Mumbai High Uran Trunk Pipeline (MUTP) Project

Mumbai High Uran Trunk Pipeline (MUTP) Project - Financial appraisal

http://www.infraline.com – Your Information Gateway to Indian Energy Sector 1

Mumbai High Uran Trunk Pipeline (MUTP) Project – Financial appraisal Preamble Oil and Natural Gas Corporation Limited (ONGC) was set up as a Directorate on August 14,1956 with an objective to explore and exploit oil and Natural gas reserves in various parts of the country. ONGC became a corporate on June 23, 1993, which has now grown into a full-fledged horizontally integrated petroleum company. Today, ONGC is a flagship public sector enterprise and India’s highest profit making corporate.

Western Offshore fields of ONGC mainly consist of major field like Mumbai High, Heera & Neelam and Bassein and other discoveries like B-55, B-121, B-46, PSE etc. Mumbai High field is situated 160 kms west-north-west of Mumbai city in the Arabian sea on the continental shelf of Arabian Sea in about 80 metre of water depth. Mumbai High field, the major producer, was discovered in 1974. This is the biggest oil field discovered in India having an aerial extent of about 1200 sq. km and having in place oil reserve of about 1541.41 Million Metric Tons (MMT) and initial gas cap reserve of about 114.6 Billion Cubic Metres (BCM).

Presently Crude Oil and Natural Gas produced at various offshore platforms of ONGC at Mumbai High is transported to Uran Plant through Bombay High to Uran Trunk (BUT) Pipeline system. The two major trunk pipelines lines of 204 Km each, called BUT lines, for evacuation of oil (30” dia) and gas (26” dia) respectively were installed during 1977-78. The pipelines originate from BHF platform in BHN complex of Mumbai High. Oil and Gas from other process complexes, viz NQ, BHS, SH, IC, BPA etc. are evacuated into the BUT Pipelines through a network of feeder pipelines. These BUT pipelines have already completed more than 25 years of successful operation and have surpassed their designed life. Recently there were two leakages in 30” oil trunk pipelines during August and September 2003. ONGC, in September 2003, had taken up a Residual Life assessment study through Engineers India Ltd (EIL) which indicated that that the existing trunk pipelines would be insufficient to transport the expected production of oil and gas beyond 2005.

With a view to avoid the future uncertainties relating to transportation bottlenecks arising out of continued use of existing pipelines and to provide for future developments, ONGC proposes of laying of new Trunk Pipelines from Mumbai High to Uran, named as “Mumbai High Uran Trunk Pipelines” and the main objectives for replacing the old pipelines are summarized below:

(i) To transport the existing and incremental production of re-development till 2030.

(ii) To explore and exploit prospective locations beyond Southern & Western flanks of Mumbai High.

(iii) To provide for transportation of oil & gas produced from following future marginal fields

gas from structure B-46, B-48, B-121 and C-series Field

oil from B-192, Bassein East, B-l78, B-179, B-180 and B-193

(iv) To provide for transportation of oil & gas produced from:

alternate evacuation from Panna-Mukta(JV Field)

future deepwater prospects of west coast.

(v) To avoid further leakages in oil pipe lines and ensure production levels envisaged without any toss due to transportation constraints

(v) To ensure continuous availability of pipeline for transport of gas beyond 2005

The current estimate of the entire Mumbai High Uran Trunk Pipeline” (MUTP) project works out to Rs. 3,418.08 crore. The MUTP project is planned to be completed by May 2005 i.e over a period of 16 months.



ONGC proposes to seek investment approval of its Board of Directors for the above project. This report has been prepared by the Merchant Banking & Corporate Advisory Department (MB & CASD) of the Industrial Development of India to carry out the Financial & Technical (Optimisation of Cost & Facilities) appraisal and the need for laying the new Mumbai High Uran Trunk Pipeline and benefits thereof.

Section – I

Promoter/Company Assessment I. Background Of ONGC

ONGC was set up in August 1956 as Oil and Natural Gas Directorate by Government of India as a part of the Public Sector development with the objective to explore and exploit oil and natural gas resources in the various regions of the country. In 1959 the status of the Oil and Natural Gas Directorate was changed to “Oil and Natural Gas Commission”, a Statutory body, with the main function to plan, promote, organize and implement programmes for development of petroleum resources and the production and sale of petroleum and petroleum products. Government of India in February 1994 transferred the assets and liabilities of Oil and Natural Gas Commission to ONGC Limited, a company incorporated under the Companies Act, 1956.

ONGC has now grown into a full-fledged horizontally integrated petroleum company and has produced more than 600 million metric tonnes of crude oil and supplied more than 200 billion cubic metres of gas since its inception, thus fuelling the increasing energy requirements of the Indian economy.

Presently, ONGC is a premier public sector enterprise with significant contribution to industrial and economic growth of the country, contributing 77 percent of India’s crude oil production and 81 percent of India’s natural gas production. It is India’s highest profit making corporate earning a net profit of Rs. 10,529 crore during the year ended March 31, 2003. ONGC is ranked 326 in Financial Times Global 500 list by market cap; first among Indian corporate. ONGC is the only PSU, which has both positive Market Value Addition (MVA) and Economic Value Addition (EVA). The company has recently been awarded by 1 National Award for excellence in Corporate Governance, 2003.

ONGC has taken over Mangalore Refinery and Petrochemicals Ltd. (MRPL) from the A V Birla Group and has also entered the global field through its subsidiary, ONGC Videsh Ltd. (OVL). The company has made major investments in Vietnam, Sakhalin and Sudan.

II. Sharerolding Patfern

The shareholding pattern of ONOC as on 31 ‘ March, 2003 is as under:

Sl. No.

Name of the holders No. of shares Percentage of shareholding

1. Government of India 1,19,93,39,605 84.11 2. Mutual fund and UTI 1,79,55,787 1.26

3.

Banks, Financial Institutions, Insurance companies (Central/State Govt.Instts./Non-Govt. Institutions)

1,29,40,644 0.91

4. FII’s 65,04,475 0.45 5. Private Corporate Bodies 7,51,523 0.05 6. Indian Public 1,70,55,420 1.20



7. NRI’s/OCB 52,312 0.00 8. Indian Oil Corporation Ltd. 13,70,67,381 9.62 9. Gas Authority of India Ltd. 3,42,66,845 2.40

• During March 1999, ONGC, Indian Oil Corporation (IOC) - a downstream giant and Gas Authority of India Limited (GAIL) agreed to have cross holding in each other’s stock. Consequent to this the Government sold off 9.62 per cent of its share holding in ONGC to IOC and 2.4 per cent to GAIL. With this, the Government holding in ONGC came down to 84.11 per cent.

Ill. Management Structure

The company is managed by a Board having 15 directors comprising of Chairman and Managing Director, six functional directors, three nominees of Government of India and five independent Directors. The Board is broad based. The Functional Directors are supported by a well qualified team of professionals in their respective fields to carry out day to day operations. The organisation structure of ONGC is well defined with the day to day affairs monitored and reported to the directors and executive directors. The present composition of the Board of ONGC is given below:

SI. No. Name

Chairman and Managing Director 1. Shri Subir Raha(Functional Directors) 2. Shri R.C. Gourh (Onshore) 3. Shri Y.B. Sinha (Exploration) 4. Shri V.K. Sharma (Offshore)

5. Shri Nathu Lal (T&FS)

6. Shri R.S. Sharma (Finance)

7. Dr. A.K. Balyan (Human Resources)

Government Directors

8. Shri B.K.Das, Additional Secretary & Financial Advisor, MoPNG

9. Shri P.K. Deb, Joint Secretary (Ministry of Finance)

10. Shri J.M.Mauskar, Joint Secretary (Exploration), MoPNG

Non - Official Directors

11. Shri U.Sundararajan

12. Shri M.M.Chitale

13. Shri Rajesh V.Shah

14. Shri N K.Nayyar

15. Shri Atul Chandra



IV. Organisation Structure

The organisation structure of ONGC is well defined with the day to day affairs monitored and reported to the directors and executive directors. The CMD is the overall in charge of the operations. The organisation chart o has been depicted below;

V. Financial Performance

The working results for the past three financial years ended March 31, 2003 and the unaudited results for the half year ended September 30, 2003 and the financial position of ONGC is furnished at Annexure I and the summary thereof is as under:

Working Results

Rs. in crore For the year ended March 31 2001 2002 2003 Sept. 30, 2003

I. Physical Quantity Sold 23.38 22.86 23.90 11.68 -Natural Gas (MMM3) 20,501 20,446 21,110 10,594 -LPG (000' Tonnes) 1.211 1.157 1,198 588 -NGL/Naphtha 223 314 365 263



- Ethane/Propane (000' Tonnes) 570 528 619 283 -Aromatic Rich Naphtha (000' Tonnes 1.291 1.367 1.277 607

-Superior Kerosene Oil (000' Tonnes) 221 231 234 116

II. Financial Gross Sales 24,225 23,857 35,365 16,172 Interest receipt 862 1,014 1,332 714 Increase in stock 45 0.2 21 (20) Total Income 25,132 24,871 36,718 17,406 Operating, Selling & General Expenses 11,124 10,953 16,354 7,320

Interest 398 247 113 14 Recouped cost (Depletion, Depreciation, Amortization) 4,453 3,816 4,128 2,269

Total Expenses 15,975 15,016 20,595 9,603 PBT 9,157 9,855 16,123 7,803 Tax 3,928 3,657 5,594 2,844 PAT 5,229 6,198 10,529 4,959 Dividend & Dividend Tax 1,728 1,996 4,516 - Net cash accruals 7,954 8,018 10,141 7,228 RONW (%) 17.34 21.0 29.57 -

Financial Position

Rs. in crore As at March 31 2001 2002 2003 Liabilities Equity Capital 1,426 1,426 1,426 Reserves& Surplus 28,885 28,296 34,313 Less: Misc Expenses not written of 163 210 131

Net worth 30,148 29,512 35,608 Assets Net Fixed Assets 5,889 5,601 5,393 Producing Properties 16,005 16,380 17,111 Capital WIP 728 690 933 Exploratory Wells in progress 935 978 1073

23,557 23,649 24,510 Investments 2,360 3,323 3,983 Net Current Assets 8,213 10,925 12,713 Total Assets 34,130 37,897 41,206 Long term liabilities



Loan-Oil Industry Development Board 141 121 101

Foreign Currency Loans 3,841 2,917 262

Deferred Tax Liability - 5,347 5,235

Total debt 3,982 8,385 5,598 Net worth 30,148 29,512 35,608 Debt Equity Ratio 0.13 0.28 0.16

• The net worth of the company has improved constantly except during 200 1-2002 Was on account of provision for deferred tax liabilities.

• Investments of the company consist of trade-non trade investment like equity shares in Indian Oil Corporation, Gas Authority of India Limited and in subsidiary viz Mangalore Refinery and Petrochemicals Ltd and ONGC-Videsh Ltd. and Govt. of India special bonds. During the year 2002-2003 investments has increased due to acquisition of shares of MRPL.

Plant Locations / Assets / Major Projects A. Assets / Plants

The list of major Assets and Plants of ONGC are located at:

• Mumbai High Asset, Mumbai • Neelam & Heera Asset, Mumbai • Bassein & Satellite Asset Mumbai • Uran Plant, Uran, Maharashtra • Hazira Plant, Hazira • Ahmedabad Asset, Ahmedabad • Ankleshwar Asset, Ankleshwar • Mehsana Asset, Mebsana • Rajamundhry Asset, Rajamundhry • Karaikal Asset, Karaikal • Assam asset, Nazira • Tripura Asset, Agartala

B. Basins

The list of Basins of ONGC is as follows:

• Western Offshore Basin, Mumbai • Western Onshore Basin, Baroda • KG Basin, Rajamundhry • Cauveiy Basin, Chennai • Assam & Assam Arakan Basin, Jorhat • CBM - BMP Basin, Kolkita • Frontier Basin, Dehradun

Thus, it may be observed from the above that ONGC has presence in almost all the strategic locations in oil and gas in the country and has a well built up infrastructure in place.



Joint ventures

i) Petronet LNG Ltd. (PLL)

ONGC along with IOCL, GAIL and BPCL has contributed Rs. 100 crore towards 12.5% equity of PLL and also extended guarantees worth Rs.1400 crore along with other founder co-promoters to P till execution of General Sale/Purchase Agreement (GSPA) by PLL with their supplier, M/s, Ras Gas of Qatar. The construction of the LNG terminal at Dahej is on schedule except for a delay in construction of the breakwater for the jetty, which will, however, riot affect commissioning of the terminal on schedule. The first LNG cargo is expected at Dahej in December 2003 for commissioning trials.

While the other founder co-promoters share the marketing rights of re-gassified LNG from I it has been decided by the Ministry of Petroleum & Natural Gas, as well as the Board of PLL, that a project for extraction of value-added components (C plus) from the LNG has been assigned to ONGC. The company has initiated preparatory work on this project. With this decision, ONGC will add to its Natural Gas value-extraction projects.

ii) Petronet MHB Limited

ONGC has acquired 23% equity at a cost of-Rs. 38.34 crore, in Petronet MHB Ltd. The 364 km long cross-country pipeline from Mangalore refinery to Bangalore via Hassan has already been commissioned on 1st August, 2003. MHBPL will carry MRPL white-oil products, offering advantages in freight, reliability and quality in the hinterland.

iii) ONG International Private Ltd.

This 50:50 JV with Indian Oil Corporation Ltd. (IOCL) was incorporated on 8th June, 2001; the Company has incurred cumulative losses of Rs. 20.56 million and it has been decided by ONGC Board of Directors to withdraw from the JV and it is to be dissolved. Subsidiary Companies

(i) ONGC Videsh Ltd. (OVL):

ONGC has entered the global field through its subsidiary OVL and has become a world-class Oil and Gas Company integrated in energy business with domain Indian leadership and global presence. OVL is the wholly owned subsidiary and achieved a number of landmarks as under

• First revenue from sale of hydrocarbons, in Block 06.1, Vietnam; • First participating interest in a producing property, in the Greater Nile Oil Project, Sudan. • First exploration and development contract as operator, in Farsi Project, Iran.

Besides, OVL acquired interests in Sakhlain-I, Russia and exploration block in Ira

ii) Mangalore Refinery and Petrochemicals Ltd. (MRPL)

ONGC has acquired the entire 37.39% equity held by the Indian Rayon and Industries Ltd. (IRlL) and its associates in March, 2065. Consequent to the preferential allotment of 60 crore-equity shares in March 2003, as approved by the MRPL shareholders, ONGC’s shareholding increased to 51.25% making MRPL a subsidiary of ONGC and further on exercise of the call option incorporated in the debt-restructuring package, ONGC’s shareholding has increased to 71.62% on 11th July 2003.



With the approval from the Ministry of Petroleum & Natural Gas (MoPNG), an Empowered Standing Committee (ESC) for crude oil imports has been constituted for MRPL. MRPL will now be able to directly execute crude purchase contracts under Government-to-Government arrangements, saving on the commission charged by canalizing agency. MRPL has been marketing Motor Spirit, High Speed Diesel, LPG cooking gas and Superior Kerosene through Hindustan Petroleum Corporation Ltd. (HPCL), who have agreed to maintain the support in line with the Shareholders’ Agreement between ONGC and HPCL. Transport fuels produced by MRFL will be retailed under the Marketing Rights granted to ONGC.

Mangalore-Hassan-Bangalore Pipeline project has been commissioned on 1 August, 2003. This Pipeline will reduce transportation cost of the while-oil products of MRPL in the hinterland areas and expand the economic supply envelope.

The operating performance of MRPL has shown improvement, but the financial results of MRPL continued to be impaired due to high interest and depreciation cost, low capacity utilization and low ‘gross refinery margins’ mainly due to lower domestic product demand/sales, lower realization in exports and relatively high prices paid on crude entirely sourced through imports. Due to ONGC exercising exclusive control on MRPL, the company has already been turned around.

VII. Overall Promoter Assessment -

• ONGC is a profit—making, dividend paying company owned by Government of India, enjoying a premier position in the industry both nationally and internationally.

• ONGC has rich experience in the field of oil and gas exploration and exploitation of the resources.

• ONGC has already laid more than 3000 kms of offshore pipelines in the Mumbai High itself and has good experience in implementing and managing similar projects.

• ONGC has sufficient free cash-flows for mobilizing the requisite resources for the project.

Section – II Financial Assessment

I. Mumbai High Asset (MHA)

Western Offshore fields of ONGC mainly consist of major fields like Mumbai High, Heera & Neelam and Bassein and other smaller discoveries. Mumbai High Field (MHF) is situated 160 Kms west-north-west of Mumbai city in the Arabian Sea in about 80 metres of water depth. MHF is the biggest oil field discovered in India (in 1974) having an aerial extent of about 1200 Sq. kms and having in place oil reserve of about 1541.40 MMT and initial cap reserve of about 114.6 BCM. Details of existing Oil & Gas Pipeline System

At present crude oil and natural gas produced at various offshore platform of ONGC at MHF is transported to Uran Plant through the Mumbai High-Ui-an Trunk pipeline (MUTP) system. The two major trunk lines (Oil and Gas) of 204 1cm each and having 30” Diameter for Oil and 26” diameter for Gas pipeline were installed during 1977-78 by M/s. Brown & Root International Ltd (UK) and are in operation since then. These existing MUTP have already completed more than 25 year of successful operation and surpassed their designed life.

The existing MUT oil pipeline was originally designed for throughput of 4,05,000 BOPD but on account of deposition of wax its transportation capacity has declined to 2,17,000 BOPD, as against the peak oil flow 3,80,000 (approx.) envisaged based on the projected production profile in the year 2006-07. On the other



hand, the MUT gas pipeline was designed for a flow rate of 12.5 MMSCMI) whereas based on the projected production profile a peak flow rate of 15.95 MMSCMJ) of gas is expected in the year 2006-07.

The details of commissioning schedule are as under;

Mumbai High Asset

Length /Dimensions

Date of commercial operation

Cumulative Running Hours (as on September 30, 2003)

Mumbai High Uran Trunk Oil Pipeline

204 km /30" dia 1978 Over 2,00,000 hours (designed life of 25 years surpassed in June` 2003)

Mumbai High Uran Trunk Gas Pipeline

204 km /26" dia 1978 -do -

II. Performance of MHA

Physical Performance

The historical performance of MHA has been satisfactory. The details of the physical performance of the MHA oilfields for the past three years ended March 31, 2003 is as under.

For The Year Ending March 31, 2001 2002 2003 Crude oil production (MMT) 10,19 9.82 11.38 Natural Gas Production (BCM) 5.16 5.00 5.29 Crude oil Sales (MMT) 9.83 9.26 10.63 Natural Gas Sales( BCM) 3.21 2.75 2.99

Financial Performance

The summary financial performance of the MBA for the past three years ended March 31, 2003 is as under:

For the year ending March 31

2001 2002 2003

Gross Sales revenue 6657 6421 12445 Less: Statutory levies 2035 2126 3566 Operating expenses 1716 1519 1520 Depreciation/depletion 685 581 752 Provisions 240 179 875 Operating Profit 1986 2015 5732

The improvement in gross sales and profitability in FY 2002-03 it on account of increased production and substantial increase in prices of oil post APM.

The oil and gas pipelines of the Mumbai High Asset through which the oil and gas is evacuated and transported to Uran has already approached the final phase of the service life as is evident from the recent ruptures and breakdown on two occasions in the Oil pipeline in the last couple of months and the



resultant increase in the O&M expenses. In order to achieve consistent efficient operations ONOC proposes to undertake the laying of new replacement of the existing Oil & Gas Pipeline, which would enable the Mumbai offshore oilfields to maintain its performance.

IV. Replacement of MUT Oil & Gas Pipelines Project

Need & Objectives

(i) The existing M pipelines (both Oil & Gas) presently transporting oil & gas from Western Offshore to Uran and Hazira on-shore terminals have already surpassed their designed life of 25 years (expired in June’2003);

(ii) Recently two leakage have taken place in the 30” MUT oil pipeline as detailed below:

• The oil pipeline got ruptured on August 10, 2003 at a distance of about 1 Km from the originating platform and two pipe sections had to be replaced with hydraulic connectors throwing the supply of oil out of gear for approximately 40 days. To meet the contingency, additional tankers had to be mobilised to makeup the production loss apart from diverting oil through alternate ICP-Heera trunk pipeline.

• Subsequently, on September 14, 2003 a hole was detected within a distance of 4 Kms from Uran end which had to be repaired by installation of a subsea clamp.

(iii) Redevelopment projects in Mumbai High Field arc under implementation which would add to the existing oil & oil equivalent gas production levels. Due to this, the recovery is expected to be achieved by more than 30% by the year 2030. Hence, the MHF has a residual life of more than 25 years which presents a strong case for replacement of the existing oil and gas transport pipelines.

(iv) Deposition of wax inside the 30” oil pipeline has substantially reduced its rated capacity (from 4,05,000 BOPD to 2,17,000 BOPD) and it would not be able to cater to the expected peak flow demand of 3,80,000 BOPD in 2006-07.

(v) Intelligent pigging carried out recently in 26” dia MUT gas pipeline has revealed that significant Metal loss (wall thickness) loss of around 40% has taken place at two locations in the pipeline, which though did not pose a major threat right now, could become extremely dangerous and may not withstand high operating pressures. Further, the existing pipeline would not be able to cater to the expected peak flow rate of 15.95 MMSCMD expected in 2006-07.

(vi) To transport the existing and incremental production of redevelopment till 2030.

(vii To explore and exploit prospective locations beyond southern & Western flanks of Mumbai High and to transport oil & gas produced from future marginal fields viz.)

• Gas from structure B-46, B-48, B-121 and C-series Field • Oil from B-192, Bassein East, B-178, B-179, B-180 and B-193 • Alternate evacuation from Panna-Mukta (JV Field) • Future Deepwater prospects of west coast.

(viii) Enhancing the image of ONGC which had suffered a beating on account of two ruptures occurred in the MUT oil pipeline during the last 3 months

(ix) Savings on the cost of additional tanker deployed for evacuation of oil (as a standby measure)

(x) Savings on the consequent loss of production which may take place on account of the bad physical condition of pipelines

(xi) The laying of new oil and gas pipelines would enable ONGC to comply to the Health, Safety and Environment (HSE) Management as any oil spillage consequent to future ruptures in the MUT



existing pipelines which may attract penal provisions of Environmental Acts apart from tarnishing the image of the institution.

Thus, it may be stated that to meet enhanced production from Mumbai High and to maintain uninterrupted supply of oil and gas to its customers, ONGC proposes to replace the existing Mumbai to Uran Trunk pipelines (MUT) which includes submarine and onshore oil and gas trunk pipelines, feeder submarine pipelines, topside platform modifications and at Uran terminal.

The proposals for the replacement of MUT pipelines project have been prepared on the basis of cost estimates prepared by Engineers India Ltd. (Eth), Residual Life Assessment (RLA) study undertaken, reports on contingency plan for evacuation of gas and oil in case of damage to MUT pipelines.

The implementation of the project involving laying of new MUT oil and gas pipelines will result in achievement of targeted availability for transportation in the peak years (2006-07), sustenance of production, improvement in operational flexibility, improvement in safety and environment, life extension etc.

Technical arrangements

Design, Engineering and Erection

ONGC has extensive experience in execution and commissioning of projects in the area of oil and gas exploration, production and its evacuation for over four decades. The present proposal of replacement of MTJT pipelines is required for transportation of oil and gas. This requires the laying of the pipelines along the sea bed (offshore) and buried in the earth (onshore) for which specialised services are required. ONGC proposes to undertake the above project involving laying of new Oil & Gas submarine Trunk pipelines by inviting tenders from reputed agencies having specialisation for performing the work on turnkey basis. Hence, the entire engineering arrangements and its requirements would need to be supplied by the successful bidder. ONGC has appointed Engineers India Limited (EIL) as consultants for the project from concept to commissioning that includes preparation of conceptual study, cost estimates and bid package, evaluation of bids, post order design and engineering review and field supervision till commissioning stage The bid documents also stipulate third party inspection by reputed international inspecting and certifying agency already identified and mentioned in the bid documents.

Implementation Schedule

The entire project envisaging laying down of the new Oil & Gas Pipelines of 30” and 28” diameter respectively is scheduled for completion within 16 months i.e. before May’2005. As the techno commercial and price bids have already been received in respect of the notice inviting tenders, Involvement of EIL as consultants and ONGC’s substantial experience in implementation, operating and maintenance of oil wells, platforms, pipelines etc. and no problem is envisaged with regard to the timeframe for completion of the project.

V. Project cost

The cost of the replacement of MUT oil and gas pipelines is estimated to be Rs. 3418.08 crore (equivalent to 737.29 million USD) based on the exchange rate of 1 USD = Rs. 46.36 as on the date of Notice Inviting Tender (NIT). The entire project is proposed to be completed on turnkey basis on International Competitive Bidding (ICB) and the implementation schedule is assumed to be 16 months. It may be mentioned that the techno commercial un-priced bid has been opened on December 3, 2003 and two bidders M/s HHI Co. Ltd. (South Korea) and M/s Allsea Marine Contractors SA (Switzerland) has submitted their bid.

Cost Estimates

The details of cost estimates for the MUT oil and gas pipelines as submitted by EIL (based on the assumptions detailed at Annexure II) are as under.



Description FC in (Eqy. Rs. Crore)

IC in Rs. crore) Total Cost (Rs. crore)

1 Material Supplies

30” Oil Trunk Line 649.35 157.96 807.31

28” Gas Trunk Line 610.47 153.13 763.60

2. Offshore Installation

30” Oil Trunk Line 505.3 - 505.32

28” Gas Trunk Line 516.09 - 516.09

3. Engineering - 275.94 275.94

4. Insurance - 106.14 106.14

5. Spares 15.33 - 15.33

6. Others Cost

- TPI charges - 16.23 16.23

-Survey cost - 4.26 4.26

- Engineering & consulting @

- 16.27 16.27

7. Duties & Taxes

- Customs Dutty 7.79 106.39 114.18

- Excuse Duty - 87.43 87.43

- Service Tax - 90.45 90.45

8. Contingency @ 3% 99.53 99.53

Total Project Cost (In Rs. crore)

2304.35 1113.73 3418.08

* Based on 1 USD = Rs. 46.36 (Exchange rate as on NIT date) @ Includes fee of Rs. 7.75 lakh for appraisal of the project from Fis/Bankers

The cost estimates for MUT oil and gas pipeline systems separately works out as under:

Pipeline Cost of Project (Rs. crore)

30” dia Oil pipeline (MUT)

1736.32

28” Dia Gas Pipeline (MUT)

1681.76

Total cost of the Project 3418.08

The physical cost estimates are based on inhouse estimates of EIL and marine duration including offshore mobilisation and demobilisation estimates made by EIL. (detailed at Annexure II) and has an accuracy level of +1- 15%.



The provision for Duties and Taxes for Customs, Excise and Service tax in respect of the above cost estimates for laying of new MUT oil and gas pipelines has been considered by ONGC at the prevailing rates after obtaining opinions from experts in the field of legal and taxation.

A provision of 3% had been made towards contingency for cost estimation purposes by ONGC.

Comparison of Cost Estimates -

The total project cost envisaging laying of the MUT oil and gas pipelines (204 Kms each), feeder lines of about 100 kms and other associated facilities is estimated to be Ks. 3418.08 Crore. The cost per inch kilometer works out to Rs. 0.2482 crore after deducting Rs. 65 crore towards Main oil line pumps at NQ platform.

The existing MUT oil and gas pipelines were laid in the year 1977-78 by M/s Brown & Root International Ltd. (BRIL). As mentioned earlier, the existing pipelines have already operated past their designed life and on account of results of intelligent pigging in 26” gas pipeline and recent ruptures in the 30” dia oil pipeline and therefore requires urgent replacement.

ONGC in 1995-96 (exchange rate prevailing at that time was 1 USD= Rs. 31) had implemented the South Bassein Hazira Terminal (SBHT) project which included laying of 244 km of 42” diameter pipeline and 4 Kms spur line of 30” diameter at a total project cost of Rs. 1456.21 crore. On the above cost, as discussed with EIL officials if the present exchange rate as well as escalation factor is accounted for, the revised cost would amount to Rs 0.2415 crore per inch km as per calculations indicated below:

Total Project Cost for 248 kms. Pipeline Rs 1456.21 crore

Add :- Exchange rate fluctuation

Rs.46.36visavisRs.31 per USD) Rs. 721.50 crore

Add :- Escalation in prices @ 2.5% p.a. i.e. (15%) Rs. 326.66 crore

Revised Cost Rs.2504.37 crore

Per inch Km cost on revised cost basis Rs. 0.2415 crore

• It can be inferred from the above observations that though the calculations as arrived for calculating the revised cost estimates for the SBHT pipeline project may be subjective, but it may be used to provide some benchmark for comparing the cost estimates arrived at for the MUT oil and gas pipeline project. It may be mentioned that the cost per inch km for the MUT project at Rs 0.2482 crore is comparable with the revised cost per inch km for the S at Rs. 0.2415 crore.

Means of Finance

The entire project is proposed to be financed by way of internal accruals.

Description Am.t (Rs. crore)

Internal Accruals 3418.08

Total 3418.08

• As the MUT pipelines replacement project investment has become an operational necessity and as the funds requirement is also not very large for the company of the size of ONGC, it is expected that the



company will be able to meet the fluid requirement of the project, out of its internal accruals. The Gross Cash accruals of ONGC for the period ended March 31, 2003 works out to its. 14,657 crore and after deducting dividend outflow of P.s. 4,516 crore, the net cash accruals work out to P.s. 10,141 crore. The expected internal generation from operations for FY 2003-04 and 2004-05 are Rs l2,64l crore and P.s 10,388 crore respectively. The commitment for capital expenditure during these years are its 10,625 crore and Rs 11,448 crore including MUT pipeline project. Considering the expected generation during the next two years and surplus already available, no problem is envisaged for arrangement of funds for the capital commitments proposed during this period including MUTP project.

VI. Cost Benefit Analysis

Laying of new MUT Oil Pipeline System (204 Kmsi) and Dia size 30”

• The cost estimates for laying of new MUT oil pipeline system bra length of 204 kms, mostly offshore along the sea bed and having diameter size of 30” has been worked out at Rs.. 173632 crore (USD 374.53 million).

• The implementation period has been estimated to be 16 months from the date of notification of award of tender (January 9, 2004) and the replacement project is proposed to be completed by May 10, 2005.

• It is assumed that about 60% of the expenditure would be incurred in the base year 2004-05 and the balance of 40% is proposed to be spent during 2005-06.

• A cost-benefit analysis has been made in the context of the laying of the new pipeline vis-ã-vis the scenario if this expenditure is not incurred and the existing oil pipeline is pursued with. To carry out the above analysis, the following parameters have been worked upon:

In case the new oil line is not laid, then as a contingency plan the entire oil transportation may be required to be made through tankers, in the event of the future ruptures in the oil line. It was worked out that the entire oil transportation to refineries through deployment of tankers would involve about minimum number of 10 tankers (LR-ll size and capacity: 76,000 MT) and entail expenditure to the nine of about Rs. 1 crore per day. Hence, the average transportation cost (Average 250520 BOPD) works out to Rs. 39.92 per BBL as against the average transportation cost through the new oil pipeline to Uran upto the period of 2027-28 (useful life of the new MUT oil pipeline) and discounted at the rate of 10% including corporate tax benefit works out to Rs.. 19.70 per BBL. However for the purposes of comparison it is considered that the cost of tankers from Uran to Refineries be excluded from the total cost of transportation arrived above for transportation of crude from offshore to the refineries. Eight number tankers (Capacity: 50,000 MT) would be required based on the tanker movement plan of July 2003 from Jawahar Deep Port, voyage and berthing time of 7 days, at the rate of Rs. 6.7 lakh per tanker per day. This works out to an annual cost of Rs. 45 crore. The overall annual savings on account of transportation through laying of new MUT oil pipeline would be to the tune of Rs. 137.5 Crore per annum.

Presently, the contingency ICP-Heera line is being used to divert part production of 1,10,00 BOPD which is the maximum limit on account of back-pressure problem at Heera.

Stabilization losses @ 5% of the production (including back-pressure loss) in case of evacuation through tankers which works out to 12,500 BOPD (equivalent to 6,00,000 MT p.a.) and the annual loss on this account would amount to Rs. 239 crore net of royalty and cess (1 BBL is assumed at USD 18). This also includes a loss of approximately 8,000 BOPD due to closure of wells of BHN while diverting the crude of NQ crude to BHN for tanker transportation.



Further, substantial losses occur due to reduction in the ‘off gas’ available at the crude stabilization units at Uran, when the crude is evacuated from Mumbai High instead of sending it to Uran which are:

- Reduction in LPG production

- Reduction in C21C3 production

- Reduction in LAN

- Reduction in the lean gas available for sale

As per the pre-feasibility report of EIL for supply of MHF oil to MRPL, corresponding to 3 MMTPA (which is not sent to Uran) worked out to Rs. 22.5 crore p.a. Hence, for 12 MMTPA the estimate losses in value added products at Uran on account of Direct Loading would be Rs. 90 crore p.a.

• Hence, it can be concluded that the total savings on account of not transporting crude through tankers but laying new MUT oil pipeline would work out to Its. 466.5 crore. The pay back period for the new pipeline would be less than 4 years.

Laying of new MUT Gas Pipeline System (204 kms) and Dia size 28

• The cost estimates for laying of new MUT gas pipeline system for a length of 204 Ions, mostly offshore along the sea bed and having diameter size of 28” has been worked out at Rs. 1681.76 crore (USD 362.76 million).

• The implementation period has been estimated to be 16 months from the date of notification of award of tender (January 9, 2004) and the replacement project is proposed to be completed by May 10, 2005.

• It is assumed that about 60% of the expenditure would be incurred in the base year 2004-05 and the balance of 40% is proposed to be spent during 2005-06.

• An analysis has been made on the cost-benefit analysis in the context of the laying of the new gas pipeline vis-a-vis the scenario if this expenditure is not incurred and the existing gas pipeline is pursued with. To carry out the above analysis, the following parameters have been worked upon:

In case the new gas line is not laid and ruptures take place in the existing Gas pipeline then part of the 12 MMSCMD gas will be supplied through ICP Heera alternate trunk line (contingency line) and the balance gas (3.6 MMSCMD) has to be compulsorily flared resulting in total loss of revenue on the flared gas. Moreover, the part of the infrastructure available (process gas compressors and gas dehydration systems) would be remaining unutilised. The estimated loss of revenue due to flaring of the gas would amount to approximately Rs. 272.50 crore p.a (based on APM price of Rs. 2074 per MCM). The envisaged cost of Rs. 1681.76 crore for laying the new MUT gas pipeline is expected to be have a pay-back period of 6 years. However, ONGC expects the present prices of gas to be revised upwards substantially post APM which will reduce the pay-back period correspondingly.

Further the compulsory flaring of gas apart from leading to wastage of scarce national resources would also be a environmental hazard besides affecting the long-term commitments to downstream consumers which would in turn have its effect on daily needs of the public viz. Power, LPG, CNG, piped gas and fertilizers. It may be mentioned here that the cost of the above losses cannot be readily quantified as these are needs of national importance.

It may, therefore, be observed that the proposal for laying of the new MUT oil and gas pipelines is necessary to be carried out to avoid losses of production due to catastrophic failure and to ensure reliability, availability and safety of the equipment. Though the expected improvement in performance due to implementation of the pipelines cannot be estimated up-front, the replacement project would help



in reducing downtime, maintaining the efficiency levels and improving/ maintaining the overall performance of the production facilities apart from catering to the peak transportation of oil and gas in the year 2006-07. Non implementation of the project might lead to deterioration in performance and increased risk of leakage, spillage etc. as the pipelines have already outlived their designed life of 25 years.

VII. Assessment of viability of MHA with MUTP project

• The objective of carrying out this assessment is to examine whether the operations of MHA wilt be able to absorb the envisaged replacement project expenditure of laying new oil & gas pipelines amounting to about Rs. 3418.08 crore and will be able to earn sufficient returns.

• The operating costs for the Project have been worked out on cost driver basis as was followed in the case of Mumbai High Redevelopment. The following cost drivers were identified for this purpose:

o Processing of Oil at the platform

o Processing of Gas

o Processing of Water

o Processing of oil at Uran

o Water Injection

o Maintenance of well platforms

o Maintenance of wells

o Maintenance of pipelines

The unit costs for each of the cost drivers and the assumptions for the profitability analysis as provided by ONGC for calculation of the IRR is furnished at Annexure III.

Based on the assumptions detailed in Annexure III, the financial feasibility analysis has been done under the Base Case and the parameter used for the evaluating feasibility is Internal Rate of Return (lltR) and the IRR for the Base Case works out to 18.27%.

VIII. Overall Financial Assessment

• The basis for cost estimates carried out by EIL together with project cost comparison with SBHT appears to be satisfactory.

• The internal accruals of ONGC are adequate to meet the requirement of funds to be brought in for the replacement project envisaging laying of 204 Kms each of the MUT oil and gas pipelines.

• In view of the present state of the existing pipelines, it is assumed that it would not be able to cater to the enhanced requirements as well as from safety and environmental point of view, it would be imperative to go for the replacement of the existing MTJT oil and gas pipelines.

• The IRR for the MHA taking into account the re-development expenditure including MUTP project works out to 18.27% which is above the hurdle rate of 14% for ONGC.

• The analysis of cost-benefit scenarios and the IRR of 18.27% reveals that the replacement project envisaged by ONGC and the proposed expenditure on the MUT pipelines is justifiable.



Section - III

Socio-Economic impact Assessment I. Environ Considerations

• In ONGC, an aggressive campaign has been launched to obtain accreditations in Occupational Health, Safety, Environmental Assurance (ISO 14001) and Quality Management (ISO 9000) at all the work-centres and considerable progress has been made. In this context, Occupational health centres have been set up at major work centres and Crisis Management Team has been expanded.

• Further, ONGC also undertakes comprehensive Environmental impact assessment which is a pre-requisite for seeking environmental clearance.

II. Energy Conservation

• ONGC undertakes comprehensive energy conservation measures which include use of waste heat recovery equipment, use of energy efficient equipment, tapping solar energy, thermal energy cost reduction etc. and an additional investment of Rs. 4.1 lakh was made during 2002-03 for reduction of energy consumption. The impact of the above measures have resulted in reduction of energy consumption (HSD, Natural gas and electricity) valuing Rs. 148.5 crore during the financial year 02-03.

III. Status of Statutory Consents

• ONGC, on the basis of similar clearances from the various past trunk pipeline project executed has already initiated steps for seeking clearances I permissions from various statutory authorities for installation of pipelines under the MTJT project viz:

Environmental clearance from MOEF

Permission from Mumbai Port Trust and JNPT

Permission from CIDCO

Permission from Offshore Defence Advisory Group

Permission from Department of Fisheries

Clearance from VSNL.

• It is expected that ONGC would be in a position to obtain all the statutory clearances based on its similar experience in the past on or before the implementation of the project.

Section-IV Conclusion

ONGC is a profit making, dividend paying company owned by Government of India, enjoying a premier position in the industry both nationally and internationally. The market capitalisation of ONGC recently breached the Rs. 1,00,000 crore mark and also became the highest dividend paying PSU in absolute terms.

The company has proposed to replace its existing oil and gas pipelines which were laid in 1977-78 and have already surpassed their designed life of 25 years in 2003. Further, on account of 2 recent ruptures in the oil pipeline and the intelligent pigging reports of significant metal loss upto 40% in the gas pipeline has made the laying of the new oil and gas pipelines from Mumbai High to Uran (MUTP) an absolute necessity.

The summary of the assessments carried in pre-sections is as under:



• ONGC has rich experience in the field of oil and gas exploration and exploitation of the resources.

• ONUC has already laid more than 3000 Ions of offshore pipelines in the Mumbai High itself and has good experience in implementing and managing similar projects.

• ONGC has sufficient free cash-flows for mobilizing the requisite resources for the project.

• The basic cost estimates have been carried out by ElL and the comparison of the MUTP pipeline project (Rs. 0.2482 crore per inch km compares suitably with the SBIIT pipeline project (adjusted for exchange rate and escalation) and completed in 1996 at (Rs. 0 crore per inch km).

• The internal accruals of ONGC are adequate to meet the requirement of funds to be brought in for the replacement project envisaging laying of 204 Kms each of the MUT oil and gas pipelines.

• The IRR for the MHA taking into account the re-development expenditure including MUTP project works out to 18.27% which is above the hurdle rate of 14% for ONGC.

Thus, it may be concluded that on the basis of the analysis of cost-benefit scenarios, project cost comparisons and the IRR of 18.27% as against the hurdle rate of 14% for ONGC reveal that the replacement project envisaged by ONGC and the proposed expenditure on the MUT pipelines is justifiable.

Annexure -1

Oil & Natural Gas Corporation Ltd (ONGC) Analysis of Profit & Loss Account

Year ended March 31 2001 2002 2003 30/09/2003

(Unauidted)

Income

Gross Sales 23186.10 22841.20 34690.70 16712.38

Pipeline Revenue 461.20 396.60 47.80 -

Other Receipt 578.40 619.40 627.60 714.23

Increase / (decrease) in stock 44.70 0.20 21.10 (20.46)

Total 24270.40 23857.40 35387.20 17406.15

Expenditure

Operating, Selling & General Expenses 5551.50 5974.20 9233.40 7318.83

Pipeline operational cost 496.50 495.10 545.20 -

Other operational cost 4949.00 4438.00 6557.00 -

Exchange loss 127.00 46.00 19.00 -

Total 11124.00 10953.30 16354.60 7318.83

EBITA 13146.40 12904.10 19032.60 10087.32

Depreciation 4453.00 3815.00 4128.00 2269.10

Operating profit before interest 8693.40 9089.10 14904.60 7818.22



& Tax

Other non-operating Income 862.00 1014.00 1332.00 -

EBIT 9555.40 10103.10 16236.60 7818.22

Interest 398.00 247.00 113.00 1423

EBT 9157.40 9856.10 16123.60 7803.99

Tax 3928.00 3657.00 5594.00 2844.45

Net profit 5229.40 6199.10 10529.60 4959.54

Payment of dividend & tax 1728.00 1996.00 4516.00 -

Net cash accruals 11882.40 11675.10 15735.60 -

EBITDA % revenue 54.17% 54.09% 43.78% 57.95%

NP ration 21.55% 25.98% 29.76% 28.49%

Year as on March 31 2001 2002 2003

Liabilities

Equity share capital 1425.90 1425.90 1425.90

Add: Reserves Surplus 28885.40 28296.30 34313.00

Less: Misc Expenses not written off 163.50 210.03 130.08

Shareholder funds 30147.80 29512.17 25608.82

Loan from Oil Industry development Board 141.50 121.30 101.10

FCL 2841.10 2916.81 261.60

Deferred Tax liability - 5347.10 5234.80

Long Term Liabilities 3982.60 8385.21 5597.50

Assets

Gross Block 35769.78 37264.74 39033.66

Less: Depreciation 29880.50 31763.95 33640.84

Net Fixed Assets 5889.28 5600.79 5392.82

Capital Work in Progress 728.30 690.30 932.90

Producing Properties (gross) 16291.32 16691.26 17438.03

Less: Provision for Impairment 286.10 310.80 327.00

Producing Properties (Net) 16005.22 16380.46 17111.03



Exploratory Wells in progress 934.90 977.50 1073.10

Investment 2360.72 3323.17 3982.60

Current Assets

Inventories 1536.92 1452.60 1571.02

Sundry Debtors 1733.78 2251.38 3935.93

Cash & Bank Balance 2054.54 5545.453 6109.02

Loans and Advances 8043.27 7748.40 9490.62

Other assets 602.97 667.96 390.48

13971.48 17665.87 21497.07

Current Liabilities

Sundry creditors 2457.82 2808.65 3118.03

Provision 3090.74 3770.51 5555.25

Other liabilities 210.94 161.55 109.92

5759.50 6740.71 8783.20

Net current Assets 8211.98 10925.16 12713.87

Net worth 30147.80 29512.17 35608.32

Debt-Equity Ratio 0.13 0.28 0.16

Current ratio 2.43 2.62 2.45

FACR 5.92 2.82 4.38

Annexure II

Oil & Natural Gas Corporation Ltd. (ONGC) – Replacement of MuT Pipeline project

Assumption underlying the cost estimates

Assumptions on cost estimates by EIL

1. For material supplies

• Line Pipes : The estimates are based on line pipe material specification, diameter, thickness and length using in house cost data considering that the pipelines are to be procured from abroad and wrapped and coated at the Kandla port.

• Coal Tar Enamel (CTE), concrete coating and anodes for cathodic protection: The cost estimates for CTE enameling and concrete coating is based on surface area involved using in house cost data and for anodes requirements for cathodic protection using in house cost data to be carried out in an Indian yard at or near Kandla port.



• Sub Sea Isolation valve, laterals etc.: The cost estimates for SSIV, laterals based on engineering specifications and MTOs using inhouse data. However, provision for cost of PLEMs based on lump sum basis. Cost estimates for umbilical (for SSIVs only) & straps based on required length using in house data of EIL.

• Onshore terminal & platform topside facilities : Cost towards facilities like platform topside and onshore terminal modifications at Uran site based on lump sum basis.

• Spares for equipment items have been included in the estimate @ 6% of supply cost.

2. Off shore transportation, installation, hook up, testing and commissioning: Based on marine spread duration as under:

Working Duration

(Days)

Mobilisation / Demobilisation

(Days)*

Description Nos No. of days

Oil Gas

Derrick cum lay barge 3 30 258 243 (30+30)* 180 days from Korea

Diving Support vessel 2 9 71 61 (9+9)*2 =36 days from Gulf

Burial barge 2 9 80 65 (9+9)*2 =36 days from Gulf

Work Boat 2 9 30 30 (9+9)*2 =36 days from Gulf

Hook up barge 1 9 60 50 (9+9)* 1 =18 days from Gulf

Survey Vessel 4 9 29 29 (9+9)* 4 =72 days from Gulf

Cargo barge 14 9 250 200 (9+9)* 14 =252 days from Gulf

Cutter hopper dredger (normal soil)

1 12 70 70 (21+21) =42 days from Europe

Cutter hopper dredger (hard soil)

1 21 15 15 (21+21) =42 days from Europe

Rock drilling / blasting

1 21 15 15 (21 +21) =42 days from Europe

* Allocation for mob / demob days estimates are based considering a single contract and is done 50:50 for oil and gas pipeline respectively.

The onshore laying for 300 mtrs. Oil and gas pipelines are based on past data.

3. Indirect costs Provision for Ocean freight assumed @ 85 IJSD per MT for line pipes, Port handling @ 2% of FOB value, Insurance @ 4%, Inland pipe handling — bare pipe @ 7 USD / MT and coated pipes @ 10 USD/ MT.

4. Project management, engineering, procurement, construction management & commissioning charges have been provided @ 10% of the total installed costs.

5. Provision for contingency has been made @ 5 % by EIL on the hard cost estimates.

6. Financing charges has been made on 25% of the hard cost for 50% of the project implementation time (i.e. for 8 months) @ 10% p.a.

7. Provision for liability and profits has been made @ 10% of the total cost.



Assumptions on total cost estimates by ONGC

8. Customs Duty, Excise Duty and Service Tax has been assumed based on opinions obtained from experts in the field of legal and taxation. The CD @50.8% on 60% of the imported component of material supplies other than Line pipe materials (Mining Lease area prior to 1/4/1999), ED ® 16% on 60% of the imported line pipe portion and Service Tax @ 8% on Design & Installation and commissioning has been considered.

9. Third party inspection charges has been assumed to be USD 3.5 million as per discussions held between ONGC and BIL.

10. Contingency has been assumed @ 3% on the total cost including taxes and duties.

Annexure — III

Oil & Natural Gas Corporation Ltd (ONGC) Unit cost for the cost driven & assumptions for profitability analysis

Unit fixed and operating cost numbers

Fixed Variable Total

Oil Processing Rs. per Mt 71.65 78.06 149.71

Gas Processing Rs. per 1000 M3 120.87 131.68 252.55

Water Processing cost Rs. per M3 2.50 2.72 5.22

Cost of oil processing at Uran Rs. per MT 3.21 15.15 18.36

Cost of water injection Rs. per M3 16.48 4.12 20.60

Cost of well platform maintenance Rs. in Lakhs

143.65 23.26 166.91

Cost maintenance per well (Rs. in lakhs) 4.91 42.21 47.12

Cost of pipelines maintenance (Rs. in lakhs per line KM)

0.47 0.84 1.31

The following assumptions have been made to carry out the profitability analysis.

1. The profitability of the project has been carried out on the basis of Long Run Marginal Cost considering the incremental Capital expenditure incurred/to be incurred from the financial year 2000-2001 including the proposed pipeline cost of itt 3418.08 crore for the entire economic life i.e. upto FY 2029-30.

2. The viability of the project has been carried out on Completion Cost basis taking into - consideration Rs.10,039.41 crore towards cost of Redevelopment of Mumbai High North and South and Rs.3,500.11 crore as completion cost of the present project. This is arrived at by taking 6% escalation per annum on cost of facilities & wells.

3. Based on the past trend and as per the data provided by ONGC the escalation of 8 % p.a. has been considered in OPEX.

4. For the purpose of revenue computation (production profile of oil and gas reserves provided by ONGC for MUN and METS only) around 3.5% production and processing loss would occur for oil and hence only 96.5% has been considered for revenue projection. For purpose of computation of revenue for gas a loss of 10% toward technical flaring has been considered.

5. Royalty and cess have been considered at the prevailing rate as provided by ONGC.

6. A provision for abandonment at rate of 10% of the total Cap excluding and treated as cash outflow.

Documents

Mumbai High Uran Trunk Pipeline (MUTP) Project