 67813 MU as opposed to 91202 MU expected by them in 1998. implying an overestimation of 58%! On the basis of this unconvincing estimation of demand, which prima facie, appears to ignore the realities of the situation, as it existed in 1998. Phase II of DPC was .given the go-ahead. Apart from these quantitative justifications MSEB also stated that certain qualitative factors such as location of DPC in Ratnagiri, where industrial growth is expected and its proximity to Mumbai and Pune areas, strategic location of the plain in the transmission network, which would avoid transmission losses and fluctuation in grid frequency, cost competitiveness on end user cost basis, locational advantage to sell to the southern states during some seasons and environmental merits as those which favored the Phase II of DPC. Not one of these reasons was substantiated. Given the current problems with the tariff of DPC, it is inexplicable as to why it was considered cost-competitive, on basis of what assumptions, and whether these assumptions were as cavalier as those used for demand estimation.

It must be recalled that the letter stipulating that "Phase II of the project could only he Taken up after MSEB/GoM ensures absorption of the entire power'¹ was addressed to DPC. Whose shareholders include "major companies" such as Enron, GE and Bechtel and whose responsibility it then became that MSEB/GoM satisfactorily ensured absorption of the entire power. It was therefore imprudent for them to accept, without contest, an assurance that was supported by patently implausible assumptions, especially an assurance that was the basis for commencement of Phase II of the plant. In this context, the Committee also finds that the financial institutions showed poor judgment and lack of due diligence in accepting these projections without demur, as they indicated to the Committee during deliberations, and as is evidenced by their agreement to disburse funds for Phase II of the project. The decision of the financial institutions to fund this project seems to have been based primarily on escrow account given by MSEB, guarantee by the state government and the counter guarantee by the central government (for Phase I) rather than an independent and meticulous appraisal of the project.

The Committee is deeply concerned at the apparent failure of governance that allows such decisions to be taken. A government that takes decisions involving the incurring of liabilities to the extent of over Rs. 6,000 crore a year, and rising, for over 20 years, in so cavalier a fashion, cannot at the same time, assert that the Courts must presume it acts in the public i n terest. The Committee finds that while the initial demand projections for DPC were flawed in that they ignored different load types in their projections, the demand projection that was the basis for commencement of Phase II was based on patently untenable assumptions, given the information at that time: assumptions that have since proved to be completely unjustified.

It has been asserted at various stages, once for Phase I and then for Phase II. that the DPC tariff is lower than the comparable Got notification tariff on a year on year basis. This demonstration is critical for a number of reasons, viz.:

a) It is the obligation of the Electricity Board, pursuant to Section 18(a) of the Electricity Supply Act, 1948 (ESA) to supply electricity to consumers in the most efficient and economical manner.

b) It forms the basis for determining the reasonableness of capital cost of the plant, as stated in the above-mentioned letter from CEA.

c) It is the basis for arguing that the DPC project is in the public interest,' as it is supplying power at a competitive price, or at least at a price that is not higher than allowed by the Gol notification.

As will be shown in this section, the demonstration that the DPC tariff was lower than the Gol tariff was at best, another example of systemic failure and at worst something much more worrisome. No reasonable person can accept the assumptions used for the comparison.

The following Chapter provides a more detailed explanation of the structure of the tariff. The primary point is that the payments to DPC are largely invariant with respect to energy supplied, and as such the PLF of the plant is an important determinant of the per unit tariff being used for comparison. Furthermore, the tariff is dollar-denominated to a substantially larger percentage³⁵ than other projects, and therefore the depreciation of the rupee has a more adverse impact on this tariff as compared to others. Furthermore, as MSEB has contracted the 2184 MW power plant as a base load station, tariff for power procured from DPC provides not only for complete recovery of capital costs but also commits MSEB for LNG payment obligations on a take or pay basis equivalent to 1.8 MT of LNG (the total contracted amount is 2.1 MT). During approval of DPC's project, there was no consideration of the adverse impact of variation in any of these parameters.

The tariff for this project needed to be approved, as it was not based on the two-pan tariff as computed in accordance with the notifications. Consequently, MSEB through its letter dated September 30, 1994 (copy attached at Annex 1 la) sought to establish that the DPC tariff for a 695 MW plant was less than the two-part tariff as computed in accordance with the notifications. MoP vide its letter dated December 23, 1994 (Copy attached at 1 Ib) cleared the tariff as per the PPA in respect of deviations with respect to Gol guidelines. This was accomplished even though the tariff for Phase I included 4% escalation in the capital recovery component, which led to a tariff level of 11.7 cents by 2021. Chart 7a provides a view of the tariff, as submitted by MSEB in its letter.

As noted in the previous chapter, the Negotiating Group calculated the levelised tariff for both Phase I&II of DPC as well as for the Gol tariff at a constant exchange rate and a discount rate of 17%. They found that the levelised value of the Gol tariff was Rs, 2.05, while the levelised value of the earlier DPC tariff was Rs. 2.60, which would not be possible if the DPC tariff was consistently lower, year on year over the Gol tariff as claimed in the MSEB submission.

A high capital cost increases the Gol tariff, which is based on a cost-plus regime (see Box 10). While for purposes of comparison, it has often been argued that the actual cost per MW was not high and it should exclude the cost of harbour and other facilities, but if one really did take these costs away from the project, the tariff would no longer be lower than the Gol tariff, even without any change in the assumptions on heat rate, O&M costs, PLF and

exchange rate depreciation, as mentioned below. The high capital cost biased the results in favour of DPC, by increasing the Gol tariff.

In calculating the Gol tariff, MSEB assumed that fixed O&M costs would escalate at 10% per year, i.e., the domestic inflation rate. The indexation is limited to actual inflation, but it is debatable whether 10% was an appropriate estimate for that time. Combined with a fixed exchange rate (see 6.4.2.5 below) and a lower escalation rate in the DPC tariff, this resulted in a high capacity charge for the Got tariff, and helped to show that the Gol tariff was higher than the DPC tariff.

The heat rate has been assumed for the purpose of Gol tariff at 2000 kcal/kWh. While the notification heat rate of 2000 kcal/kWh is on the face of it correct, the PPA heat rate used for DPC is much lower. This implicitly assumes here that MSEB could not have obtained a heat rate equivalent to the DPC heat rate in its negotiations with a comparable project structured on a two-part basis. CEA clarified in 1998 that these were "ceiling norms only". Indeed, in the case of other IPPs based on the two-part tariff, the heat rates are lower than the norms laid out by CEA. The heat rate of 1808 kcal/kWh assumed by MSEB for the purposes of the submission is itself odd. since the PPA heat rate is specified 7605 Btu/kWh, which translates to 1916 kcal/kWh. using the standard conversion factor of 0.252 kcal/Btu. This is confirmed by the alterations (by hand) to the submission of MSEB for Phase II of the project on January 12, 1999, when it submitted the heat rate for Phase I of the project as 1917 kcal/kWh. This assumption of lower heat rate for DPC decreases the fuel cost of DPC and assists in showing that the DPC tariff was lower than the Gol tariff. If the same heat rate is used, the levelised Gol tariff decreases from Rs. 3.20 to Rs. 3.06, still above Rs. 2.98 as calculated for DPC. But here, it is no longer the case that the Gol tariff is higher on a year-by-year basis, as shown in Chart 7b. From 2008 onwards, the Gol tariff is lower.

As per the first PPA, the DPC tariff was escalating at 4% per year, and therefore reached about 11.7 cents in the year 2021. However, since the tariff submission did not consider any depreciation in the exchange rate, the effect of this increase in dollar cost did not find full reflection in the tariff calculation. It is curious that this assumption of fixed exchange rates " were maintained even though a domestic inflation rate of 10% was assumed. It is elementary economics that excess domestic inflation leads to depreciation of the exchange rate. This is all the more surprising since the exchange rate had depreciated sharply during the negotiation period. Chart 7c shows the effect of a 5% depreciation in the exchange rate on the DPC tariff over time, as compared to the notified tariff. While the Gol levelised tariff increases to Rs.

3.37 per unit. the DPC tariff rises from Rs. 2.98 lo Rs. 3.69 per unit. Also. the DPC tariff is higher than the Gol tariff from 2000 onwards. The assumption of a fixed exchange rate played a key role in showing that the DPC tariff was lower than the Gol tariff.

The base case assumption for calculating the Gol tariff assumes a PLF of 90%. A higher PLF reduces the per unit tariff for DPC since it spreads the fixed charges over a larger base, while it increases the GOI tariff since a higher return on equity (RoE) is assumed for the GOI tariff due to incentives, i.e., the assumption of PLF at 90% compares the DPC tariff with a two-part tariff where the RoE is 31.05%. As mentioned earlier in this report, the assumption of a PLF of 90% was gratuitous, but as shown in Chart 7d, it was very "convenient", since it permitted MSEB to show that the DPC tariff was lower than the Gol tariff. If a P1.F of 68.5% is assumed, as argued in Chapter 3 along with an exchange rate depreciation of 5%, then the levelised DPC tariff rises to Rs. 4.37 as compared to Rs. 3.34 for the Gol tariff. Indeed, even if no other change except a PLF of 68.5%, was made, i.e., even if the exchange rate is fixed, and a heat rate of 2000 kcal/kWh was assumed for the Gol plant, even then the levelised DPC tariff at Rs. 3.44 is higher as compared to Rs. 3.26 for the Gol tariff as shown in Chart 7e.

Thus, it is seen that even without changing the unfavourable assumptions on capital cost and indexation of O&M expenditure, the demonstration that the DPC tariff for Phase I was indeed lower than the Gol tariff is seen to be based on very convenient assumptions of a fixed exchange rate and a heat rate of 2000 kcal/kWh, a PLF of 90% and of course, the high capital cost and indexation of O&M expenditure. Instead of trying to determine whether MSEB was actually receiving value for money, the effort seemed to be to find assumptions so as to demonstrate that the DPC tariff was lower than the Gol tariff. Table 6A below summarises the discussion in this section.

Subsequent to the renegotiation and lenders requirement as a condition precedent to financial closure of Phase II. MSEB wrote to CEA on January 12. 1999 (attached at Annex 12a) to approve the tariff with respect to the deviations from the Gol notifications. The approval from Gol was received on March 18, 1999 (Annex 12b). The important assumptions for the two-part formula computation were capital cost of $ 2828 million including working capital "as approved by CEA" and $ 2726 million excluding working capital, 90% PLF for both base load and peak load operation, station heat rate of 2000 kCal/kWh for base load operation and 2900 kCal/kWh for peaking operations for the comparator GOI project. Depreciation rate, income tax and interest on working capital was taken as per the notifications. O&M v.'as considered at 2.5% of the capital cost and escalated at 8.87% p.a. and the tax was considered at 46%. The various exchange rates used in the analysis were:

Based on the analysis, MSEB determined the levelised tariff as per the PPA at Rs. 2.90 per kWh and for the Gol tariff at Rs. 3.26per kWh. Indeed, the analysis showed that the DPC tariff was lower than the Gol tariff on a year-to-year basis. None of the above assumptions were appropriate, based on the information at that time. as discussed below. So, where did they emanate from? In the letter from CRISDL forwarding the results of the analysis to MSEB, it is mentioned: "the scope of the exercise does not include validation of the assumptions used". Further it notes that "the modelling assumptions used for tariff computation are those agreed between MSEB and DPC'. Further, "the capital cost and the financing assumptions for Phase I and Phase II have been assumed based on the terms represented by DPC and MSEB". Thus, it is clear thai these assumptions were mutually agreed between DPC and MSEB.

While the cost of the project reduced to US$ 2501.2 million after the re-negotiation, and explicitly stated as such by DPC in their letter dated April 6. 1996. a higher project cost of USS 2828 million (US$ 2726 million excluding working capital) has been assumed for the purpose of comparison. 'As mentioned earlier, this biases the results in favour of PPC. bv increasing the Gol tariff. This increased capital cost has been assumed, "us approved by CEA'' even though the CEA has averred that "[DPC] have slated that there will he certain reductions in the capital costs of the scheme" [counter-affidavit of CEA in the CITU case. July 1, 1996) and that fresh formal clearance was not necessary as "no cost increase is involved.''

The heat rate has been assumed for the purpose of Gol tariff at 2000 RCal/RWh. While the heat rate of 2000 kCal/kWh is correct, the notification also mentions that "for removal of doubt, it is clarified that the norms laid down by the authority are the ceiling norms onl\ and tins shall not preclude the boards and generating companies from agreeing to accept improved norm^'. It would therefore be correct to assume the same heat rate as negotiated in the PPA i.e. 1878 kCal/kWh for the purpose of Gol tariff calculation. Again, assuming a higher heat rate increases the Gol tariff. In the case of other IPPs based on the two-part tariff. the heat rates are lower than the norms laid out by CEA.

The assumption of a much higher exchange rate for the Gol notification as compared to the DPC is inexplicable. The lower exchange rate on DPC favours the DPC tariff. Further, there is no scenario analysis conducted for depreciation in the exchange rate, which as noted above would go against the DPC tariff, as it is more heavily dollar weighted. The DPC tariff does not lose this linkage, even after the loans are paid off. as would be the case in the GOI tariff.

The base case assumption assumes a PLF of 90%, in line with the PPA. As per the Gol notification, Gol does not guarantee any incentive beyond 68.5% PLF and the same would be available only if the plant is dispatched. The notification reads as follows: "For naphtha based thermal units, the extent of bucking down us ordered by Regional Electricity Boards or the Slate Loud Dispatch Centre as the case may he, beyond PLF of 6000 hours/kW/year. Shall l not be reckoned us generation for incentive purpose". A higher PLF makes it more likely that the Gol tariff would be higher than the DPC tariff as it increases the equity return of the Gol project, due to incentives specified in the notification. The assumption of PLF at 90% compares the DPC tariff not with a two-part tariff where the RoE is 169<-. but with on where the RoE is 31.05%, which is perhaps close to the implicit return in the DPC tariff.

An examination of DPC's tariff profile reveals that its return on equity (as obtained through the capital recovery charge component, explained in the following chapter) is around 30%. In addition, as explained later, there is additional equity return in the form of excessive O&M charges and in fuel arbitrage (see sections 7.5.3 and 7.7.6). Therefore, the Gol tariff had to be brought to a similar level of equity return, which was only possible if the PLF was 90%.

Thus, in each and every instance, both for Phase I and Phase II, the assumptions are not only untenable; they are also favourable to DPC. As shown in Table 6 b above and Chart 8, even without any exchange rate depreciation, if the appropriate assumptions were used, DPC tariff ceases to be lower than Gol tariff. Box 11 below shows the impact of exchange rate depreciation assumptions on the DPC tariff. The Committee considers this combination of circumstances to be beyond the realm of coincidence and thereby is constrained to conclude that these assumptions were deliberately chosen so as to show that the DPC tariff was lower than the GOI tariff. As can be seen. the entire demonstration of public interest owing to the lower DPC tariff is on extremely shakv ground and in the opinion of the Committee utterly unsustainable.

Pursuant to section 29 of the Electricity Supply Act the DPC scheme was notified by publication in the Official Gazette on September 22, 1993 and in various newspapers. On November 23, 1993, on the expiry of the statutory 60 day period, the GoM wrote to the CEA stating "M/s Enron have stated that they have not received any objections" on the "proposed Dabhol project". Therefore, "the requirements of Section 29" of the ESA "have been met". The CEA wrote that it had been reported that 34 representations have been received including two from consumer groups, viz., Mumbai Grahak Panchayat and Swadeshi Jagaran Manch and requested GoM to examine and confirm satisfactory compliance of Section 29 of the Electricity Supply Act, 1948 by Ms. DPC. The very next day, on November 23. 1993, in response to CEA's letter, the GoM replied stating it had a look at ail the responses that the DPC received. The GoM also mentioned that they had a "look at the replies given by the DPC' and found the replies to be "adequate". GoM further added "// specifically looked into the applications" of Mumbai Grahak Panchayat and Swadeshi Jagaran Manch and opined that these bodies had raised broad issues concerning the project, like the technical details, capital structure of the project, tariff issues and the broad policy issues of" the Central and State Government, which had been "looked into by agencies like the CEA, Department of Power, Ministry of Finance, FIPB, CCEA and of course, the Government of Maharashtra /MSEB'\ and therefore felt, that "the action desired to be taken under Section 29" of the Act had "been duly taken and complied with by the DPC'. Given the limited time span (one day) within which GoM examined the objections raised against the project, it is an issue whether satisfactory compliance of Section 29 was effectively evaluated.

The fulfillment of pre-conditions for Phase I of the project took place by a letter sent by DPC to MSEB, on February 25, 1995 (attached at Annex 14), after the conclusion of elections in Maharashtra and before the installation of a new government. General elections were notified on January 10, 1995, and held between February 9 to 12, 1995 and the results were declared on March 11, 1995, when the incumbent government lost the elections. During this period, an amended PPA was also signed on February 2, 1995. The subsequent government, in the CITU case, challenged this waiver as "deceptive and fraudulent' and referred to the last 2 paragraphs of the letter dated February 25, 1995 (reproduced below), as evidence for the same, i.e.,:

''A// the conditions precedent set out in paragraphs (a) to (I) inclusive of Clause 2.1 of the PPA have therefore been either satisfied or waived in accordance with the terms of the PPA as of the date of its letter. Therefore, all the allegations of the parties to the PPA in connection with Phase I, including those relating to (lie calculation and payment of the tariff for the supply of electricity. will become binding and effective. in)on Financial Close of Phase I us required by Clause 2.1 (in).

Please confirm your agreement to the matters set out in this letter by signing and returning to us the attached copy."

GoM averred. 'No confirmation has been recorded by [MSEB] on the letter save and except the cryptic word "Received" (undated) and signed hy the then Chairman of [MSEB]." GoM submitted, ''Receipt of the letter is not and cannot he equated to llie requirement of the agreement in writing between the [DPC] and [MSEB], as specifically provided in PPA."

These waivers relate to 12 conditions precedent stated in clauses 2.1 (a) to (1) of the PPA. Of these, 7 items, viz., (b), (c)-(v), (e), (f),(g), (h) and (i) could be waived by DPC as provided for in clause 2.1(m)-(B) of the PPA, as they related to issues that affected DPC. These were waived by DPC, presumably in order to hasten the fulfillment of all pre-conditions. For the others, waivers had to be through mutual consent between DPC and MSEB, in Writing, as stated in clause 2.1(m)-(A) of the PPA and it is. this which is referred to in the GoM petition above. The letter however mentions that DPC has been granted or received clearances from all the relevant competent authorities, "except in the case of a confirmation from GoM of the non-applicability of electricity duty under section 3 of the Bombay Electricity Duty Act, 1958, the requirement for which we [it is not clear whether the we refers to DPC and MSEB or DPC and GoM] have mutually agreed to waive as a condition precedent". In the list of clearances submitted by DPC, it has been mentioned that this particular clearance has been waived by mutual consent of MSEB and DPC. It is not clear to the Committee whether this waiver relates only to the receipt of confirmation from GoM of the non-applicability of electricity duty or to the non-applicability of electricity duty itself (which would be a matter for GoM and not MSEB). The other major issue relates to the novation of project contracts in favour of MSEB. According to clause 2.1 (d), undertakings agreeing to the novation of project contracts in favour of MSEB needed to be provided, so that if MSEB took over the project as a result of any eventuality, then these contracts would remain valid and MSEB would have the option of being able to run the plant in the same manner as DPC. The two agreements for which this novation has been waived or otherwise fulfilled are the site agreement and the Fuel Management agreement, which was executed on the date of the letter itself. As for the Fuel Management Agreement, this undertaking was provided for within the agreement itself in clause 13, and a separate agreement was therefore not called for. The site agreement condition was waived, as it was between two state agencies, i.e., MSEB and MIDC.

As per the Amended and Restated Escrow Agreement entered into between DPC and MSEB on March 22, 1999, specific revenue collection centres of MSEB have been identified and the collection from these centres would be deposited into a separate account in an identified bank, i.e., the Escrow Agent. The Escrow Agreement provides for a cover of 1.25 times the monthly billing amount. Presently, the Escrow cover of Rs.5,333 crore provided to DPC works out to approximately 51% of MSEB's aggregate revenues from sale of power of Rs. 10,626 crore in FY 1999-2000. This escrow is insufficient to cover the expected billing in 2002-03. As the tariff payment to DPC grows, to cover the inevitable shortfall in cash flow into the Escrow Account, MSEB would be obliged to provide DPC the dedication of

additional distribution circles, which would further worsen the situation. As these revenues are diverted to DPC, MSEB will find it increasingly difficult to meet its commitments to its fuel suppliers and even its employees.

The Committee is distressed with the failure of governance that has characterised almost every step of the decision making process on matters relating to DPC. However, while the development of DPC has been fraught with infirmities, its existence cannot be wished away. In this short existence, limited to Phase I, DPC has already managed to bring down the State's credit rating. The anticipated commissioning of Phase II has been likened by DPC itself to an express train coming at you. Action therefore needs to be taken to address certain urgent and critical issues pertaining to the project and examine the sustainability of DPC. This is done in this Chapter.

In its submissions to the Committee, MSEB has urged in a Resolution of the MSEB Board submitted to the Committee³⁸ that a suitable Special Purpose Vehicle (SPV), constituted for the purpose by the Gol, should take over the obligations for purchase of power under the PPA of DPC totally. At a minimum, MSEB's purchase obligations should be restricted to an amount equivalent to the Phase I capacity, no liability for gas take or pay and for the re-gasification plant should fall on MSEB, and no escrow cover should be required of MSEB. During negotiations, efforts may be made to reduce the capacity charges. Finally, even to service the power purchase obligations of Phase I, support from GoM will have to continue j until MSEB's revenues build up through suitable tariff revision and reforms.

In its first meeting with the Committee, DPC recognised the need to find a solution that , would ensure stability of MSEB and the project in the long term. According to the DPC, |such a solution will have to be worked out as a package to be acceptable to all stakeholders, |and it should be without prejudice to DPC's rights under the existing contracts. DPC showed willingness to explore options to mitigate MSEB's obligations. Specifically it offered to work with GoVGoM for off-take of power by Gol or any of its agencies for optimal utilisation of | existing installed capacity to bridge demand-supply gap in other parts of the country; assist | MSEB to sell power to other States on marginal cost basis; to work with MSEB on hedging ;| fuel and foreign exchange risk and also to reduce MSEB's LNG take or pay obligation, by sale of LNG on spot basis. In the last case, MSEB would need to bear the differential cost, if any, of such sales. DPC expressed the hope that Gol or any of its agencies, preferably NTPC, would purchase DPC power equivalent to at least 1 block (740 MW). since GOL under the counter guarantee, is, in any case, obliged to make payments for 740 MW. According to DPC, this will permit Gol to pool DPC power with NTPC power and enable reduction of average tariff, and provide NTPC with significant capacity addition with no up-front investment. DPC believes that this will also potentially give NTPC access to re-gasified LNG for its gas based power projects on the Western coast. DPC is also prepared to offer 15 per cent equity to NTPC as part of its ongoing effort to reduce equity so as to avert consolidating DPC's accounts with those of Enron, as will soon be required under US law. The other suggestion from DPC is that it should be accorded the mega project status so that the benefits accruing as a result, i.e., 100 per cent tax holiday for 10 years, and import duty exemption on capital goods, which DPC proposed it should be allowed to set off against import duty payable on fuel imports, can be passed on to MSEB. DPC has also proposed that it be given exemption from applicability of Minimum Alternative Tax (MAT) and Dividend Distribution Tax (DDT). DPC, at the same time, underlined that all project contracts (including PPA) have stringent provisions for non-performance by way of default provisions, liquidated damages, termination provisions, etc. It has also warned that non-payment by MSEB would trigger a cascading effect, with project constituents looking to MSEB/GoM/Gol for recovery. DPC has emphasised that an effective solution lies in operating DPC at 90 per cent dispatch level to minimise unit tariff; MSEB undertaking reforms in a time-bound manner; and reducing MSEB's obligations to DPC over a 3-4 year term to enable MSEB to undertake reforms. In their perception, detailed plan and timeframe of reforms is essential part of the solution. In its second meeting with the Committee, the DPC made it clear that it would be prepared to place its cards on the table only in a meeting at which GOI, GOM, MSEB and DPC were represented. Any such package of measures would have to be linked to optimal off-take of power from DPC by MSEB/Gol and finalisation of a time-bound reform process by MSEB. DPC said that such concessions cannot be given every few years and there must be some finality to them.

The Committee has carefully considered the points made by MSEB and the DPC. The question of restructuring of MSEB and initiating a time-bound reforms programme is certainly crucial to any long term and durable solution to the problem. The relevant issues are engaging the attention of the Committee and will be dealt with extensively and in-depth in its second report. It is hoped that MSEB and the state government will take very early decisions and follow-up action thereon. In so far as the other points made by MSEB and the DPC are concerned, however, the Committee believes that it will not be possible to deal with the relevant issues by merely bringing in the Gol in the matter and expecting any of its agencies such as the NTPC to off-take a part of the DPC power. If DPC power is expensive for Maharashtra consumers, so will it be for consumers- in all other parts of the country. The main question to be asked is whether MSEB should have purchased DPC power even if it was in the best of financial health and the reply will have to be a-categorical 'No'. DPC power is not the least cost option, whether looked at from the point of view of a consumer in Maharashtra or elsewhere in the country.

It must also be noted that any such change in the arrangements for sale of power will have to be approved by the Central Electricity Regulatory Commission by following the procedure prescribed under the relevant Act and calling for objections from the consumers and so on. It is therefore imperative that the basic issues involved in this project are addressed up-front. These would call for financial re-engineering and restructuring of DPC so as to reduce the cost of its power substantially. Only such a package of measures will open up possibilities for greater off-take of DPC power not only in Maharashtra but also elsewhere in the country. It is based on this appreciation that the Committee has made certain proposals in the following paragraphs regarding the manner in which the dialogue with the DPC may be pursued further in the renegotiations of this project. DPC has emphasised the sanctity of the contracts entered into with it. However, it is well known that many commercial contracts are routinely renegotiated with major changes. In a sense, economic reality dominates over technical legality in the commercial world. This is discussed in more detail in Chapter 8.

The Committee approached the sustainability of DPC in a holistic manner. It recognised that a number of different projects characterised DPC, some of which have potential for use

beyond the power plant, as mentioned in Chapter 4. Focusing on the power plant, it examined the possibility of sales outside the MSEB system and found it to be impractical. given the current price of DPC power, and the demand supply situation in the neighbouring states, and indeed the finances of all SEBs in general, who lose more money with every extra unit_sold. as their additional revenue realisation is below the cost of supply. The Committee therefore arrived at the conclusion that there is no buyer for the existing power, as currently priced and according to the existing terms of the PPA.

Essentially, negotiations would have therefore to be held to alter the terms of the PPA. Since. as structured, on paper, DPC is eminently profitable and carries relatively high interest debt. there is substantial scope for altering the terms and still retaining a reasonably profitable project. Such a renegotiation is not anathema to DPC. Indeed, according to them, they made concessions in 1995 and expect to make them again in the near future. They accept that "economic realities are what they are" and are willing to consider "lowering of equity return". In their discussions with the Committee they indicated: "there is nothing sacred about this project'. Against this background, the Committee has laid out certain broad guidelines and indicative directions for the conduct of renegotiation in a manner that would make this project sustainable.

DPC can be separated into at least two distinct projects, as indeed was conceptualised at the initial stages of the MoU itself, viz., the Fuel Facility and the Power Plant. As was mentioned in Chapter 4, there are significant alternative uses for the LNG Facility. To reiterate, the Re-Gasification facility, which is much larger than what the power plant needs, could be marketed to other gas marketers and importers of LNG, such as Petronet LNG Ltd. Similarly, the harbour facility can also be used as a common facility, by such importers of LNG, as its capacity is again well above what can be used by the power plant. With respect lo the LNG purchase contract itself, other buyers for the LNG can be found, perhaps with some additional investment in pipelines. Besides, the current market conditions for spot LNG make it quite attractive to trade LNG on the spot market. Finally, if total deliveries including additional buyers are less than what is required for the shipping charter, it can be used for transportation of LNG in the spot market.

The Committee has not examined the viability of this separate LNG project in detail However, given the large volume of new investment being planned by Petronet LNG, as well as other private parties, which include large business houses such as Tata and Reliance, it would be reasonable to assume that there is a business case for an existing facility, such as the one at Dabhol, with already well developed port and re-gasification facilities to be utilised by the other parties. If there is no such case. the Committee suggests that the Ministry of Petroleum and Natural Gas (MoP&NG) as well as the financiers and investors in projects such as Petronet re-examine their business plans intensively, lest similar expensive follies such as DPC are committed elsewhere.

For the purposes of this chapter, the Committee treated the power project as a single unit, fueled by LNG. To the extent that it will not be feasible to run the plant on LNG at low levels of off-take, the analysis would hold a fortiori, since this would increase the cost of power further and enhance the need for restructuring the project. The viability of any power project ultimately depends on whether the cost of power produced by it is priced at a level where there is a demand for such power. It is therefore useful to begin with a discussion of DPC's tariff structure.

As shown in Table 7a, DPC's tariff structure is best understood as a combination of three charges, viz.. Fixed Capacity Charge, Fixed Energy Charge and Variable Charges. Both types of Fixed Charges are payable regardless of whether any output is produced from the power plant. Their specification in per unit terms is therefore misleading. Furthermore, it must be noted that the PPA does not mention dollar-denominated tariffs, but instead a "Real Rupee" charge, where the Real Rupee is defined at 1/32 of a dollar, i.e., one "Real Rupee" equals 3.125 US cents, which effectively implies a dollar denominated charge. Since fhe DPC tariff has been the source of much acrimony, it is useful to detail out the major components.

The Capital recovery charge is the critical item that distinguishes DPC from the tariff structures of other IPP. In the Gol two-part tariff structures, the equity charge is specified ' separately, as a specified rate of return on equity invested and a separate debt service charge that reflects the interest paid, while repayment of principal is made from depreciation provisions. In such a structure, as the debt is paid off, the tariff comes down over lime, unlike the DPC case, where it remains constant in dollar terms, and increases in rupee terms due to depreciation. As the debt is paid off the entire charge becomes an equity and tax payment.

This component is based on seventy six percent of the actual debt service on rupee loans. ^ The remaining 24% is supposed to be financing the LNG facility, for which separate charges are specified. The Rupee Debt is a minor amount, being only 14.5% of the total cost of the project. In any event, the capital recovery charges remain at 2.629 cents. If Rupee debt service increases or decreases, the "Real Rupee" or dollar linked component is adjusted accordingly.

The O&M recovery charge is substantially different from the standard Gol notification,which provides for 2.5% of capital cost escalated at a composite index of Indian inflation. Assuming an average construction period exchange rate of Rs. 40 to the dollar for Phase I i and Rs. 45 to the dollar for Phase II, the O&M recovery charge as per the Gol notification works out to about Rs. 214 crore. By contrast, the charge here is around $ 88 million and Rs.4 46 crore, i.e., almost Rs. 460 crore annually, which is much more than this figure. As will be seen later, one of the major differences in moving to a two-part tariff from the DPC tariff is in the reduction in O&M cost. The excess of O&M recovery over actual O&M expenditure adds to the equity return, in this case, by around 5% per year

The re-gasification charge was instituted to recover the costs of the LNG Facility, including t the harbour, which were stated to the Negotiating Group as $ 494 million. As can be seen;! from Box 4 in Chapter 5, the present value of this charge, with an annual outgo of approximately $ 93 million, discounted at 17% (in itself a fairly high discount rate in dollar terms), is equal to the same amount. As such, as mentioned before, the entire cost of the facility is recovered from this charge alone, even though the facility itself is of a capacity much larger than required for the plant.

The Shipping and Harbour Charge is presumably to recover the cost of transportation of LNG. Since the cost of $ 494 million was for all non-power plant facilities, the harbour costs too would have been recovered from the re-gasification charge. The outgo on this account is approximately $ 45 million and Rs. 22 ci-ore, i.e., approximately Rs. 233 crore per year. To the extent that this amount exceeds the cost of the shipping charter, there is additional recovery on account of harbour charges. In this context, the bids received for the charter for a vessel similar to DPC LNG ship Laxmi by Petronet LNG has been recently reported to be around $ 70,000 per day, which is about $ 26 million per year. The charter rate for Laxmi, as mentioned earlier is around $ 98,000 per day.

The fuel supply agreement obliges MSEB to pay for 90% of the contracted quantity with Oman LNG (1.6 MT) and 75% of the contracted quantity with ADGAS (0.5 MT), which is about 1.8 MT of LNG per year (which is the fuel requirement for a 73% PLF), even if it does not consume a single ton of LNG. At a price of $ 3.75 per mmbtu ($25 per barrel of JCC), the outgo on this account is $ 403 million. Even though there are such take or pay provisions in most LNG supply contracts, the advantage of a separate fuel venture is that such demand risks are distributed more widely across various consumers, so that no individual buyer is exposed to the risk of take or pay. In this case DPC has transferred the entire risk to MSEB. One of the advantages of the separation of the fuel venture referred to earlier in Section 7.1 would be the ability to distribute these risks in a more equitable manner.

The impact of this tariff structure is that DPC has almost no variable charge until the PLF reaches 73%, i.e., 14,000 MU. Even if MSEB were to buy no power from DPC, it would have to pay around $ 1140 mn. per year, or about Rs. 5360 crore per year. Under the current tariff structure it is financially sensible to draw as much power as possible from DPC, since even if one does not draw the power, one would have to pay anyway. This would imply replacing 73 % of MSEB's entire power purchase of approximately 18,000 MU in 2001-02 and replacing it with power from DPC, which would increase the cost of power purchase substantially.

At these tariffs, there is unlikely to be any demand for DPC power, especially since it is a base load facility. Table 7b gives the growth in energy demand by various categories of customers in some states of the region. The demand growth in the region over the past, especially in the paying categories, i.e., industrial demand has not been strong and commercial demand has a small share. Besides, most of the shortage is not at base load but during peak. Even so, each unit purchased by an SEB increases its losses since they are unable to direct the power only to paying consumers and their average realisation ends up below the cost of supply.

In addition, a substantial capacity is coming on line in these areas. A list of such projects and their commissioning dates is given in Table-70. In addition, in states like Andhra Pradesh, there has been substantial interest in smaller power plants using natural gas, from the Krishna Godavari basin. These plants have been awarded on a competitive bidding basis at extremely low tariffs, whereby the fixed cost is as low as Rs.0.94 per unit and the variable cost is expected to be Rs.1.05 per unit. Any power sales from DPC will therefore have to be extremely competitive. In addition to this IPP capacity, there are public sector projects such as NTPC's Simhadri plant, APGENCO's .projects in Kothasodam and Rayalseema and Karnataka Power Corporation Limited's (KPCL) expansion at Raichur, all of which are expected to be extremely cost competitive, especially for base load supply.

It is evident that if DPC is to be made sustainable, the tariff will have to be reduced considerably. At the current levels of tariff, there is no demand for power from DPC and as such, the low PLF implies that tariffs will continue to remain high. A lower tariff will induce demand, increase PLF and thereby allow the fixed costs to be distributed over a wider base. A lower tariff can only be obtained by lowering the fixed costs associated with the project. DPC, in its presentations to the Committee have indicated their willingness to enter into further discussions, but in a forum that includes the Government of India. Furthermore, they have explicitly stated that nothing was sacrosanct. The Committee, in fulfillment of its terms has tried to determine in good faith whether it was at all possible to restructure DPC in a manner where it could produce energy at an affordable price that would permit some absorption of power, and thereby provide guidelines for the re-negotiation process. Having examined a number of options, the Committee has arrived at the following indicative list of actions that would have,a substantive, impact on the tariff. An illustrative exercise is provided for ease of understa-'iding. Charts 9a, 9b, 9c and 9d provide an overall view of the evolution of fixed charges under various options and Table 7e provides a snapshot of the impact of various options described below for this exercise.

The first point of departure was to calculate the fixed costs associated with an equivalent project, which we call the "Synthetic DPC (S-DPC)". The S-DPC project has the same capital cost as associated with the power plant of DPC, which based on the Summary Report that was agreed to by DPC, is assumed at $ 2,007 million. The LNG facility is separately costed at $ 494 million and priced accordingly. The financing package for this project has been assumed to be the same as the actual DPC project, i.e., in terms of its interest rates, currencies and tenor (duration of loan), with pro-rata changes in quantum of loans and equity for differences in capital cost. The O&M expenses for this project were assumed at the levels provided for by the Gol guidelines, which allow up to 2.5% of project cost, escalated at a composite Indian rate of inflation. The currency of equity holdings is the same as DPC, i.e. 100% dollar denominated equity. A full list of assumptions is attached at Annex 16.

Given the S-DPC project, it is possible to calculate a rixed charge based on the Gol's two-part tariff guidelines that will allow the equity holder to earn a given rate of return in dollar terms. As is evident from Chart 9, which calculates these tariffs initially for a 16% return on equity, there is a large difference in the fixed charge between DPC and S-DPC. This is further proof of the manner in which tariffs have been improperly presented in the past to justify the untenable presumption that DPC tariffs were lower than the Gol notification.

As the Chart 9 shows, eventually the fixed charge starts rising. This is due to the impact of dollar depreciation. A conversion of all dollar-denominated equity in S-DPC into Rupee equity (which is equivalent to denominating the equity return in Rupee terms instead of, dollar) brings a further reduction in the tariff. However, the first year tariff including fuel charge is still too high to be absorbed into the system. It is necessary to reduce per unit fixed cost component of tariff in initial years when PLF is expected to be low.

Reduction in tariffs in the initial years can only be achieved through changing the financial structure of S-DPC substantially. Three such changes are explored, viz., conversion of all debt into Rupee debt, introduction of a moratorium with an extended repayment period and reduction in the interest rate. Part of the equity could be converted into preference capital, with the same redemption period as the debt apart from a write down of equity. These options involve significant financial sacrifices for the debt and equity holders.

Not only does the power plant have to be restructured, the LNG facility also has to be similarly restructured. This would reduce the costs further. However, for the illustrative exercise, it was only assumed that the fixed costs of the facility are proportionately allocated to the fuel charge, i.e., only 42% of the cost of the LNG facility is recovered as a charge on the fuel supply. This would have been a more appropriate manner in which to execute the separation of the LNG Facility, when the Negotiating Group recommended it in 1995. When the fuel charge is added, the tariff becomes somewhat more regular since the fuel cost is rising due to depreciation, which counteracts the reduction in fixed charges as debt is repaid.

It has been suggested that the use of LNG in place of naphtha would reduce tariffs considerably. However, the difference is not much, though LNG is cheaper than Naphtha. The prices of both change with the price of crude oil and could go much higher than their base indexation price. Over the past ten years, the difference has varied between 3% and 14% and the reduction in fuel charges would be of a similar magnitude, much less than what is needed to make the project viable. In addition LNG brings take or pay obligations in its wake, which, if implemented would increase the fixed outgo substantially as shown earlier in Table 2d. The LNG contract needs to be renegotiated so as to remove the 1.8 m.t. take or pay burden from the power plant. At 30% PLF, DPC will be unable to absorb more than 0.8 m.t. of LNG. This is not insurmountable. As Box 13 shows, all three assumptions that underlay the core design of Dabhol viz., that a single train'¹⁹ of LNG (approximately 2.5 mtpa) had to be absorbed, that a long term Take or Pay (ToP) contract had to be executed, and the impossibility of finding other buyers for gas in India; are much less relevant today.

This box examines the LNG business and its impact on the manner in which the Dabhol power project was originally structured to determine whether recent developments make it possible for it to be reconfigured as an intermediate load plant that will slowly increase its output over time.

The original conception of Dabhol described in 7.7.5 above led to the project being designed as a 2000+ MW base load plant to absorb the entire train of LNG. To match the take or pay obligation, either the PLF had to be high, which meant a base load configuration or, if it served only intermediate load ie PLF of around 60-65% see Box 2), the plant size had to be increased further. The project structure was thus driven by the assumed inflexibility in the LNG contract.

Today, LNG is fast losing its "club" reputation as the number of participants on both sides of the market has grown-⁴⁰. Consequently, from the seller's viewpoint, the need to sell a whole train to one buyer has diminished. In India itself, there are now a large number of potential users and a rapidly evolving infrastructure for marketing and importing gas. Indeed, if all the projects under development were to come on line (excluding proposals in the preliminary stages), India would have receiving capacity for LNG of over 40 MT per year, almost equal to the current consumption of natural gas⁴¹. Finally, while take or pay contracts are still the norm, there is now a growing number of short-term contracts and a rapidly growing spot market. Even long-term contracts are now being structured with much more flexibility⁴². Thus, all the three assumptions that underlay the basic design of Dabhol power project are much less relevant today and this permits the project and its contracts to be restructured in a more flexible manner, to better exploit the benefits of a CCGT plant in system operations.

LNG is not a cost-effective solution to meet base load power. Two recent analyses of the project economics of LNG power plants come to the conclusion that it is competitive vis-a-vis coal only if the delivered price of gas is less than $ 3.85 per mmbtu in one case and $ 4.90 per mmbtu in the other⁴³. Neither of these analyses takes the impact of exchange rate depreciation on project economics into account and therefore even these overestimate the competitiveness of LNG plants. If one deducts transportation charges and Dabhol's re-gas charges at $0.50 and $0.65 per mmbtu respectively even from these implausibly low costs, it implies Dabhol's FOB price must be between $2.70 and $3.75 per mmbtu (i.e., $18 to $25 per bbl) for it to be competitive. To the extent that the assumptions in these studies are favourable to LNG economics, as they are, the actual FOB price must be even lower,

DPC can be made flexible to serve the intermediate load. Shorter term and more flexible contracts are available, and it is now also possible to distribute any residual take or pay risk among a larger set of buyers⁴⁴ in India. To illustrate, if Dabhol initially runs at 30% PLF, it will consume about 0.8 mt of LNG leaving only 1 mt to be distributed to other buyers, even if there is no reduction in the ToP the main supplier may actually prefer a lower ToP as it seems to have over-committed its capacity⁴⁵). Given demand projections of the projects referred to above, absorption of this quantity seems trivial, if other importers also can use the terminal and there is associated pipeline capacity. Scarcity of shipping capacity is not a problem for Dabhol, as there is large storage capacity and a dedicated charter (with LNG ship Laxmi) that can be modified to ensure that there is adequate supply for the power plant, even if the charter is used elsewhere. The current scarcity of shipping is actually a benefit as Laxmi's costs can be easily covered even if it is not used fully for Dabhol.⁴⁶ Finally, it is also possible to renegotiate the price index away from the JCC to a structure more suited to the demands of the Indian market. The netback approach already in the Atlantic LNG trade typically tie the sales price to a price at which the buyer is able to resell the re-gasified product and this can be adapted for Dabhol too. Indeed, originally, Oman LNG was scheduled to sell the gas now meant for Dabhol to Thailand, using a price indexed a basket of alternative power fuels, primarily coal.⁴

The reason for this is obvious from the discussion in Chapter 6. IPPs make considerable profit from the difference in these heat rates, as explained in Box 14 below. This will lead to a reduction in the overall tariff by reducing the fuel charge.

All the restructuring is designed to yield a tariff that will translate into a cost of supply that is affordable to the consumer. Therefore, the final tariff stream that emerges from the process, at realistic levels of PLF that may be as low as 30% in the initial years, is a critical determinant of the efficacy of the restructuring. It is important to subject this tariff to a full range of sensitivity analysis with respect to variables such as the exchange rate, fuel price, PLF, etc. A critical component of the restructuring is to benchmark the tariff to the lowest cost of supply of power from gas-based projects elsewhere and also to the willingness of other buyers such as other states and PTC to pay for the power.

What will actual tariffs look like? This will depend on the extent of restructuring and the off take of power. To the extent that the rise in PLF can be accelerated by selling the power to other distributors or to creditworthy buyers in Maharashtra or other states, who also lack sufficient intermediate load facilities and who can take advantage of higher ,time of day (ToD) tariffs, now being permitted by regulators, e.g., ifBSES starts buying this power, then one can achieve lower tariffs. However, if the full extent of restructuring as described above is undertaken, even if the PLF rises slowly over time, for example reaching 67.5% by 2007 (a higher PLF cannot be assumed for a plant that is expected to serve intermediate load, as explained in Chapter 3), the ultimate tariff could still prove affordable, but only if a complete restructuring is undertaken and the plant is reshaped to meet intermediate load. Such a probable scenario is shown in Chart 10. •

Box 15 and Table 7e provide an illustrative example of the kind of tariff reductions that can be obtained through restructuring. As the project structure is changed from DPC to S-DPC, there are two effects, i.e., fall in equity return (from the implicit DPC return to 16%) and a reduction in O&M charge to that provided by the Gol guidelines. Conversion of equity into Rupees reduces the equity return by removing dollar indexation, and conversion of all debt into Rupee debt (same repayment profile as the existing loans) reduces the debt service charge. The subsequent restructuring, write down of equity and reduction of interest reduce capital recovery charge and debt service respectively. A moratorium on debt service increases the levelised cost (due to a higher burden of interest cost), but reduces the payout in initial 1 years, when PLF is expected to be low. Finally, conversion of equity to preference capital at 8%, with the same redemption profile as the loan moratorium reduces the equity return.

This box provides an illustrative example to demonstrate the impact of the restructuring options delineated in the previous section. Not only is the power plant restructured, it is assumed that the fixed costs of the LNG facility are proportionately allocated to the fuel charge, i.e., only 42% of the cost of the LNG facility is recovered as a charge on the fuel supply. The Fuel charges, assuming an annual rupee depreciation of 6.5% with respect to the dollar, and oil price of $ 25 per barrel, is provided at the bottom of Chart 10. When fuel charge is added, the tariff becomes somewhat more regular since the fuel cost is rising due to depreciation, which counteracts the reduction in fixed charges as debt is repaid. The Committee hopes that this will provide a better understanding of the magnitudes involved in the process. Note that the tariff at a PLF of 90% is only provided for comparison with earlier tariffs mentioned in connection with DPC. As has been made abundantly clear, DPC is not expected to achieve 90% PLF since it will be serving intermediate loads and can therefore attain a PLF closer to 60%.

Changing DPC's tariff structure to a two-part structure: Given the S-DPC project, it is possible to calculate a fixed charge based on the Gol's two-part tariff guidelines that will allow the equity holder to earn a 16% rate of return in dollar terms. For the purposes of this example, no additional return to equity for higher availability was assumed. As is evident from Chart 9 and Table 7e, this single change (along with the exclusion of the LNG facility) 'brings down the levelised tariff from Rs. 2.95 to Rs.1.72 per unit at 60% PLF or Rs 5.88 per unit to Rs. 3.46 per unit at 30% PLF, which is probably a more realistic level to consider in the beginning. These levelised tariffs are being provided purely as an illustrative device to show the extent of change

and should not be used independently of the actual tariff stream in Chart 9. This is obviously not enough, since the variable cost of power itself is around Rs. 1.94 (assuming oil at $ 25 per barrel), which combined with a first year capacity charge of Rs. 3.36 implies a tariff of Rs. 5.30 at 30% PLF. This would need to be brought down much further before it becomes affordable.

De-dollarising equity: In this example, all dollar-denominated equity in S-DPC is converted into Rupee equity (which is equivalent to denominating the 16% return in Rupee terms instead of dollar). This brings a further reduction in the levelised tariff to Rs, 2.85 per unit at 30% PLF (Rs. 1.42 at 60% PLF) and a first year capacity charge of Rs. 3.19 per unit. However, the combined first year tariff at 30% PLF ofRs. 5.13 per unit is still too high to be absorbed into the system. It is necessary to reduce per unit fixed cost component of tariff in initial years when PLF is expected to be low. This can only be achieved through financial restructuring.

Financial restructuring: The financial structure of S-DPC is changed substantially at this stage. Three large changes are made, viz., all debt is converted into Rupee debt. A 5-year moratorium and a repayment period of 15 years are introduced and the interest rate is reduced to 12%. Furthermore, 75% of equity is changed into preference capital at 10%, with the same redemption period as the debt. The cumulative result of this exercise is to reduce the first year capacity charge at 30% PLF from Rs. 3.19 to Rs. 2.18, which when coupled with a Rs. 1.94 fuel charge^ gives a barely acceptable tariff of Rs. 4.12 per unit at 30% PLF.

EPC Heat Rate: The heat rate is assumed to be the EPC heat rate of 1725 kcal/kWh. The fuel charges for this assumed heat rate for different values of the JCC index are given in Annex 17. For this example, the JCC value is assumed to be S 25 per barrel.

The combined effect of this illustrative restructuring on the tariff stream over the next twenty J/ears is shown in Chart 10.

Fuel Cost: Convert all re-gas finance to rupee debt and equity: No fixed component: Pay as use

'The options shown in this Table are cumulative, i.e., reductions in option 4 also includes reductions as a result of option 3 and 2.

* This has been calculated by deducting the likely taxes and foreign debt service corresponding to a project cost of US$ 2007 million from the Real Rupee-Capitall Recovery Charge (RRCRC) in the Dabhol l PPA, adjusted for the Rupee debt service as provided in the PPA.

*This is the Debt service for a capital cost of US$ 2007 million, financed as per the financing package for DPC.

This Chapter brings together the recommendations of the Committee with respect to the first part of the terms of reference. These recommendations are unanimous, except in one instance as outlined in Section 8.2 below.

The Committee is concerned with the extent of apprehension, fear and suspicion among the people who have sent their representations and even among the MSEB staff with respect to IPPs in general and DPC in particular. The Committee recognises that all new IPPs and PPAs will be examined by MERC, which has instituted a transparent open hearing process. It also recognises that the State has recently adopted the Freedom of Information Act. While commercial considerations may apply in certain instances, the Committee is convinced that in the case of PPAs, this concern is overwhelmingly overridden by the public interest. In a PPA, one of the parties (in this case, a state owned utility, the MSEB) undertakes financial obligations that eventually devolve on the public, either through increased tariffs or increased taxes to finance subsidies needed to be given by GoM, or a reduction in other expenditures by GoM, as discussed in Chapter 6. The public therefore has a right to know what is being contracted on their behalf. Keeping all these in view, the Committee recommends that all documents, including associated contracts, related to all IPPs, including, in particular. DPC, be published by the Government of Maharashtra within two months.

In view of the critical importance of the issues involved in this report and its relation to the DPC roject, the Committee also recommends that this report be published for the information of the people as soon as possible.

As said at the outset, with respect to DPC, the Committee is concerned with numerous infirmities in the process of approvals granted in the project, which bring into question the propriety of the decisions. Arguments advanced to support these decisions appear unconvincing, and prima facie against public interest. The Committee is troubled with the failure of governance that seems to have characterised almost every step of the decision making process on matters relating to DPC. This failure of governance lias been broad, across different governments at different points of time, at both the State and the Central level, and across different agencies associated with examining the project, and at both the administrative and political levels. It strains belief to accept that such widespread and consistent failure to execute assigned responsibilities is purely coincidental. Though the Committee was given certain additional terms of reference, specifically- item (3) of Resolution No. PSP 2001/CR3448/NRG-2 dated March 9, 2001, it has unanimously decided that it is not the proper foriirn to investigate such matters to the degree that would be required. The Committee, in the short time allocated to it, is unable to determine reasons for the consistent lapses, but is extremely concerned at it.

Dr. Godbole and Dr. E. A. S. Sarma both felt that the Committee should categorically make a recommendation that GoM should appoint a judicial commission of inquiry in onier that satisfactory answers are found for the questions raised by the various sections of the people in Maharashtra. As already explained in the previous chapters, the Committee has prima facie found infirmities in several decisions taken in respect of this project at different points of time by the successive governments and agencies in the Centre and the State. If this project had been subject to a comprehensive techno-economic appraisal as envisaged under the provisions of the Electricity (Supply) Act 1948 and the related legislation, these infirmities would have been avoided and the design and the scope of the project would have been so adapted as to fully subserve interests and the requirements of the electricity consumers of Maharashtra in particular and the people of Maharashtra in general. The fact that this has not been allowed to happen raises questions on whether there has been a concerted effort towards exercise of undue influence on the process of decision making at each and every stage in this | project. There have been clear lapses in governance in the whole affair of DPC and this Committee would be failing in its duty if these lapses were not pointed out. However, in order to establish in a legally sustainable manner whether there is exercise of undue influence -or not, it would be necessary to elicit documentary and other evidence, examine all those concerned on oath and carry out a detailed investigation. Any such investigation will have to cover the State Government, its agencies, the Central Government, its agencies and all the others who are concerned with the project. Such an investigation would be necessary for fixing both administrative and political accountability for the lapses, if any. They felt that it would be in the public interest to conduct such an enquiry, as the findings from an enquiry into this matter will have an important bearing on policy initiatives in the power sector in the years to come. However, this task cannot be carried out by this Committee as it is neither legally equipped nor has sufficient time at its disposal to conduct the kind of a detailed investigation that would be necessary for the purpose. It would therefore be more appropriate to appoint for this purpose a judicial Commission of Inquiry under the Commission of Inquiry Act under a sitting o or retired judge of the Supreme Court of India. Depending upon the findings of such a judicial Commission, if there are lapses established on the part of the Government functionaries including the political executives, the responsibility for the same needs to be determined and appropriate action taken against them. If the judicial enquiry also establishes that there is exercise of undue influence that had resulted in any decision that was against the public interest, the relevant provisions of the contract law may have to be invoked for legally reviewing.the existing contractual commitments with DPC and

taking all necessary steps that would subserve the public interest, without GoM/MSEB having to incur by contractual liability. However, three other members of the Committee, namely Mr. Parekh, Dr. Pachauri and Mr. Lal were of the view that the terms of reference did not provide the Committee with any reason to suggest a Commission of Inquiry. In respect of the Dabhol Power Project, the terms of reference of the Committee, as laid down, only required the Committee to evaluate and review the Dabhol Power Project, review any or all of its clearances etc. It is open to the Government of Maharashtra or other authorities to set up a Commission of Inquiry, should they find any reason to justify the establishment of such a Commission. The three members mentioned above also expressed their doubts whether such a Commission of Inquiry would serve any useful purpose, given the need for recording the evidence of a large number of those associated with the decision in MSEB, the Government of Maharashtra, the Government of India, and others, particularly since several of those who were involved have

retired and may not be easily available. In addition, these members observed that Commissions of Inquiry in India have rarely completed their task within a reasonable timeframe. Therefore, they felt that such a Commission if established could, in fact, only act as a hurdle in the re-negotiation of the project as recommended by the Committee.

Even though contracts are supposedly sacrosanct, economic realities often overwhelm legal protection. Though there are individual variations in factors leading to renegotiation, the main driver has been altered economic circumstances. In the case of PPAs. these have included lower than anticipated demand for power, excess supply, incongruence with 'merit order dispatch' and IPP generation and more recently, the restructuring of the electricity sector in many developed economies. Long-term LNG supply contracts to countries such as Japan and Korea have also been renegotiated.

In Indonesia, which was among the hardest hit by the South East Asian currency crisis, a number of IPPs became uncompetitive as their dollar linked tariffs soared far above the consumer's capacity to pay in local currency. The PLN, the buyer in Indonesia, which had signed long-term agreements with various IPPs, was forced to enter into extensive renegotiations and restructuring of contracts, some of which were allegedly obtained on extremely favourable terms, as a result of political connections. The recently appointed head of the Philippines Power Corporation has announced his intentions to seek renegotiations with the IPPs. Although the Corporation has serviced its obligations to date, the payments have reportedly imposed unsustainable burden on the economy. There are similar instances in other countries, including Pakistan. The extent of relief granted has varied. In Indonesia, one IPP has agreed to accept only the variable cost for up to next 12 months pending more satisfactory renegotiations for the future. There was also an offer to continue with present PPAs till 2003, and then operate as a merchant power plant. An IPP operating as a merchant plant has recently achieved financial closure in Singapore .

The largest extent of renegotiations has however taken place in the USA, as the industry has been restructured along more competitive lines and away from long-term PPAs. Some of these contracts had to be bought out; others were renegotiated to bring them in line with pool requirements. In Alberta, Canada, some of these PPAs were recently auctioned as part of overall sector reform. There have been a number of litigations on "regulatory takings", where firms have argued that investments have not been fully compensated. Here the US Supreme Court has held. in Diiqiiesne Light Co. et. al. vs. Barasch et. al. 488 U.S. 299, that such action must be judged against the equity return that the company earns, because that is an index of the risk that it takes. A company earning high returns has a weaker case than one that has had a low regulated return. Indeed, it is eminently debatable whether the PPA with DPC, given its high tariff, and base load off-take level when the need is at best for intermediate load would have been viewed by regulators in the US as having followed norms of prudent business behaviour."⁴⁹.

In India too, long-term license agreements in the telecom sector, entered into by the central government, were reopened on the ground that they were anti-competition, unworkable and would. lead to unsustainable losses to the private sector licensees and were renegotiated on a revenue sharing basis. Hopefully, the proposed Electricity Bill may require a re-look at long-term PPAs.

In the LNG trade, a number of contracts have been restructured³⁰. Thus far, successful renegotiations of LNG contracts in both directions have been possible, partly owing to the limited number of buyers and sellers in the market. The collapse of oil prices in 1986 and the relatively low levels of oil prices that followed led to ^he renegotiation of LNG contracts, a direct result of the failure of the pricing formulas that had been used. In 1998, numerous project delays and cancellations of LNG contracts occurred. In South Korea, KOGAS cancelled at least 20 cargoes in 1998. Thailand effectively cancelled its 2.2 mtpa agreement with Oman LNG and another for an undecided quantity from Indonesia due to come into effect in 2003.

The eventual decision as to whether or not to renegotiate eventually depends on each partner's perception of the benefits from continuing a relationship versus the costs of terminating the agreement and the relative recoveries after termination.

While the development of DPC has been fraught with infirmities- its existence cannot be wished away and it now stands as a near-completed project on Indian soil. In this short existence, limited to Phase I, DPC has already managed to bring down the State's credit rating. The anticipated commissioning of Phase II has been likened by DPC itself to an express train coming at you. Therefore, even if a Commission of Inquiry is constituted and commences its work, action needs to be taken concomitantly to address certain urgent and critical issues, pertaining to the project, through negotiations with DPC. so as to bring down the cost of power. During discussions held, DPC has indicated that nothing was sacred and it was willing to re-examine all project issues, but with the relevant parties viz. MSEB, GoM and Gol together at a common forum. The Committee is also of the unanimous view that these negotiations with DPC would be best carried out between parties' signatory to the various agreements. However, in fulfillment of its mandate and in order to provide broad guidelines for negotiation, and especially mindful of the previous outcome of the renegotiations, the Committee recommends the following approach to restructuring the DPC project. The exact terms need to be agreed between the contracting parties, but in the Committee's opinion, unless the negotiations proceed on these broad guidelines and the various parties make concessions of this magnitude, the ultimate result is likely to be as infructuous as the earlier re-negotiations in 1995. As can be seen, this approach needs broad involvement, of DPC, MSEB, the GoM and the Gol, not only the Ministry of Power (MoP) but also the Ministry of Finance (MoF) and the Ministry of Petroleum and Natural Gas (MoP&NG). It also needs a strong political mandate and united public opinion to succeed.

The Negotiating Group recommended this in 1995. However, it was not implemented in order to avoid a fresh examination by the CEA. This should be carried out forthwith. The Committee is aware that such a separation may attract further attention from CEA, as was communicated in 1996, and considers such fresh scrutiny to be an added benefit. The LNG facility has several other uses as mentioned earlier. The re-gasification facility is for 5 mmtpa of LNG whereas the power plant has contracted for only 2.1 mmtpa of LNG (of which 1.8 million tonnes is take or pay) and even using that requires an unreasonably high

PLF. As a separate facility, it could be marketed to other buyers of gas. distinct from the power project. That such buyers exist is demonstrated by Enron's own MetGas initiative and by Petronet's large project plans. It is critical that the costs of this facility be distributed over its entire capacity and not just over the amount sold to the power plant, as is currently the case. Similarly, the harbour facility can also be used as a common facility, by other importers of LNG, as its capacity is well above what can be used by the power plant. The Committee therefore recommends that the LNG Facility be separated into a distinct facility, whose capital costs are reflected in the fuel charge, not as take or pay. but only in proportion to the extent of fuel re-gasified for power generation, compared to the total re-gasification capacity.

With respect to the LNG contract, the current market conditions for spot LNG make it feasible to trade LNG on the spot market. The Committee is also of the opinion that in view of Petronet's expansion plans and their view of the LNG market, it, and other market participants in import of LNG, should seriously consider contracting for the use of excess supply in the LNG contracts executed with Oman LNG and ADGAS. The shipping charter is not linked inflexibly to the project. It can be used for transportation of LNG in the spot market, 'n case deliveries required for the power plant are reduced and no other off-takers are found in India. As seen in Box 13 in Chapter 7, the current market for spot trading in LNG is constrained by availability of vessels, and Laxmi can be profitably redeployed. Further, wider use of the Dabhol LNG Facility should be examined by the Ministry of Petroleum and Natural Gas (MoP&NG) for possible integration with the expansion plans of Petronet LNG-Other private companies interested in LNG imports can also undertake this. The necessary pipeline investments may be examined for this purpose.

In view of the difficulties involved with this LNG based power project, the Committee also suggests that the MoP&NG and Ministry of Power jointly review the demand estimates for LNG in India, especially the use of LNG for power plants. Furthermore, while, the Committee has, in its indicative calculations assumed the price of fuel as contracted by DPC, there appears to be considerable scope for re-negotiating the price of LNG in the agreement | and evolving tight bounds on the price, to limit the impact of sudden increases in fuel price and even denominating a certain portion of the payment in Rupees. The Committee therefore recommends re-negotiation of the 'LNG Supply and Shipping Agreements including through review of both the .guaranteed off-take as well as cornmercia! terms. The MoP&NG should examine the feasibility of integrating the Dabhol facility within the broader plans for LNG imports into India and examine the necessary pipeline investments in this regard.

The most contentious issue with respect to DPC is the tariff and its non-transparent nature. It is essential to remove this opacity. This can be done by converting the tariff structure into a two-part tariff based on the Gol guidelines and the ABT (Availability Based Tariff) Order of the CERC (Central Electricity Regulatory Commission). It is not however necessary to agree to the availability linked incentives given in these notifications. As shown in Section 7.7.9 and Box 15, this will lead to a substantial reduction in the tariff. The Committee therefore recommends that the DPC tariff be redefined using the principles contained 'n Gol guidelines and the ABT Order of CERC to convert it into a two-part tariff but limit equity return substantially.

Dollar linkage in the project increases the rate of growth of tariff since the effective equity return is the base return plus depreciation. Since the rate of future depreciation is contentious and uncertain, this adds unnecessary volatility to the tariff, in a situaon where it has become necessary to defirne a predictable tariff in order to evolve a long-term restructuring plan. The debt component of the fixed charge also has the same unpredictability, though in this case the difference in interest rates between domestic and foreign funds provides a cushion against a certain level of- depreciation. Indeed for certain levels of depreciation, it would be less expensive to have foreign debt. The Committee therefore recommends that the equity return for the redefined DPC tariff be defined in rupee terms rather than in dollar terms.

In the initial years, the off-take of power from DPC is likely to be low, given the lack of creditworthy buyers for the power, until such time as the distribution system can be reformed within Maharashtra (which the Committee will address in Part II of the Report) and outside, where the process has begun in states like Andhra Pradesh and Karnataka. If the fixed charge is distributed over this low off-take, it will increase the per unit tariff to unaffordable levels. The finances of DPC therefore need to be restructured so as to defer the payment obligations to the later years, when the off-take would be higher and the higher fixed cost can be distributed over this higher off-take, which will keep tariff at acceptable levels. Box 15 and the associated Chart 10 provide one such possible scenario.

In view of the non-sustainability of the Dabhol project as outlined in the previous chapters, the promoter company i.e. DPC should forego a portion of the return on its equity so that the project may become viable. The Committee therefore recommends that the maturity of the debt of DPC be increased, preferably to 15 years, with an initial moratorium of 5 years. An indicative interest rate for such debt could be 12% (in rupee terms, which would be around 6% in dollar terms). In case such maturity is not possible for foreign loans, the foreign debt should be converted to rupee debt and restructured accordingly. Concomitantly. the equity may also be restructured into deferred preference capital, so that the impact on tariff is felt only in later years. .

The Escrow Agreement with DPC, as currently structured, requires fresh regions to be added when there is a shortfall in revenue requirements. This will soon give rise to a situation where virtually all of MSEB's revenues will be required to be escrowed to meet DPC's .' payments, leaving little for wages and fuel. let alone additional power purchase. As discussed j in Chapter 6, the escrow arrangement is not even in the interest of DPC, since it would retard i reform of distribution, which is critical to raise revenue collection. However, as long as | escrows remain, privatisation will not be possible. The Committee therefore recommends that. as part of the negotiations, the current Escrow Agreement with DPC be cancelled. The security of future payments to DPC under the restructured tariff (and the security of payments -to other EPPs) will be based on increased cash flows from a reformed distribution system, which the Committee will address in Part-n of the Report.

This extent of financial restructuring will not be possible without the active co-operation, involvement and possibly financial support from GoM and Gol. The debt of DPC can be serviced only if MSEB makes timely payments as per the restructured tariff, which again will depend on timely payment of subsidies by GoM to MSEB. Similarly, given prudential guidelines, it may not be possible for existing domestic lenders to increase their exposure to DPC to the extent envisaged in case of a conversion to rupee debt. While it is correct to assure that existing lenders should suffer losses as a consequence of their inept due diligence with respect to the project; in order to attract new lenders, it may be necessary to provide suitable credit-enhancements for this debt. GoM and Gol both have extended guarantees and partial guarantees to DPC, which cover the entire project including the LNG facility. The restructured payments will be of substantially lower magnitude. The Committee therefore recommends that GoM and Gol guarantee, or otherwise credit-enhance, the restructured lending but only to the extent necessary, and limited to the extent of their current exposure to the project.

The reason for this is obvious from the discussion- in Chapter 7 and Box 14. This will lead to a reduction in the overall tariff by reducing the fuel charge. '

All the restructuring is designed to yield a tariff that will translate into a cost of supply that is affordable to the consumer. Therefore, the final tariff stream that emerges from the process, at realistic levels of PLF that may be as low as 30% in the initial years, is a critical determinant of the efficacy of the restructuring. It is important to subject this tariff to a full range of sensitivity analysis with respect to variables such as the exchange rate, fuel price, PLF, etc. The Committee recommends that this tariff be benchmarked to the lowest cost of supply of power from gas-based projects elsewhere and also to the willingness of other buyers such as other states and PTC to pay for the power. Such benchmarking is necessary to ensure that Dabhol power becomes saleable within and outside Maharashtra in a sustainable manner. This aspect is central to the whole process of negotiation with DPC. Without such benchmarking, any negotiation with DPC would prove futile.

In the opinion of the Committee, there are few opportunities for DPC to sell power outside MSEB, especially at current tariffs. However, the Committee has recommended a radical restructuring of the project. Within the terms of this restructuring, however, the restructured Hxed charge continues to be the responsibility of MSEB. This is being distributed over a low off-take in the initial years, and is resulting in a higher tariff. Sale of power outside MSEB will allow this fixed charge to be distributed over a larger base and thereby reduce the per unit tariff. While MSEB itself may be able to locate creditworthy buyers for such power, DPC may prove to be more successful in marketing than MSEB. The Committee therefore recommends that DPC be allowed to sell such power subject to the condition that: DPC designates a certain capacity for sale outside the MSEB system and the fixed charges on account of MSEB are reduced in proportion to this designated capacity.

Alternatively, DPC may find the conditions of restructuring too onerous and may believe it has prospects of earning better returns if it had the contractual freedom to sell power to other parties directly. If so, the Committee recommends that DPC could be allowed to sell power to any such parties, outside the MSEB system, as it may be able to find. but only if DPC then agrees to relieve MSEB of all its contractual obligations relating to- the power plant. The possibility and modalities of allowing power sales to third parties within the MSEB system will form part of the deliberations of the Committee for Part II of the Report.

8.5 Re-examine PPAs with All Other IPPs in accordance with a Least-Cost Plan

As noted by the Committee neither of the two IPPs, RPPL and CIPCO are today contractually structured to meet the needs of intermediate and peaking load in either MSEB or Maharashtra. In the opinion of the Committee, MSEB needs to justify its projections in more detail as to the type of demand before proceeding further with these projects. MSEB's procurement policy for power needs to be according to a least-cost plan and the Committee is aware that the MERC, which is the appropriate institution to determine whether the procurement conforms to such a plan or not, is seized of this matter. This will be addressed in greater detail in Part 11 of the Report. In the interim, allowing these IPPs to proceed, as currently structured, will only result in a problem similar to DPC re-emerging in future years. Therefore, the Committee recommends that MSEB defer all PPAs with IPPs and re-examine them in accordance with a Least-Cost Plan and in any case till such time the demand levels in the State permit full absorption of power generation from such IPPs.

The Committee would like to state strongly that none of the solutions espoused for IPPs in general and DPC in particular is tenable without the reform of MSEB, especially its distribution business, which it shall address in Part II of the Report. The Committee has already expressed its grave concern at the persistently high level of T&D loss. However, a clear recommendation from this part of the deliberations of the Committee, consistent with the earlier recommendation to cancel the Escrow Agreement with DPC, is:

An escrow arrangement transfers the primary claim on revenue stream from the Distribution Company to the IPP. In the context of privatisation of zones, most of the privatised regions can be expected to have cash losses in the initial years. The negative effect 6f an escrow on the already low cash flow stream that would be received by the prospective buyer makes it difficult to privatise a region that has been escrowed. Escrowing of specific zones thereby hinders the process of distribution privatisation and as long as escrows remain, privatisation may not prove possible.

Before concluding this report, the Committee would like to place on record its deep appreciation of the excellent work put in by the Infrastructure Development Finance Company, as secretariat to the Committee. Without their whole-hearted co-operation and strenuous work, the Committee would not have been able to complete its onerous task in such a short time.

(Dr. Madhav Godbole) (Shri Deepak Parekh) (Dr. E.A.S. Sarma) Chairman Member Member

' According to the Planning Commission (1996-97), the State has an annual average consumption of electricity of 556 units per person as against a national average of 334 units per person.

³ The letter from the World Bank dated July 26, 1993 mentions that MSEB had represented that the existing system was "projected to decline in efficiency" and that slippages in MSEB's least-cost programme had been "recently discovered''. See Box 9 in the text for further details.

⁴ During the year 1999-00, MSEB added 1000 MW of new capacity to its existing hydro complex at Koyna but MSEB is unable to utilise the entire 1920 MW capacity for longer periods during peak demand and its utilisation is limited to between 1200 to 1400 MW, depending upon the real time requirement of the grid. As for the Uran power station, it was developed on the basis of gas allocation received from ONGC fields in Bombay High area to the extent of 4.5 mmcmd (million metric cubic metres per day), which was confirmed by Gol in their original allocation, through its letter dated November 29. 1989. The gas supplied has since fallen from 3.16 mmcmd in the year 1995-96 to 2.24 mmcmd in 2000-01. This has mainly been due to gas production by ONGC below the level of 10 mmcmd in 2000-01, as compared to 15.76 mmcmd at the time of allocation. At gas production levels below 10 mmcmd, the gas allocation to MSEB would have worked out to 3 mmcmd, which would have allowed an additional generation of 1 158 MU. MSEB has also indicated to the Committee that the preference given in gas allocation to fertiliser companies by Gol has resulted in lower generation at Uran. Further, out of the original 4.5 mmcmd of gas allocation, MSEB vide its letter dated October 7, 1996, to the Ministry of Petroleum and Natural Gas agreed to transfer 1.4 mmcmd in favour of the winning bidder for the 410 MW Nagothane project, which was won by Reliance. The location for the project was subsequently changed to Paialganga, and it is one of the EPPs under consideration by the Committee. The logic for this give-away is difficult to fathom, particularly when the gas allocation had been obtained from Government of India with such long and arduous efforts. ,

⁵ Within Mumbai, Bombay Electric Supply and Transport Undertaking (BEST), a municipal body,. serves Greater Mumbai; Bombay Suburban Electric Supply Ltd (BSES) serves suburban Mumbai,;

while TEC has a bulk license for generation, transmission and distribution in and around Mumbai and' is allowed to serve all loads greater than 1 MVA. The Mula-Pravara Electric Co-operative Society;;

Limited serves parts of Ahmednagar District. MSEB serves Bhandup and Mulund areas of Mumbaii and the rest of Maharashtra. - : , a

⁶ The reallocation of unmetered consumption away from agriculture to commercial loss has results in^ an increase in the average agricultural tariff realisation. Despite this imbalance in tariff, over the.] period 1995-2000, the total income of MSEB has increased from Rs.7,386 crore (excluding subsidy! claimed of Rs.630 crore) to Rs.l 1,131 crore (excluding claimed subsidy of Rs.2084 crore). The] average realisation of Rs.l.71 per unit consumed. The average HT revenue realisation ofRs. 3.99 per ' unit in 1999-2000 is amongst the highest in the country. In part due to this burden of cross-subsidy ? and poor health of some key industrial segments such as textiles and steel, the total HT consumption I in the State has grown slowly. . :

Subsidy provided by Government of Maharashtra to MSEB is calculated as the revenue support J required over the revenue obtained from sale to consumers, to achieve a given rate of return on | MSEB's capital base, defined as the capital employed excluding loans and consumer deposits for| providing the services. While the Electricity Supply Act (1948) stipulates the minimum rate of return,! for SEBs to be achieved as only 3%, MSEB, in line with an earlier World Bank loan covenant has, been maintaining that the applicable return is 4.5%. However, most of these subsidy claims fromt

GoM remain unrealised, as shown in the Tabife below, which details the subsidy paid by GoM to

^s Of the total power purchased, 21% is purchased from DPC but of the total payments to power suppliers, 37% is to DPC, implying that DPC power is priced 1.76 times higher than the average cost of purchased power. Over this period, the total purchase of power by MSEB increased by 2785 MU. Of this, purchases from DPC increased (this was the first year of commercial operation for DPC) by 3623 MU and concomitantly, purchases from TEC-reduced by 507 MU, from NTPC by 303 MU, NPC by 65 MU, BSES by 10 MU and cogeneration by 8 MU.

'' The number of IP sets used were 1.98 mn., 2.04 mn., 2.11 mn., and 2.16 mn, for 1996, 1997, 1998 and 1999 respectively.

"This has happened earlier already. The Central Government during October 1998 to July 1999 deducted Rs.62.05 crore from the Central Assistance for the annual plan of State of Maharashtra, due to MSEB's failure to clear the dues, and paid the amounts directly to NTPC, NPC, subsidiaries of Coal India Limited and Railways. This has affected development programmes of the State.

" If the estimated T&D loss of 38.82% of 2000-01 is used, this would be higher. ^1; MSEB added 1370 MW. The rest was added by DPC, TEC and BSES.

¹¹ RPPL is entitled to sell additional energy available over 68.5% to Reliance group companies in Maharashtra in the event the energy off-take by MSEB is lower than the contracted quantity of the plant or RPPL is not entitled to receive incentive payments.

In an interview, published in Economic Times entitled "Stand Up for India" on June 11, 1996, the then Finance Minister stated as follows: "First, the Constitution makes no difference between a government that is to win a vote of confidence and one which has obtained it. Second, the Cabinet Committee on Foreign Investment (CCFf) had approved of the revised PPA on 30 April 1996. We were sworn to office on 16 May. I was given charge of the finance portfolio on the I7th. By the time I was seized of the impending issues, it was about the 22nd or 23rd. But from the first of May, the clock of delay costs, to be shared between the Maharashtra State government and the Centre, started. licking. If by May 1, all the formalities were not cleared, delay would cost around $25,000 per day. One was to curtail this avoidable loss. The other was the matter of automatic arbitration, early in June, if settlement had not been reached. All we had to do was to confirm the decision of the CCFI of the previous government. We decided to meet as a full Cabinet. We decided that notwithstanding the enhanced production capacity', the counter guarantee remains unalterably fixed. The government's exposure is limited to this cap. The gains would be lower delay cost, avoiding arbitrage and power for India. We acted impeccably, and in trying to save costs, we acted in the national interest."

An additional investment of US$ 35 million was required to make it a multi-fuel plant, as recommended by the Group, without increasing the tariff, thereby increasing the total cost to US$ 2.87 billion.

¹⁶ In 1994-95, a new type of gas turbine i.e. 9 FA was introduced by GE. The fact that this change was minor and design-related is also seen from CEA's counter-affidavit on July 1, 1996 in the CITU case.

¹⁸ The benefit of this reduction in cost, small though it is, is not being passed on, as, according to DPC. the reduction in capital cost would be considered on a overall project cost basis, and not on a individual basis for the capital cost adjustment in tariff as per Schedule 9, Part XIV of the PPA.

¹⁹ The Group noted "while a tariff profile is agreed upon, any other time profile oftariff'acceptable to MSEB can also be agreed upon as long as it gives the same IRR on equity as given by the present levelised tariff'. The Group also questioned the need for a Fuel Management Agreement separate from the O&M Agreement, and a distinct fee of US $ 2.5 million, but allowed the same, as it would mitigate the risk undertaken by DPC to ensure fuel availability for 90% plant load factor. It was noted that the same convention was followed in other transactions in China and Pakistan. The Group also said that the lenders would require such comfort. However, all features of the Fuel Management Agreement could also be provided under the O&M Agreement. The relevant question was whether the additional compensation was appropriate, and the Group appears to have decided it was.

²⁰ Article by Dr. Kirit S. Parikh, member of the Negotiating Group entitled "Levelised Tariff and the Dabhol Agreement"', in the Times of India dated 4 February 1996, and the Summary Report.

²¹ This was pointed out at that time by Mr. S. Venkitaramanan, former RBI Governor in a Times of India article entitled "Interest is the Great Leveller" dated 4^th February, 1996, where he suggested that "the prevailing exchange rate should be used and tariff matrix needs to be provided based on various kev assumptions such as the exchange rate movement and fuel price movements and the same would provide a more realistic view". He also indicated that a discount rate equal to then prevalent rupee interest rate of 17% was inappropriately high, when the tariff components were predominantly dollar denominated.

²² There is little data in the Summary Report to substantiate this. It contains only a daily log sheet of October 31, 1995, (Annexure X in the Summary Report) which indicates that the base load energy .a factor for the day was only 84.73%. ^

²³ The Group's recommendation on the usage of indigenous naphtha instead of imported distillate to ^l;

reduce the foreign exchange outflow was referred to CEA, which observed vide its letter dated April 17^th 1996 that the same was a minor modification and did not require its approval. ',

²⁴ Initially, Glencore was chosen on a global tender basis. Recently, as the government did not extend the import license, DPC negotiated with IOCL for supply of naphtha on import parity basis. This gave rise to a price differential of around $12 to $15 per tonne, or about 28 to 35 4- per mmbtu. ^\

⁵ MPDCL also assumed the rights / obligations of the promoters shareholders of DPC on a pari-passu., basis, by agreeing to pledge its shareholding to the lenders, provide completion support guarantees /^| liquidated letter of credits as required in the financing agreements.

²⁶ Order by Justice A.P. Shah on July 27, 1994 in writ petition number 2735 of 1994.

⁷ S. Venkitaramanan, Interest Is The Great Leveller, The Times of India, 4 February 1996 referred to in note 21 above.

²⁸ The bill for October 2000, amounting to Rs. 114 crore, was paid finally on January 9, 2001, from the contingency funds of GoM.

²⁹ These are No. 1702 of 1994 (Ramdas Nayak and V.P. Sahasrabuddhe vs. DPC and others) and No. 2416 of 1996 (CITU and Abhay Mehta vs. DPC and others). In the first, the Court ruled that the Government had the right to enter into negotiated contracts and in the second, the main plaintiff, the

State of Maharashtra, withdrew their case after submitting that it had filed the case in order to exert pressure on Enron to renegotiate the DPC power purchase agreement.

'° The 1992 price was conditional on some tax concessions, which may not have been obtained. But this is unlikely to be so large as to justify an additional payment of over $ 100 million a year. Furthermore, since the 1994 price was based on distillate and the 1992 price was based on natural gas, there is an issue concerning the difference made be varying heat rates for the two fuels. However, the benchmark price of natural gas when the price of distillate was $ 4.3/mmbtu would be lower. It has also been argued that the final PPA allocated a number of risks to DPC, such as financial risk, fuel availability risk, delay penalties, operating penalties, O&M obligations and penalties for cheating, peak and off-peak variations in off-take to the extent of 86% in monsoon and 92% otherwise, comprehensive termination events and the right to purchase the plant at a concessional price. None of these are any different from normal risks borne by any power project developer. In addition, DPC has a separate charge for O&M obligations, it has a separate fuel management fee to defray the fuel availability risk and it is considered usual to include penalties for cheating in any contract.

'' These statements are based on documents stated to be the minutes of the meetings submitted by respondents to the Committee.

''' The clearance was accorded subject to the following conditions, "State Govt's approval to M/s. DPC to establish, operate and maintain the power plant;

Before starting Phase-11 of the project, Maharashtra GovtJMSEB will ensure that the entire power from the project including off-peak surpluses will be absorbed within the Maharashtra system or if necessary, by entering into agreements with entities outside Maharashtra;

MSEB will ensure completion of associated transmission system matching with the commissioning schedule of the project.

³⁵ At 90% PLF, 94% of the tariff is linked to the dollar. There are a number of other smaller changes.

³⁷ These statements are based on documents stated to be the relevant letters that were submitted by respondents to the Committee.

³⁹ LNG is manufactured by trains (production units) that have steadily increased in size from 0.4 mtpa to 3 mtpa, and decreased in cost. Nigeria's planned two-train facility with a capacity of 5.8 mpta is expected to cost $US 3.8 billion, half of what it would have cost in the 1980s. New technologies like the Phillips Cascade have helped to lower costs and increase competition. A multitude of EPC contractors are now bidding on construction of LNG plants as opposed to only 2-3 in past years. The production of an LNG facility is fairly flexible, and can occasionally reach 150% of nameplate capacity. Recently, Faisal Mohammed al-Suwaidi, vice chairman ofQatargas said (MENA Petroleum Bulletin April 2000, No. 13):, "Our three train plant has a capacity- of 6mtpa but, through de-bottlenecking, we will be able to produce an additional 3ml/y of LNG. This is like a new train"

Approximately 40 different energy companies now have interests in existing or planned LNG export projects. As compared to a time when only three or four "majors" could be a lead sponsor of an LNG project; more than a dozen companies now vie for the lead sponsor role. Indonesia, Malaysia and Brunei, now account for 60%, of LNG exports, Algeria 20%, and the Middle East and Australia 10% each though new exporters such as Nigeria are fast emerging. The buyers are heavily concentrated in Asia, which accounts for 75% of imports, of which Japan itself is 57%( within Japan, the big three Japanese utilities-Tokyo Gas Co. Ltd., Osaka Gas Co. Ltd.. and Toho Gas Co. Ltd.-account for more than 75% of the country's gas sales.), with Korea at 14% Taiwan at 4%. Europe, principally France (8%), Spain (6%) and Belgium (4%), takes 22% of imports. The rest is shared among various countries, principally the US (2%). By 2010 there will be lots of new potential for supply, including Nigeria, Trinidad, Egypt and the Middle East in the Atlantic Basin exceeding the demands of Japan, Korea, Taiwan and India. Coupled with deregulation and liberalisation the market will be characterised by uncertainty amongst potential buyers. Increasingly they are reluctant to commit tn long-term take-or-pay contracts.

⁴¹ In December 1998, Dabhol signed a sales and purchase agreement with Oman LNG for 1 6 mtpa and with ADGAS for 0.5 mtpa for their 5 mtpa project. In mid-1999 RasGas signed a sa'es and purchase agreement with Petronet of India for 7.5 mtpa, of which 5 is to be delivered by 2003 to Dahej and the rest by 2005 to Cochin. These are the early birds. In development are TEC and Total's 3 mtpa project at Trombay, DBEC's 2.5 mtpa project at Ennore, British Gas' proposal to build a 5 mtpa terminal at Pipavav and the Government ofbrissa's agreement with the Al Manhal International Group to build a 5 mtpa project at Gopalpur, based on supplies from Australia LNG. The Heads of Agreement'for this project was signed in December 1999, for sales of 5 mtpa from 2004. In addition. Indian Oil is planning a 3 mtpa facility at Kakinada and Reliance Industries has already obtained FIPB clearance for two 5 mtpa terminals, one at Jamnagar and the other at Hazira. This amounts to a total of 41 mtpa of terminal c-.'pacity.

⁴² Pertamina of Indonesia is . onsidering offering 5 to 10 year contracts to its traditi 'nal markets in Japan, Korea and Taiwan a', these countries are after more flexibility rather tha.i being overly committed with the 20 year cciitracts. This reflects the ample availability of supply. P. ten & Partners estimate that there could be an estimated 9.5mt of spare capacity in 2002 but may be restricted by the availability of tankers. For years, Enron has been one of the biggest proponents of the development of a different LNG market, stating that in its view "market intermediaries which bring needed risk management and aggregation skills to this chain, and which are willing to participate in the significant equity cost of developing LNG supplies and markets, can be invaluable in ensuring the growth of LNG in the new inillennimn."(Ele,venth International Conference & Exhibition on Liquefied Natural Gas, Paper 1.7 Birmingham, England 1995) Even Japanese buyers are now moving to the spot market. Says President Hideharu Uehara of Tokyo Gas (Tokyo Gas Investors' Guide 2000):

"Specifically, we have placed orders for two LNG tankers, which will be wholly owned by Tokyo Gas and will allow us to reduce transportation costs and take better advantage of the LNG spot market". Even Seai-le of Oman LNG, DPC's current supplier recognises this (MENA Petroleum Bulletin April 2000, No. 13); "All our experience tells us that deregulation is good for marke' growth in the long term. Suppliers will need to be more innovative and more flexible in the future. At the ''same time buyers will need to remember that new LNG developments and expansions of existing capacity will continue to require major financial investments that in turn will need security of market and income to support them. Therefore long term relationships will continue to be a major feature even if long tenii contracts are not"

⁴³ "Gas Import Options for India" by Rahul Deep Singh (TERI) and "India's LNG Industry - The Challenges that lie ahead" by Ravi Suri (Project Finance International. July 99) The difference in two

analyses comes from differing assumptions about the CCGT plant and its comparator coal plant, e.g., their capital cost, the cost of coal and other assumptions such as the calorific value and the heat rate.

⁴⁴ For example to Chubu Electric Company (Chubu) act as the co-ordinator on behalf of eight Japanese utility companies, to whom Qatargas is supplying 6mtpa of LNG.

⁴⁵ Oman LNG has signed 25-year long-term sales agreements with KOGAS (4.1 mtpa) and Osaka Gas (0.7 mtpa) and a further 20-year contract with Dabhol Power (1.6mtpa). Its MD, Graham Searle said in a recent interview (MENA Petroleum Bulletin April 2000, No. 13) says that, "From 2002 onwards these contracts will consume the full nameplate capacity' of the plant. Forward selling the nameplate capacity does wonders for the project's economics, but the downside is that the plant must be extremely reliable, as we do not have 20-30% spare capacity to fall back on. We are confident that we can achieve 96% uptime."

⁴⁶ Rick Bergsieker, -President and chief operating officer of Enron Global LNG recently told Natural Gas Week. (September 4, 2000):"/ don't think it will be a problem getting supplies. Any of the big Mideast projects that have build-up schedules will have gas available. The only constraint is shipping" [emphasis added]

⁴⁷ In 1998, Thailand effectively cancelled its 2.2 mpta agreement with Oman LNG &long with another from Indonesia. The contract reportedly proposed to buy Omani LNG at a price indexed a basket of alternative power fuels; primarily coal, as opposed to an oil price index.

⁴⁸ "Financing in a deregulating market - SembCogen" Project Finance International, Issue No. 212. March 7, 2001

⁴⁹ As Richard J. Gilbert and David M. Newbery (The Dynamic Efficiency of Regulatory Constitutions, Rand Journal of Economics, Vol. 25, No. 4. Winter 1994.), have brought out, regulatory commissions have rarely strayed far from the principle that a utility is entitled to a rate of return approximately equal to its cost of capital. Instead, the focus of regulatory conflict has been on the assets that should be included in the rate base. This conflict assumed critical proportions in the 1980s, following large cost overruns and excess capacity from utility construction programmes, particularly nuclear and supercritical coal plants. Between 1980 and 1988, state commissions disallowed over $10 billion in utility investment in nuclear projects. In determining the assets that should be included in a utility's rate base, state regulatory commissions considered whether the management of the construction programmes followed norms of prudent business behaviour and whether there was an economic need for the capacity that was built. Both considerations, and particularly the latter, drew on the standard that customers are obligated to pay only for capital that is "used and useful". On this background, it is abundantly clear that DPC project under discussion may not have been cleared even in Enron's home base in the United States, and even if the work had been started thereon, it would have been asked to be discontinued by the electricity regulator.

⁵⁰ On at least two occasions the importing country's government has, after much debate, been unwilling to approve the necessary facilities to import LNG. The first instance occurred in Los Angeles in the early 1980s. The second happened in Italy in 1996 when the Italian state electricity utility, ENEL, decided not to build an LNG receiving terminal on the coast ofTuscany and attempted to canceled its LNG sales contract with Nigeria LNG Ltd. Thereafter, Nigeria LNG brought a breach of contract suit against ENEL for $13 billion in damages (reportedly the largest claim ever brought under English law). ENEL claimed the force majeure clause of the contract allowed it to cancel the contract due to increased expenses associated with compliance with environmental conditions for the LNG receiving terminal. Fortunately, the case was quickly settled, with the parties agreeing that the Nigerian LNG would be shipped to France instead, in exchange for Russian gas diverted by French buyers to Italy. (International Litigation News by Euromoney Publications 1998).

Phase I (DPC Tariff Vs Gol notification tariff) ( Heat rates identical, rupee depreciation 5%)) '

Phase I ( DPC Tariff Vs Gol Notification tariff) ( Heat rates identical, rupee depreciation 5%, pit 68.5%)

Phase I ( DPC Tariff Vs Gol Notification tariff) ( Heat rates identical, no rupee depreciation , plf68.5%)