1. Performance Evaluation Report
Project Number: 37905
Equity Investment Number: 7192
November 2006
India: Dahej Liquefied Natural Gas Terminal Project
Operations Evaluation Department

2. CURRENCY EQUIVALENTS
Currency Unit – Indian rupee/s (Re/Rs)
At Appraisal At Operations Evaluation
(15 December 2003) (15 May 2006)
Re1.00 = $0.02 $0.02
$1.00 = Rs47.00 Rs45.00
ABBREVIATIONS
ADB – Asian Development Bank
APM – administered pricing mechanism
BPCL – Bharat Petroleum Corporation Limited
CAPEX – capital expenditure
CIF – cost, insurance, freight
CNG – compressed natural gas
CO2 – carbon dioxide
CPCL – Chennai Petroleum Corporation Limited
CSP – country strategy and program
DMP – disaster management plan
EIA – environmental impact assessment
EIRR – economic internal rate of return
EPC – engineering, procurement, and construction
ERP – emergency response plan
FIRR – financial internal rate of return
FOB – free on board
GAIL – GAIL (India) Limited
GDF – Gaz de France
GDFI – GDF International
GE – General Electric
GIDC – Gujarat Industrial Development Corporation
GMB – Gujarat Maritime Board
GPCB – Gujarat Pollution Control Board
GSPA – gas sales and purchase agreement
GTG – gas turbine generators
HBJ – Hazira–Bijaypur–Jadgishpur
IGL – Indraprastha Gas Limited
IHI – Ishikawajima-Harima Heavy Industries Company Limited
IOC – Indian Oil Corporation Limited
IPO – initial public offering
ISO – International Standards Organization
JCC – Japan crude oil cocktail
JV – joint venture
KG – Krishna Godavari
LNG – liquefied natural gas
MGL – Mahanagar Gas Limited
MOEF – Ministry of Environment and Forests
MOPNG – Ministry of Petroleum and Natural Gas
MSEB – Maharashtra State Electricity Board

3. NELP – New Exploration Policy
NOx – nitrogen oxides
O&M – operation and maintenance
OCR – ordinary capital resources
OEM – Operations Evaluation Mission
OIL – Oil India Limited
OISD – Oil Industry Safety Directorate
ONGC – Oil and Natural Gas Corporation Limited
PCG – partial credit guarantee
PLL – Petronet LNG Limited
PPER – project performance evaluation report
PPP – public-private partnership
PSD – private sector development
PSOD – Private Sector Operations Department
Rasgas – Ras Laffan Liquefied Natural Gas Company Limited
RIL – Reliance Industries Limited
RRP – report and recommendation of the President
SCV – standard combustion vaporizer
SO2 – sulfur dioxide
SPA – sales and purchase agreement
SPM – suspended particulate matter
STV – shell and tube vaporizer
TA – technical assistance
USEPA – US Environmental Protection Agency
WACC – weighted average cost of capital

4. WEIGHTS AND MEASURES
BBL – barrel
BCM – billion cubic meter
km – kilometer
m3 – cubic meter
mg/N m3 – milligrams per normal cubic meter
MMBTU – million British thermal unit
MMSCMD – million standard cubic meters per day
MMT – million metric ton
MMTPA – million metric ton per annum
MW – megawatt
ppm – parts per million
SCM – standard cubic meters
TCF – trillion cubic feet
NOTES
(i) The fiscal year (FY) of Petronet LNG Limited ends on 31 March.
(ii) In this report, "$" refers to US dollars.
Keywords
Asian Development Bank, Dahej Indian gas sector, liquefied natural gas, Petronet LNG public-
private partnership
Director General B. Murray, Operations Evaluation Department (OED)
Director R. Adhikari, Operations Evaluation Division 2, OED
Team leader B. Finlayson, Senior Evaluation Specialist, OED
Team members J. Dimayuga, Evaluation Officer, OED
R. Perez, Senior Operations Evaluation Assistant, OED
Operations Evaluation Department, PE-693

5. CONTENTS
Page
BASIC DATA ii
EXECUTIVE SUMMARY iii
I. THE PROJECT 1
A. Project Background 1
B. Project Features 2
C. Progress Highlights 4
II. PROJECT EVALUATION 4
A. Overview 4
B. Development Outcome 5
C. ADB’s Investment Returns 10
D. ADB’s Effectiveness 10
E. ADB’s Additionality 11
F. Overall Rating 11
III. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS 12
A. Project Issues 12
B. Lessons 13
C. Follow-Up Actions 14
APPENDIXES
1. Private Sector Development Indicators and Ratings 15
2. Developments in the Indian Gas Market 16
3. Review of Petronet LNG’s Operations 21
4. Reevaluation of the Economic Internal Rate of Return 26
5. Social, Environmental, Health, and Safety Performance 30

6. The guidelines formally adopted by the Operations Evaluation Department on avoiding conflict
of interest in its independent evaluations were observed in the preparation of this report. The
fieldwork was undertaken by consultants Pradeep K. Dadhich (Gas Specialist) and TS Panwar
(Environment Specialist) under the guidance of the mission leader. To the knowledge of the
management of the Operations Evaluation Department, there were no conflicts of interest of the
persons preparing, reviewing, or approving this report.
This report contains information that may be subjected to disclosure restrictions agreed between
ADB and the relevant sponsor or recipient of funds from ADB. Recipients should therefore not
disclose its content to third parties, except in connection with the performance of their official
duties. A summary of this report shall be made publicly available in accordance with ADB’s
Public Communications Policy (PCP) and such summary shall not include any confidential
information and other information that falls within the exceptions set out in Paragraphs 126, 127
and 130 of the PCP.
As agreed by Operations Evaluation Department, Office of the General Counsel, Office of the
Secretary, and the Department of External Relations, only the 35-paged redacted summary will
be uploaded in the Board Document System.

7. BASIC DATA
Equity Investment 7192: Dahej Liquefied Natural Gas Terminal Project in India
TA Number TA Title Type Amount Approval Date
TA 2752 Technical Assistance to India for the PP $600,000 27 Jan 1997
Liquefied Natural Gas Terminal Project
KEY DATES Expected Actual
Fact-Finding Jul 2003 28 Jul 2003
Appraisal Nov 2003 11 Nov 2003
Board Approval Jan 2004 13 Jan 2004
First Disbursement Feb 2004 6 Feb 2004
Project Completion 1 Apr 2004 9 Apr 2004
DMC Government of India
Executing Agency Petronet LNG Limited
MISSION DATA Missions Person-Days
Type of Mission
Fact-Finding 1 8
Appraisal 1 6
Project Administration
Review 1 2
Operations Evaluation 1 24
ADB = Asian Development Bank, DMC = developing member country, EIRR = economic internal rate of return, FIRR =
financial internal rate of return, OEM = Operations Evaluation Mission, PP = project preparatory, TA = technical
assistance, WACC = weighted average cost of capital.

8. EXECUTIVE SUMMARY
In December 2003, the Asian Development Bank’s (ADB) Board of Directors approved a
report and recommendation of the President (RRP) for: (i) an equity investment in Petronet LNG
Limited (PLL) for a 5.2% shareholding; and (ii) a partial credit guarantee (PCG), without a
Government guarantee, to support a PLL bond issue of up to Rs7 billion, amounting in exposure
terms to Rs3.525 billion. The funds, sourced from ADB’s ordinary capital resources (OCR), were
to be used to construct and operate a liquefied natural gas (LNG) import and regasification
terminal with a 5.0 million metric tons per annum capacity at Dahej in Gujarat state. This project
performance evaluation report (PPER) assesses ADB’s support to help develop PLL’s LNG
plant at Dahej (the Project).
The Operations Evaluation Mission (OEM) visited India 24 April–5 May 2006 to review
the Project and obtain the necessary data to prepare the PPER. The OEM interviewed project
stakeholders, including representatives of PLL’s senior management team, shareholders,
lenders, and government officials. The PPER incorporates the findings of the OEM,
observations of relevant ADB staff, and a review of project reports and documents. The
evaluation criteria used for the Project were based on the best practice guidelines identified by
the Evaluation Coordination Group of the Multilateral Development Banks on Private Sector
Operations, as well as the criteria presented in ADB’s draft Guidelines for the Preparation of
Performance Evaluation Reports of Private Sector Operations. Reflecting these arrangements,
ADB’s participation in the Project was evaluated using four criteria: (i) development outcome, (ii)
ADB’s investment returns, (iii) ADB’s effectiveness, and (iv) ADB’s additionality. Overall, the
Project is rated satisfactory.
The development outcome is rated satisfactory. It was evaluated using five subcriteria: (i)
private sector development (PSD), (ii) business success, (iii) economic sustainability,
(iv) contribution to living standards, and (v) and environmental impacts. For PSD, the primary
justifications for the Project presented in the RRP were to (i) help meet growing energy demand
in North and West India; (ii) enhance energy security by diversifying the energy base; (iii)
contribute to economic development by providing additional and lower-cost alternate inputs to
the power, fertilizer, oil, and transport sectors; (iv) promote the use of clean energy; (v) provide
an example of good practice in public-private partnership in infrastructure development; and (vi)
further develop the capital market for long-term, fixed-rate financing through the use of the PCG.
The RRP objectives were relevant. With the exception of capital market developments,
the Project helped achieve these goals. The Project was the first step in liberalizing and
commercializing the LNG segment of the Indian gas industry, and encouraging the use of a
clean, environmentally friendly fuel. Demand for energy in India continues to grow rapidly, and
the increased availability of clean energy at internationally competitive prices is important for the
development of the country. The Project demonstrated that the successful importation of LNG at
competitive prices is possible, thereby supporting the liberalization of the gas sector and
enhancing the level of private sector participation in the energy sector. PLL has demonstrated
the high standards of performance that can be achieved by a modern, well-run public-private
partnership managed on a commercial basis. PLL’s business success has been excellent due to
lower-than-expected operating expenses and interest costs. Further, the Project has
demonstrated that the use of LNG technology is feasible in India. As such, additional plants are
being developed.
Economic sustainability was rated excellent due to the substantial benefits derived from
meeting unmet demand, and the cost savings realized by firms that can use gas instead of

9. iv
naptha. The environmental benefits associated with the use of gas, offsetting emissions from
coal-fired generation, are difficult to quantify. However, they are likely to be substantial. While
the Project was assigned an environmental rating of category A at project appraisal, the actual
direct social and environmental impacts have been minimal. The main issues at the plant site
relate to safety of the mooring facilities during the monsoon period. A shareholder in PLL, GDF
International, which has more than 30 years of LNG experience, is assisting in developing and
refining the mooring procedures.
ADB’s investment returns have been excellent, as PLL’s share price has risen
significantly since investment. Offsetting this result, ADB did not issue the PCG that was
originally envisaged in the RRP, as it was not commercially attractive.
ADB’s effectiveness is a function of factors such as screening, appraisal, structuring,
monitoring, and supervising the Project. The result has been satisfactory. PLL management
found that ADB’s financial appraisal was performed to a high standard, and investment approval
was completed promptly. Most assumptions underpinning the Project have been realized largely
as envisaged in the RRP. The main weakness of the Project was the PCG, which was not
commercially viable. This outcome was primarily due to adverse movements in the market.
Monitoring of the Project appears to have been of a high standard, with regular visits by ADB
staff to PLL headquarters and the plant site, although most of these visits focused on arranging
financing for the phase II expansion. The documents on the subscription agreement and
insurance documents are in order. The main issue with the monitoring arrangements related to
environmental and social safeguard policies, as regulatory reports were not supplied to ADB
quarterly as stipulated in the equity subscription agreement. The OEM confirmed PLL’s
compliance with regulations through its review of the regulatory reports submitted to the
Government.
ADB additionality for the Project appears material, and was rated satisfactory. In
discussions, the management said ADB played a critical role in facilitating the liberalization of
the gas market. Subsequently, ADB helped mitigate investor and lender concerns regarding a
new and untested product and technology in India, where locally available skills and experience
were limited. ADB was given a position on the board of directors, and contributed to
improvements in corporate governance by heading the PLL audit committee.
The main variations from the original project concept were as follows: (i) the price of oil
and natural gas increased dramatically, (ii) the construction by GAIL of the Dahej–Uran pipeline
was delayed, (iii) the breakwater was replaced with the construction of a third LNG tank, (iv) the
Government did not divest its majority shareholding in one the main state-owned shareholders
of PLL, and (v) ADB was unable to issue the PCG due to adverse market movements.
The Project generated lessons in a number of areas. PSD was significant in terms of
helping to catalyze industry reforms through technical assistance to improve the enabling
environment, and through direct investment that helped reduce financiers’ concerns about
project risks. Although the Project has been operating for only 2½ years, the financial
assumptions are radically different from the investment appraisal, especially regarding
international prices for oil and gas, highlighting the importance of an adequate financial
assessment. Despite a category A rating at project approval, environmental impacts and social
externalities at the plant site have not been significant. However, some safety issues still are
being resolved. Unstable mooring conditions have been more challenging than originally
anticipated, reinforcing the need for an adequate assessment of new technology during due
diligence. Some of the original assumptions on privatization of PLL have not materialized, and

10. v
the current ownership structure continues to represent a public-private partnership. A small
shareholding by ADB was required to help make the project viable. This model can be
replicated in future gas projects, which potentially can be financed without ADB support. The
most important lesson that emerges from the Project was the ephemeral demand for PCGs and
bond finance for infrastructure projects in India.
No follow-up social and environmental action is required.
Bruce Murray
Director General
Operations Evaluation Department

11. I. THE PROJECT
A. Project Background
1. In December 2003, the Asian Development Bank’s (ADB) Board of Directors approved a
report and recommendation of the President (RRP) for: (i) an equity investment in Petronet LNG
Limited (PLL) for a 5.2% shareholding; and (ii) a partial credit guarantee (PCG), without a
Government guarantee, to support a PLL bond issue of up to Rs7 billion, amounting in exposure
terms to Rs3.525 billion. The funds were to be used to construct and operate a liquefied natural
gas (LNG) import and regasification terminal (the Project) with a 5.0 million metric tons per
annum (MMTPA) capacity at Dahej in Gujarat state. The Project would serve gas users along
the 2,500-kilometer (km) Hazira–Bijaypur–Jadgishpur (HBJ) pipeline that covers Gujarat,
Western Madhya Pradesh, Rajasthan, Delhi, Haryana, Western Uttar Pradesh, and Uran,
Maharashtra. It was to be the first ADB private sector transaction to utilize a long-term PCG, as
well as the first PCG that would support local currency debt.
2. At appraisal in 2003, the Project was to be financed based on a debt-equity ratio not
exceeding 70:30 and achieve an economic internal rate of return (EIRR) of 23.0%. The Project
began operations in April 2004. ADB’s Private Sector Operations Department (PSOD) had not
prepared a Project Completion Report at the time of appraisal.
3. The Project was strongly oriented towards strengthening the energy sector. At appraisal,
India’s predominant source of energy was coal (55%), followed by oil (31%), and natural gas
(8%). Energy consumption in India had been growing rapidly through the 1990s, relative to the
rest of the world, reflecting strong potential for continuing growth in the sector. Rising oil prices
and concerns about environmental impacts stimulated demand for natural gas, which was
envisaged at appraisal to increase from 8% to 15% of Indian energy consumption by 2011–
2012, provided gas was available. In addition to relieving energy constraints, the Project was
expected to lower industrial costs. The industrial sector is a heavy user of natural gas, which
can be used as a substitute for naphtha. At appraisal, about 50% of fertilizer units in India used
natural gas as feedstock. While growth in this sector was not expected to be high, an increasing
number of plants using naphtha and fuel oil were expected to switch to gas.
4. Traditionally, the Government of India (the Government) has dominated production in
the gas sector. At appraisal, the majority state-owned companies Oil and Natural Gas
Corporation Limited (ONGC) and Oil India Limited (OIL) accounted for 75% of gas production,
with the balance controlled by joint ventures (15%) and private companies (10%). State-owned
GAIL (India) Limited (GAIL) had a near monopoly on onshore transmission, including the HBJ
pipeline. The Ministry of Petroleum and Natural Gas (MOPNG) regulated GAIL in areas such as
setting gas quality and access standards, and administering monopoly tariffs.
5. To help relieve supply constraints, the Government started to liberalize the gas sector in
1991 with the opening of oil exploration to small-scale private sector participation. Despite the
reforms, domestic production did not keep pace with the increase in demand for natural gas. As
India has limited indigenous natural resources, the supply shortage was expected to increase.
In 1996 and 1997, ADB provided technical assistance (TA) for two studies that helped develop a
master plan for the natural gas industry in India. These studies also assisted with (i) an
assessment of the potential for setting up public-private joint ventures to build and operate LNG
terminals, (ii) formulation of a project implementation plan, and (iii) development of a structure to
enable limited recourse financing. Although the TA studies have not been evaluated formally,

12. 2
the sponsors appeared to regard them highly, and they seemed to contribute to the liberalization
and development of the gas sector in India. In 1999, the Government introduced further reforms
to allow private domestic exploration, incorporated the TA concept into its Hydrocarbon Vision
2025, and removed many of the restrictions on LNG imports.
6. As part of these developments, four state companies—Bharat Petroleum Corporation
Limited (BPCL), Indian Oil Corporation Limited (IOC), GAIL, and ONGC (collectively referred to
as the sponsors)—formed PLL to develop LNG facilities at Dahej, Gujarat and Kochi, Kerela.
The sponsors include some of the largest companies in India. BPCL is engaged in refining
crude oil, and production and distribution of petroleum products. IOC, the largest company in
India in terms of sales, is engaged in refining and distributing petroleum products. GAIL is the
dominant gas transmission and marketing company, while ONGC produces the majority of the
natural gas in India. In 2002, the sponsors asked ADB for financial assistance to implement the
Project in Dahej.
B. Project Features
7. The Project was designed to build, operate, and transfer the first LNG import and
regasification terminal in India, with a phase I capacity of 5.0 MMTPA. The land at the project
site is part of an industrial complex owned by Gujarat Maritime Board (GMB). At appraisal, PLL
had signed a letter of intent with GMB to enter into a 99-year concession agreement to lease the
58.6 hectare site at Dahej, Gujarat, as well as a 30-year agreement to develop and use a port
facility. The concession was not tendered formally, as the market for leasing land at the project
site was competitive and does not have any monopoly characteristics. The project facilities
comprised (i) two full-containment LNG storage tanks, each with a gross capacity of 160,000
cubic meters (m3); (ii) recovery system for re-condensation of the boil-off gas; (iii) send out
facilities, including “shell and tube” and “submerged combustion” vaporizers; (iv) auxiliary
facilities, including a 23-megawatt (MW) gas-fired captive power plant; (v) electrical and utilities
production control systems; (vi) metering, fire, and gas detection and protection systems; (vii) a
jetty; and (viii) initially, a breakwater. A backup power agreement was signed with the Gujarat
State Electricity Board, and the plant is connected to the local high-tension network. At
appraisal, the Project had an environmental rating of category A, indicating substantial impacts
primarily in the area of safety, rather than emissions. Two environmental impact assessments
(EIA) reports were prepared for the Project—one for the onshore storage and regasification
facility, the other for the marine unloading facilities. The Ministry of Environment and Forests
(MOEF) and the Gujarat Pollution Control Board (GPCB) approved the EIAs, which defined the
standards that are monitored by their local regional offices.
8. Following competitive bidding, PLL signed a sales and purchase agreement (SPA) with
Ras Laffan Liquefied Natural Gas Company Limited (Rasgas), obligating PLL to purchase up to
7.5 MMTPA of LNG for 25 years. The agreement had two stages. In the first stage, PLL would
take 5.0 MMTPA on a take-or-pay basis up to 2009. After 2009, PLL could take the remaining
2.5 MMTPA subject to the mutual agreement of both parties. The purchase price initially was set
at $2.53 per million British thermal units (MMBTU), and it will be rebased regularly in
accordance with a defined formula after 2009. Rasgas, a joint venture between Qatar Petroleum
(70%) and Exxon Mobil (30%), has access to the largest non-oil associated gas fields in the
world. An international consortium led by Mitsui OSK Lines provided two dedicated special
purpose tankers with capacity of 138,000 m3 each to transport LNG to PLL under a 25-year
contract under terms that were commensurate with the Rasgas contract. GAIL (60%), IOC
(30%), and BPCL (10%) (collectively referred to as the offtakers) are purchasing gas from the

13. 3
LNG terminal. The offtake contract is take or pay, with terms that are back-to-back with PLL’s
SPA.
9. As envisaged at appraisal, the offtakers initially were to transport the gas from the PLL
terminal to consumers through an expanded 528 km HBJ pipeline system, and eventually
through a new 485 km pipeline connecting Dahej to Uran. IOC and BPCL have executed gas
transport agreements through GAIL, which is responsible for expanding the existing and
proposed pipelines. The offtakers intended to use the gas for internal consumption, or to sell it
under long-term contracts to industrial users. One third of the output would be consumed by
IOC and BPCL at their refineries; one third would be sold to large end-use consumers, such as
Hindustan Petroleum Corporation Limited, ONGC, and a fertilizer company; and the balance
sold to smaller end-use consumers, such as power and fertilizer companies that are customers
of GAIL.
10. PLL’s gas sales price to end users is set commercially without any Government control.
The price consists of the LNG rate, taxes and duties, and a regasification charge that reflects
actual costs of LNG supply. As presented in the RRP, the gas price was estimated to average
$3.27 per MMBTU at PLL’s delivery point n the first 5 years of operation; and, after the offtakers
add transport charges and sales tax, $3.80 per MMBTU at the end-user point. This price was
considerably higher than the subsidized domestic gas price of $2.84 per MMBTU being charged
at the time of appraisal, though it was commercially attractive due to the substantial demand
supply gap in the market. PLL’s gas was expected to meet demand that was either not met at
all, causing capacity underutilization; or replace alternate fuels, such as naptha, that were more
expensive than PLL’s gas.
11. The Project was to be constructed under a lump sum, fixed price, date certain turnkey
EPC agreement with an international consortium selected through international competitive
bidding. PLL’s in-house staff was to operate and maintain the LNG terminal with technical input
from ONGC and a new strategic shareholder in PLL, Gaz de France International (GDFI). A
combination of equity and short-term bridging debt finance, was to fund project construction. As
part of the Project, the shareholding structure of PLL would be expanded from the four original
state-owned shareholders, which would retain a 50% interest with equal 12.5% shareholdings.
The remaining 50% ownership interest in PLL was to be allocated to (i) GDFI holding 10%; (ii)
ADB holding 5.2%; and (iii) public and other shareholders holding the remaining 34.8% of the
shares. The inclusion of offtakers and the supplier in the shareholding structure was intended to
help mitigate risks. As envisaged, the Indian public sector shareholding would not exceed 50%,
and would decline as a consequence of the proposed privatization of BPCL. ADB became a
shareholder to meet its charter requirements for an anchor investment to support its guarantee
operations, and these funds were to be injected in January 2004 after mechanical completion.
12. After the start of commercial operations, the Project was to be financed under a debt-
equity ratio that would not exceed 70:30. The 70% debt financing was to be sourced from local
currency ADB-guaranteed bonds (up to approximately 30.0% of total debt) and Indian
commercial bank debt (up to approximately 70.0% of total debt). The bonds were to be issued
after construction in April 2004. A charge on all of PLL’s assets, project documents, and cash
flows were to support the bonds in the first instance. Subsequently, a PCG that covered part of
the scheduled principal repayments and part of the scheduled interest payments on the bonds
was to provide support. ADB was given a position on the board of directors.

14. 4
C. Progress Highlights
13. PLL and a consortium led by Ishikawajima-Harima Heavy Industries Company Limited
signed the EPC agreement in January 2001. Construction was completed on schedule, and the
plant was mechanically complete in December 2003. At the same time, GAIL doubled the
capacity of the HBJ pipeline by laying a new 82 km pipeline from Dahej to Vemar, Gujarat; and
a 528 km pipeline parallel to the existing HBJ pipeline from Vemar to Bijaypur, Madhya Pradesh.
The Dahej–Uran pipeline identified in the RRP has not been constructed due to delays in the
tender process, and completion is now targeted for 2007. The first shipment of gas arrived from
Qatar in January 2004, initiating the commissioning period. Commercial supply commenced on
schedule in April 2004.
14. The actual project cost of the PLL plant was less in local currency terms than the initial
cost estimate in the RRP. This cost saving resulted from a decision by PLL not to proceed with
the construction of the breakwater that had been included in the original design. Originally, a
660-meter breakwater was included in phase I to restrict downtime during the monsoon period.
Based on the morphological data collected in the early stages of breakwater construction, PLL
concluded that the breakwater was not required. The plant could accommodate any potential
delays arising from the lack of a breakwater by increasing storage capacity, and an additional
LNG storage tank would provide greater operating flexibility. As a result, PLL decided to
reallocate breakwater funds to construct a third tank, which will be part of the phase II
expansion that will increase plant capacity to 10 MMTPA by 2009. Operating at 50% capacity in
2004, and then increasing to 100% in 2005, the terminal’s technical performance has exceeded
expectations at appraisal. LNG has been of high quality, supply and transportation risks have
not materialized, and the delivery of LNG to the regasification plant has not been delayed or
interrupted. Staff from ONGC and GDFI supported PLL staff for the initial period of operations
under a series of technical support agreements. A possible extension is being negotiated with
GDFI, primarily to address ship mooring safety issues.
15. The projected financial structure has been changed slightly, with a 34.8% stake
allocated to the public through an initial public offering (IPO) in March 2004. The price per
shares at IPO was Rs15, compared with the price at OEM appraisal of Rs60 per share. The
most important material departure from the financial structure presented in the RRP was the
failure to issue a PCG that could be used to support a bond issue. Due to adverse movements
in the Indian capital markets, bond financing was not seen as cost-effective. As a result, ADB’s
PCG was not issued, and the Project relied on local currency long-term debt finance from Indian
banks.
II. PROJECT EVALUATION
A. Overview
16. The evaluation criteria used for the Project are based on the best practice guidelines
prepared by the Evaluation Coordination Group of the Multilateral Development Banks on
Private Sector Operations, and the derived criteria incorporated in ADB’s draft Guidelines for the
Preparation of Performance Evaluation Reports of Private Sector Operations.1 Reflecting these
developments, ADB’s participation in the Project was evaluated using four criteria:
(i) development outcome, (ii) ADB’s investment returns, (iii) ADB’s effectiveness, and (iv) ADB’s
additionality. Overall, the Project was rated satisfactory.
1
ADB’s Operations Evaluation Department is preparing the guidelines, which will be finalized in 2006.

15. 5
B. Development Outcome
17. The initial criterion, development outcome, is rated excellent. It was evaluated using four
subcriteria: (i) private sector development, (ii) business success, (iii) economic sustainability,
and (iv) social and environmental impacts.
1. Private Sector Development
18. Private sector development impact is rated satisfactory (details are in Appendix 2–4). In
the RRP, the primary justifications for the Project were to (i) help meet growing energy demand
in North and West India; (ii) enhance energy security by diversifying the energy base; (iii)
contribute to economic development by providing additional and lower-cost alternate inputs to
the oil, power, fertilizer, and transport sectors; (iv) promote the use of clean energy; (v) provide
an example of good practice in public-private partnership (PPP) in infrastructure development;
and (vi) further develop the capital market for long-term, fixed-rate financing through the use of
the PCG. Overall, the RRP objectives were relevant. With the exception of capital market
development, the Project helped achieve the envisaged goals.
a. Beyond Company Impacts
19. In 1996, ADB provided TA to develop a master plan for the development of the natural
gas sector in India. The main objectives of this study were to (i) rationalize the projected
demand for natural gas, taking into account alternate energy sources and economic costs; (ii)
establish and analyze gas import alternatives; (iii) develop a plan for expansion of gas
infrastructure in India to meet the projected demand; and (iv) identify the economic, technical,
legal, and regulatory issues that need to be addressed as a result of the importation of natural
gas. The Government accepted ADB’s recommendations on gas industry liberalization and
commercialization, establishing the foundation for investments in a public-private partnership
structure. In 1997, ADB approved a TA to provide financial, legal, technical, and economic
advice and assistance to PLL to develop LNG importation and regasification facilities in Western
and Southern India. The second TA project focused on formulating a bankable project structure
for specific facilities to the established at Dahej in Gujarat state, and at Kochi in Kerala state.
The second TA also was successful, and led to the PLL project at Dahej. The Project was the
first investment that reflected tangible progress in liberalizing and commercializing the LNG
segment of the Indian gas industry, and in encouraging the use of a clean, environmentally
friendly fuel. Overall, these activities provide an excellent example of how ADB can create an
enabling environment through its public sector operations, and then catalyze private investment
through its private sector operations.
20. Development of the gas sector was important for India due to shortages of energy, as
well as the positive environmental impacts of using natural gas as an energy source. The power
sector accounts for the bulk of LNG demand (69%), followed by fertilizer and petrochemicals
(29%), with the balance consumed in sectors such as transport. Domestic fuel consumption is
growing following directives from the Supreme Court of India to increase the use of compressed
natural gas (CNG) as a fuel for the transport sector. Indraprastha Gas Limited (IGL) in Delhi and
Mahanagar Gas Limited (MGL) in Mumbai are developing city gas distribution projects for the
supply of CNG and piped natural gas in these cities. IGL is catering to about 94,246 vehicles of
different categories through 135 CNG stations. MGL has set up 105 CNG stations that serve
about 147,536 vehicles, mainly three-wheelers and cars.

16. 6
21. Coal is the main source of energy in India, though domestic supplies are low quality and
generate significant levels of harmful environmental emissions. While most of the coal is in
Eastern India, the majority of industrial demand is in Western India. This makes coal a high-cost
form of energy compared to alternative sources, such as LNG. The potential to increase the
availability of energy from other sources, such as nuclear and hydro power, is limited. Oil-based
products, such as naptha, have become expensive. Demand for natural gas in the fertilizer and
petrochemical sectors remains high. These circumstances are likely to continue for the
foreseeable future due to the continued price differential between natural gas and feedstock
substitutes, such as naptha.
22. The two main constraints on natural gas supply are inadequate reserves and a lack of
transmission capacity. The Bombay High fields and Gujarat produce the bulk of India’s natural
gas. However, these fields are relatively old, output is declining, and production is expected to
be exhausted by 2020. To help offset this decline in production capacity, the Government
opened the gas sector to private participation by awarding concession rights to public sector
joint ventures (JV) with private sector operators. In 1999, the Government developed the New
Exploration Policy (NELP), under which additional gas exploration concessions have been
awarded to private operators. As a result of these initiatives, a series of major new deep sea
gas fields have been discovered recently, especially by Reliance Industries Limited (RIL) in the
Krishna Godavari (KG) Basin off the coast of Andhra Pradesh in eastern Indian. These are
expected to substitute for the diminishing supplies from the existing fields.
23. The Government is developing additional transmission capacity. The Indian gas
transmission infrastructure has consisted of small regional pipelines and the HBJ pipeline
operated by GAIL, which carries gas from the offshore Mumbai High basin to fertilizer and
power plants in North West India. However, the capacity of the HBJ pipeline is sufficient to meet
only about 45% of India’s gas consumption. GAIL has expanded the Dahej–Bijaypur section of
the HBJ pipeline; and is building the Dahej–Uran gas pipeline, which is scheduled for
completion in 2006. GAIL also is developing a $4.4 billion National Gas Grid, which is expected
to cover the entire country. The 8,000 km project will be implemented in phases over the next
6–7 years. With the Government permitting private sector investment in gas transmission
infrastructure, RIL intends to build a 1,400 km pipeline from Kakinada to Ahemdabad via
Hyderabad and Uran in Maharashtra. The pipeline would transport the RIL’s reserves in the KG
Basin to the Gujarat power plants belonging to National Thermal Power Corporation. In addition,
RIL plans to build a pipeline from Hyderabad on the east cost to Delhi. Several smaller projects
are also are being implemented.
24. Despite these developments in the local gas industry, demand continues to outstrip
supply. To help bridge this gap, the Government has removed many of the restrictions on
importing gas, and some public and private sector companies are pursuing gas importation
options. Potentially, gas could be imported by pipeline from Iran, Turkmenistan, Bangladesh,
and Myanmar. However, none of these pipeline projects is expected to materialize in the next
4–5 years due to technical or political constraints, and LNG remains the most important source
of imported energy. India has only three LNG import terminals: (i) PLL’s Dahej plant with a
capacity of 5.0 MMTPA (equivalent to 17.5 million standard cubic meters per day [MMSCMD]);
(ii) the Dabol plant (recently renamed Ratnagiri Gas) also with a capacity of 5.0 MMTPA, which
is only beginning production after years of inactivity due to the collapse of Enron in 2001; and (iii)
the Hazira plant owned by Shell, which has a capacity of 2.5 MMTPA (equivalent to 8.8
MMSCMD) and began operation in April 2005. Reportedly, the Hazira plant is operating at only
about 5% of capacity due to its reliance on a merchant business model that is unsuitable for gas
user requirements. The current gas deficit has prompted PLL to accelerate the phase II

17. 7
expansion of its Dahej plant, increasing its capacity to 10.0 MMTPA. PLL also has started the
development of a 2.5 MMTPA LNG plant at Kochi, which was part of the TA concept
investigated in 1997. The plant should be operational by 2009. In addition, a new 2.5 MMTPA
plant is expected to be developed at Ennore in Tamil Nadu. This plant, which is being
developed independently of PLL, appears to have been catalyzed by the excess demand for
gas and by the demonstration effects of the PLL projects.
25. The current market structure uses gas prices that are administratively and market based,
although PLL’s LNG is competitive. The Government sets the consumer price of natural gas for
approximately 54% of the market at $1.80 per MMBTU, compared with PLL’s ex-terminal price
of $3.51 and a delivered price of $4.25 per MMBTU. Sourced from ONGC and OIL, the
subsidized gas is sold mainly to nominated consumers in protected sectors, such as power and
fertilizer. Although the Government announced in 1997 a program to eliminate these subsidies,
the program has stalled for political reasons. The proportion of the market that is subsidized is
expected to continue to decline over time. The Government subsidies are only sustainable as
the state-owned resources are sold at prices substantially below market rates. Available
supplies of subsidized gas are expected to fall as state-owned reserves are rapidly becoming
depleted. Approximately 20% of Indian gas consumption is sourced from JVs and private
concessions that are sold at market-linked prices (effectively market rates). The remaining 26%,
which is sourced from LNG, is sold at market rates. Gas produced from new fields will be priced
at market rates.
26. While gas importation and exploration are now substantially competitive markets, GAIL
continues to maintain a near monopoly on onshore transmission. The Petroleum and Natural
Gas Regulatory Bill, enacted in April 2006, established an independent gas regulator. The new
regulatory body, which will be separate from MOPNG, is expected to be established and staffed
later in 2006. The precise regulatory framework that will be introduced is not clear, although the
independent regulator will be responsible for downstream operations relating to transmission
and distribution. Regulations will be based on competitive principles that will help attract private
investment in transmission, and will ensure open access to existing monopoly facilities. Tariffs
will be cost-based, which will ensure that private gas supplies are sustainable. Like the power
sector, gas supply will be subject to the requirements of the Competition Commission.
b. Direct Company Impacts
27. PLL has demonstrated the high standards of performance that can be achieved by a
PPP managed on a commercial basis. PLL has helped increase firm access to gas at affordable
prices in Northern and Western Indian states, and now accounts for 20% of the country’s natural
gas. As natural gas provides 8%–9% of domestic energy consumption, the Project has
increased the available energy in India by 1%. As the first company to establish and operate a
commercial LNG plant in India, PLL has provided strong demonstration effects. Steps are being
taken to replicate the original concept applied at Dahej at other LNG sites. As relatively few
skills were available in India to operate the plant, PLL has successfully trained local staff
through the use of a management contract with GDFI, which has more than 30 years
experience managing LNG plants. Further, PLL has completed international standards
organization (ISO) programs for quality, environment, health, and safety procedures, confirming
that policies and procedures reflect world class norms.
28. Management and reporting systems are of a high standard. Accounts are prepared in
accordance with standards for publicly listed companies that reflect international accounting and
audit requirements. ADB has its own independent board representative, who has contributed to

18. 8
the development of high corporate governance standards by chairing the audit committee. The
private sector participated directly in the ownership of PLL through a highly successful initial
public offering (IPO) of 34.8% of the company’s shares. Offsetting these positive results, the
objective of stimulating bond market development was not achieved due to an adverse shift in
the cost of this form of finance, which obviated the need to issue a PCG and PLL bonds.
2. Business Success
29. Business performance is rated excellent.2 The recalculated real financial FIRR before
phase II expansion was higher than the estimate at loan approval. The assumptions and
analysis underpinning the FIRR calculation are in Appendix 5. The recalculated FIRR exceeds
PLL’s WACC. Project performance has been strong, and no material problems with supply,
plant operation, offtake, or gas pricing risks have arisen. PLL has a competitive advantage
relative to other energy companies through its long-term access to low-cost gas under the take-
or-pay contract with Rasgas, and its access to the GAIL transmission network. GAIL, IOC, and
BPCL procure the gas from PLL under take-or-pay arrangements that are very low risk,
although end-user demand ultimately will underpin the security of these arrangements.
30. Natural gas customers of the state-owned oil companies currently pay only $1.80 per
MMBTU, while private sector operators sell domestic gas at international prices that range from
$3.00 to $3.50 per MMBTU. Nevertheless, private firms remain competitive as the availability of
state-owned gas is declining, and not enough gas is available to meet consumer needs. LNG
imports from Dahej for the first 5 years have an external price of $3.51 and a delivered price to
end users of $4.25 per MMBTU. Although this price is slightly more than the market price of
local gas supplies, it is substantially less than naptha, which costs about $16.50 per MMBTU.
After 2009, PLL’s fixed procurement price for gas will become variable and linked to the Japan
crude oil cocktail (JCC) price, with a cap and floor. The move to a floating rate will increase
offtake risks, though this risk is substantially moderated by the rolling average cost of gas that
was secured contractually when gas prices were much lower than current market rates.
Table 1: Key Financial Ratios of Petronet LNG Limited
Item 2004A 2005A 2006 2007 2008 2009
Net Profit Margin (%) (0.01) 4.57 3.51 3.73 3.84 2.88
Return on Average Assets (%) - 15.30 12.19 12.69 13.45 12.85
Return on Average Equity (%) - 18.01 13.03 13.48 14.45 13.38
Current Ratio 1.65 3.01 2.84 2.32 2.11 2.00
Long-Term Debt: Total Assets (%) 50.00 49.1 46.6 42.8 38.7 32.9
( ) = negative, A = actual.
Sources: Audited accounts and PLL and ADB estimates.
31. Reflecting the near certain demand and low cost of gas, PLL’s financial performance has
been strong. In its first year of operations, PLL recorded a net loss of Rs284 million in 2004 as
the plant ran at 50% capacity. In 2005, the plant utilized 100% of its capacity utilization and
achieved a profit of Rs1,755 million, more than five times the appraisal estimate of Rs335
million. This improvement in projected performance, which is attributed to lower-than-expected
operating expenses and interest costs, is the reason for the material increase in the FIRR.
Sensitivity analysis of critical variables, such as the exchange rate and movements in the LNG
price, indicate that the FIRR is reasonably robust. Long-term debt as a percentage of total
assets does not exceed 50%. PLL has raised additional debt for the development of the Kochi
2
The rating scale is as follows: (i) excellent: FIRR > WACC + 2.5%, (ii) satisfactory: FIRR > WACC, (iii) partly
unsatisfactory: FIRR > WACC – 2%, and (iv) unsatisfactory: FIRR < WACC – 2%.

19. 9
plant, and might raise additional finance through the international sale of a convertible bond on
the Singapore exchange. This underscores the financial success of the PLL venture.
3. Economic Sustainability
32. Economic sustainability is measured by the EIRR generated by the Project, which aims
to capture the effects of competition, as well as externalities associated with social and
environmental impacts. The recalculated EIRR is 32.6%, which is excellent.3 Appendix 6 shows
the assumptions underpinning the EIRR calculation. The recalculated EIRR is higher than the
appraisal estimate of 23.0%. The end users for PLL gas are predominantly industrial users
along the expanded HBJ pipeline, consisting of fertilizer (40%), power (20%), petrochemical and
chemical (20%), and others (20%). These benefits are derived from the Project meeting unmet
demand (incremental), and generating substantial cost savings for firms that can switch from
naptha to gas (non-incremental). Sensitivity analysis indicates that these results are robust
under a wide range of scenarios.
4. Social and Environmental Impacts
33. While the Project was assigned an environmental rating of category A at appraisal, the
actual negative social and environmental impacts have been minimal. The main issues relate to
safety of the mooring facilities during the monsoon period. Details on social and environmental
impacts are in Appendix 7. PLL has provided positive social impacts by investing in local road,
water, and power infrastructure; and by providing emergency relief to local residents affected by
the earthquake that occurred in the region several years ago. During the 3 years of construction,
an average of 700 new jobs were created. About 160 staff are required for continuing operations
at the plant, and 50 staff are employed at the head office in Delhi. An additional 176 staff are
employed indirectly through shipping LNG (60 staff), outsourcing of jetty management (70 staff),
and security (46 staff). Approximately 15 squatters on the project site were resettled. State-
owned Gujarat Investment Development Corporation, which created the project site for
industrial use, addressed the associated issues before the Project started. The main forms of
compensation provided to the resettled parties were comparable land, and accommodation and
cash grants financed by PLL to cover daily living expenses during the construction of new
premises.
34. LNG is a cleaner source of energy than oil and coal. The environmental benefits of the
project arising from offsetting the use of coal are likely to be substantial due to the reduction in
energy-related emissions, such as carbon dioxide (CO2). Natural gas is about 32% cleaner than
coal. Conservative estimates of the value of these CO2 savings in India range from about $4.0 to
$24.0 million per year. These external environmental benefits were not included in the EIRR due
to difficulties in precisely quantifying them. Additional economic benefits are being generated by
the project site, where the high quality of the technology and strong management team have
resulted in virtually zero emissions. However, some safety issues still are being resolved. The
LNG terminal has limited environmental impacts. PLL has complied with all necessary
environmental regulations. Independent third parties audit the annual and quarterly reports,
which are submitted to MOEF, GPCB, and Forests and Environment Department of the
government of Gujarat. The terminal has received ISO certification for its processes and
procedures for quality (ISO 9001), environmental management (ISO 14001), and occupational
3
The rating scale is as follows: (i) excellent: EIRR > 18%, (ii) satisfactory: EIRR > 12%, (iii) partly unsatisfactory:
EIRR > 6%, and (iv) unsatisfactory: EIRR < 6%.

20. 10
health and safety management (ISO 18001). PLL’s Dahej plant was the first LNG facility in the
world to achieve accreditation within 1 year of operation.
35. The Project’s major environmental risks are associated with safety. PLL has prepared
various emergency response plans. The terminal has achieved 2.73 million accident-free hours
of operation to date. In October 2005, the National Safety Council conducted a safety audit and
made recommendations for improving systems and procedures. The main issues that have
arisen involve the safety of the jetty and ship mooring operations due to strong currents, high
winds, and large waves during the monsoon season (May to September). As originally
envisaged, a breakwater was to be constructed to help mitigate the effects of wind and waves.
Construction started and then was halted following an analysis that concluded the breakwater
would not mitigate these effects. A program is being developed to remove rock debris that was
being used to construct the breakwater, and this will increase ship maneuverability. GDFI is
providing assistance to develop and refine safe mooring procedures. In the event of an accident
at the terminal, the effects probably would not extend beyond the boundaries of the plant site.
C. ADB’s Investment Returns
36. PLL is in a strong financial position, which is reflected in the substantial appreciation in
ADB’s equity shareholding in the company. Offsetting this result, ADB did not issue the PCG as
envisaged at appraisal because it was not commercially attractive. While no direct costs arose
from the PCG, an opportunity cost was associated with the facility.
D. ADB’s Effectiveness
37. ADB’s effectiveness is rated satisfactory, based on an evaluation of screening, appraisal,
and structuring; and monitoring and supervision.
1. Screening, Appraisal, and Structuring of the Project
38. Screening, appraisal, and structuring are rated satisfactory. Screening refers to
relevance of the Project in achieving ADB’s strategic objectives, as defined in its country and
sector strategy documents; and in complying with policies on private sector development, and
social and environmental protection. The Project met these requirements to a high degree. By
establishing a commercially viable and environmentally friendly LNG plant, the Project
supported the country strategic program (CSP) objectives of removing impediments to the
liberalization and growth of privately financed energy infrastructure in India. In the view of PLL
management, ADB’s appraisal was of a high standard, and the investment approval process
was performed rapidly. The assumptions underpinning the Project have materialized largely as
envisaged in the RRP. The primary weakness in the Project related to ADB’s performance was
the PCG, which proved not to be commercially viable. This was due mainly to unforeseen
adverse movements in the market.
2. Monitoring and Supervision Quality
39. Monitoring and supervision quality was satisfactory. Monitoring appears to have been of
a high standard. PSOD staff visited PLL headquarters and the plant site regularly, although
most of these visits focused on arranging financing for the phase II expansion. The documents
on the subscription agreement and insurance documents are in order. The main issue with the
monitoring arrangements involved environmental and social safeguard policies, where
regulatory reports were not supplied to ADB quarterly as stipulated in the equity subscription

21. 11
agreement. Following a review of the regulatory reports submitted to the Government, the
Operations Evaluation Mission (OEM) confirmed PLL compliance with regulations.
E. ADB’s Additionality
40. Additionality is defined as the extent to which something happens as a result of an
intervention that would not otherwise have occurred in the absence of the intervention. The
Project has been successful from the perspective of stimulating development, liberalizing the
energy market, encouraging private sector investment, and creating a strong company that has
had significant demonstration impacts. In discussions with the OEM, PLL management said
ADB played a critical role in liberalizing the market before the investment. While the construction
program was largely complete by the time PSOD participated, ADB helped mitigate investor and
lender concerns regarding a new and untested product and technology in India, where locally
available skills and experience were limited. ADB also helped facilitate corporate governance
through the introduction of an independent private director to the board. ADB’s direct board
representative, who has important international experience, chairs the board’s audit committee.
41. Offsetting this result, ADB was not able to pursue the pioneering issuance of a PCG
equivalent to $65 million. As a result, ADB did not stimulate the development of the local bond
market. This bond transaction never materialized due to adverse market movements that were
beyond the control of the participants. In 2001, the International Finance Corporation had
successfully issued PCGs to support the mobilization of local currency financing for several
large Indian companies, such as Bharti Mobile Limited. Thus, the product appeared attractive
and feasible. However, subsequent movements in interest rates meant that firms could access
funds from the domestic market using a swap at less cost than issuing bonds in the local market.
This price differential has persisted and continues to favor swaps over local bonds as a source
of local currency.
F. Overall Rating
42. The Project received an overall rating of satisfactory. The evaluation criteria were
development outcome, ADB’s investment profitability, ADB’s operational effectiveness, and
project additionality. Based on the analysis in Section II, the ratings are presented in Table 2.

22. 12
Table 2: Evaluation of the Petronet LNG Limited Project
Partly
Item Unsatisfactory Satisfactory Excellent
Satisfactory
Development Outcome X
Private Sector Development X
Business Success X
Economic Sustainability X
Contribution to Living
Standards X
Environmental Performance X
ADB’s Investment
Profitability X
ADB’s Effectiveness X
Screening, Appraisal, and
Structuring X
Monitoring and Supervision X
ADB’s Additionality X
ADB = Asian Development Bank.
Source: ADB Operations Evaluation Mission.
43. Development outcome is rated satisfactory based on an assessment of the following five
subcriteria: (i) private sector development was rated satisfactory, as the objectives of catalyzing
private investment in a competitive natural gas industry are being achieved to a significant
extent, and PLL has demonstrated strong corporate performance, though capital market
development goals were not attained; (ii) business success is rated excellent, as the
recalculated FIRR exceeds the WACC; (iii) economic sustainability is rated excellent, as the
EIRR of 32.6% was higher than expected due substantial cost savings and incremental demand
arising from improved availability of gas; (iv) contribution to living standards is rated satisfactory,
as PLL has helped develop local infrastructure and create jobs, without any material
resettlement or indigenous people issues; and (v) environmental performance is rated excellent,
based on the substantial reduction in energy-related emissions, such as CO2, due to improved
availability of gas offsetting the use of coal. In addition, the plant site has generated virtually
zero emissions due to the high quality of the technology and strong management team,
although some safety issues still are being resolved. ADB’s second criterion, investment
profitability, is rated excellent. ADB’s operational effectiveness is rated satisfactory. Screening,
appraisal, and structuring, as well as monitoring and supervision, have been of a high standard,
aside from the limited follow-up on collecting outstanding environmental impact reports. ADB’s
additionality is satisfactory. While not participating until construction was almost complete,
ADB’s presence helped crystallize industry reforms, strengthen corporate governance, and
support partial privatization of PLL.
III. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS
A. Project Issues
44. Due to ADB’s involvement in the Project only a few months before operations
commenced, the relatively short period since operations began, and the robust business model,
variations from the expectations presented in the RRP have been limited. The main differences
were as follows:

23. 13
(i) The price of oil and natural gas has increased dramatically following ongoing
geopolitical problems in the Middle East.
(ii) GAIL has not completed the construction of the Dahej–Uran pipeline.
(iii) The breakwater was not constructed. It has been replaced with a new LNG
storage tank as part of the phase II construction program, resulting in a cost
saving.
(iv) The Government has not divested its majority shareholding in BPCL. As a result,
PLL continues to be majority state-owned.
(v) ADB did not issue its PCG due to unforeseen adverse market movements.
B. Lessons
45. Based on the developments outlined in Section II, ADB could improve its performance
by considering the following factors when designing projects:
46. Private Sector Development. ADB played a central role in the liberalization and reform
of the Indian gas sector, and then catalyzed a series of important PPP investments in LNG
facilities. As such, the Project provides an excellent example of how ADB’s Private Sector
Development Strategy can work in practice. Some of the most important private sector
development benefits involved discoveries of domestic gas by Indian private sector companies,
independent of PSOD participation. An important issue that emerges from the analysis of
private sector impacts is the long gestation period required for enabling environment reforms to
flow through to tangible PSOD investments and loans. In many respects, these delays were
necessary to provide the Government time to implement reforms before ADB and private
investors could commit funds. A precondition for the investment was the certainty that the
planned changes would occur within the industry. The sponsors did not perceive access to
ADB’s funding per se as the most important benefit of ADB participation. Rather, the sponsors
were more interested in the leveraging effect of ADB involvement, even through a small equity
participation.
47. Revenue and Cost Projections. The price forecasts for PLL gas in the RRP were
based on an assumed price of $29 per barrel, well below the price of approximately $75 per
barrel at the time of the OEM. Similarly, significant cost savings on capital expenditure were
realized, even though ADB participation occurred only months before project completion. These
adjustments highlight the random volatility inherent in commodity products, as well as the need
for aggressive sensitivity analyses—especially for downside scenarios—to ensure that credit
risks are managed adequately.
48. Social and Environmental Impacts. The Government was well organized when dealing
with social impacts, keeping risks associated with resettlement with the public sector agency,
Gujarat Industrial Development Corporation. Similarly, GAIL retained the risks associated with
the development of the gas transmission network, effectively eliminating any negative social and
environmental impacts from construction and commercial performance. PLL’s operations have
had positive impacts through employment, with an increasing number of local staff being
employed over time. Environmental operational impacts have been negligible due to the nature
of LNG, and the associated technology that resulted in almost zero emissions. The safety of the
mooring operations is the primary outstanding issue associated with externalities. Safety risk
has very localized physical impacts. The more serious risks involve PLL compliance with
commercial take-or-pay obligations, which probably would fall under force majeure provisions.

24. 14
49. Ownership Structure. As envisaged in the RRP, a chain-type ownership structure
would be adopted, allowing the Government, buyers, and a supplier to have an ownership
interest in the facility that would help minimize commercial risks. In many cases, equity
ownership can complicate buyer and supplier incentives unnecessarily. Ideally, reliance should
be placed on input and output contracts wherever possible to minimize risks of conflicts of
interest. Another important feature associated with PLL’s ownership structure was an
assumption in the RRP that the Government would divest its majority shareholding in BPCL,
thereby handing majority ownership of PLL to private investors. Although the divestment has not
occurred, it does not appear to have created a problem. However, international evidence
suggests that a privatized PLL will achieve better commercial results over time.
50. Financial Structure. Indian banks have been prepared to lend to PLL on a secured
basis due to the financial strength of the buyers and the high level of Government involvement
in the Project. As the lead arranger and financier of PLL, the Government-owned State Bank of
India raised the issue of how ADB participation adds value to Indian PPP infrastructure projects.
The primary benefits relate to access to private sector funds. Despite having a relatively
sophisticated banking sector, India still lacks access to sufficient long-term funds to finance
necessary infrastructure projects. This makes private sector participation increasingly important,
and ADB can play a central role in allaying investor and lender concerns.
51. Partial Credit Guarantee. The potential benefits arising from the application of a PCG
were one of ADB’s primary motivations for participating in the Project. However, the PCG was
not used due to adverse movements in the market. At loan appraisal, international financial
institutions, such as the International Finance Corporation, had used guarantees successfully to
support local currency bond issues. Subsequently, however, corporate bond market activity was
limited, and the market for raising local currency through the use of swaps became much more
active. ADB has the capacity to participate in this market on favorable terms due to its AAA
credit rating.
C. Follow-Up Actions
52. No follow-up actions are required, although ADB is recommended to exit its equity
participation as soon as practicable. The main development objectives of the equity
participation—i.e., allaying financiers concerns and strengthening governance provisions—have
been largely achieved. ADB can exit safely through the share market. No outstanding social and
environmental actions are required by ADB. Given the potential for substantial shifts in the
market between ADB’s approval and financial drawdown, a degree of flexibility needs to be
incorporated in the structures presented in Board documents.

25. Appendix 1 15
PRIVATE SECTOR DEVELOPMENT INDICATORS AND RATINGS
Annotations and Ratings
Potential Future
Impact
Assessed and Risk to
Impact Realization Combined
Change Attributable to the PSO to Datea Impact Riskb Rate Justification
A. Beyond Company Impacts
1. Improved laws, frameworks, and sector 4.0 4.0 4.0 4.0 ADB has played an important
institutions role developing the enabling
environment for natural gas
2. Pioneering or increased private sector 4.0 4.0 4.0 4.0 Private investment is occurring
role in the country’s natural gas sector in LNG
and more widely
3. Pioneering or enhanced competition (to 4.0 4.0 4.0 4.0 Private competition is being
state natural gas monopolies, early introduced into the LNG sector
concession operators, or others)
4. Relative to investments, significant 3.0 3.0 4.0 3.0 Project is helping to stimulate
economic links to previously underserved private investment in North
regions and business sectors (including West India
SMEs); and more productive employment
for reached social groups for poverty
reduction, including women
5. Pioneering or catalytic finance to 2.5 3.0 4.0 3.0 ADB could not use its partial
enhance market funding prospects for credit guarantee to support a
more investments in the natural gas bond issue, although a
sector subsequent follow-on ADB
financing facility has been
approved
B. Direct Project Company Impacts
1. Know-how: internalized management 3.5 3.0 4.0 3.5 Leading-edge LNG technology
and operational skills introduced
2. Achieved standards of the company:
(i) against global industry performance 3.5 3.0 4.0 3.5 Standards compare with
and service quality benchmarks developed countries
(ii) in corporate governance, transparency, 3.5 3.0 4.0 3.5 Excellent environmental, safety,
worker relations, health and social and corporate governance
security
3. Direct employment impact in relation to 3.0 3.0 3.0 3.0 Capital- rather than labor-
the amount of investments intensive
c 3.5 Satisfactory
Overall Rating
LNG = liquefied natural gas, PSO = private sector operations, SME = small and medium-sized enterprise.
a
Impact: excellent (4), satisfactory (3), party unsatisfactory (2), unsatisfactory (1).
b
Risk: low (4), modest (3), medium (2), high (1).
c
The calculation of the overall rating for private sector development impact is not arithmetic.
Source: Draft Guidelines for the Preparation of Performance Evaluation Reports of Private Sector Operations.

26. 16 Appendix 2
DEVELOPMENTS IN THE INDIAN GAS MARKET
A. Overview of the Natural Gas Sector in India
1. Liquefied Natural Gas (LNG) is one of the fastest growing fuels in the world, with
average annual usage rising about 8% over the past 5 years. Natural Gas is a clean and
environment-friendly fuel that can comply with stringent emission standards in power generation
and industrial processes. It is also used as compressed natural gas (CNG) in the transport
sector, helping reduce vehicle emissions. In India, substantial reserves of natural gas have been
discovered onshore and offshore. While the availability of gas is expected to improve, the
demand for energy is expected to grow more quickly. At –160O C, natural gas becomes liquid
and its volume shrinks by 600 times, facilitating its transportation for trade.
2. With crude oil prices at around $75 per barrel (BBL), LNG has emerged not only as a
clean source of energy, but also as a cost-effective fuel. Several industries in the country are
using more expensive liquid fuels (naphtha and fuel oil, low-sulfur heavy stock) as sources of
energy and carbon feedstocks. The indigenous availability of natural gas is unable to meet the
demand of natural gas, and the reserves are declining steadily. As such, the importation of LNG
is increasingly important. India is strategically located close to the large gas reserves in the
Middle East and the Asia-Pacific countries. These countries hold 70% of the world’s LNG
liquefaction and export facilities. Globally, gas accounts for nearly 23% of commercial energy
consumption. Natural gas accounts for only 9% of the Indian energy basket due to domestic
supply constraints. The Government of India (the Government) is seeking to identify options to
increase natural gas consumption within India.
B. Demand and Supply of Natural Gas
3. Lack of access constrains the demand for natural gas. If additional supplies of LNG were
made available within the country, through discoveries of further reserves and expansion of of
pipeline distribution capacity, the use of gas could be much higher. Table A2.1 shows various
supply scenarios based on a Government study, Hydrocarbon Vision 2025.
Table A2.1: Future Gas Deficit Scenarios
(MMSCMD)
2002 2007 2012 2020
A. Demand Scenario 1 117 166 216 322
Supply
1. As given scenario 70 58 45 36
2. Optimistic scenario 70 64 78 84
Gap (as given) 47 108 171 286
Gap (optimistic) 47 102 138 238
B. Demand Scenario 2 151 231 313 391
Supply
1. As given scenario 70 58 45 36
2. Optimistic scenario 70 64 78 84
Gap (as given) 81 173 268 355
Gap (optimistic) 81 167 235 307
MMSCMD = million standard cubic meters per day.
Source: Hydrocarbon Vision 2025.

27. Appendix 2 17
4. In 2005, the Ministry of Petroleum and Natural Gas (MOPNG) estimated in its annual
report that the energy sector accounted for 69% of natural gas consumed in India, while the rest
was used primarily as feedstock in the fertilizer and petrochemical industries. The energy and
fertilizer sectors are allocated state-owned gas at subsidized prices, although they are free to
purchase gas from private sources at market rates if they wish. The most rapid sources of
growth between 2004 and 2005 are the domestic fuel sector (269%), followed by industrial fuel
(16%) and petrochemicals (10%). Domestic fuel consumption is growing following directives
from the Supreme Court of India to increase in the use of CNG as a fuel for the transport sector.
Indraprastha Gas Limited (IGL) in Delhi and Mahanagar Gas Limited (MGL) in Mumbai are
developing gas distribution projects for the supply of CNG and piped natural gas in these cities.
IGL is catering to about 94,246 vehicles of different categories through 135 CNG stations. MGL
has set up 105 CNG stations to service about 147,536 vehicles, mainly three-wheelers and cars.
5. The two critical supply constraints are inadequate reserves of natural gas and lack of
distribution capacity. The geographic distribution of India’s gas reserves is as follows: (i)
western offshore, 54%; (ii) onshore Gujarat region, 13%; (iii) onshore Andhra Pradesh region,
6%; and (iv) others, 27%. The western offshore area (Mumbai High Basin) supplies most of
India’s gas. Assam, Andhra Pradesh, and Gujarat states also produce major volumes of gas,
followed by Tripura, Tamil Nadu, and Rajasthan. About 60% of India’s natural gas is associated
with oil. The south basin and Tapti fields in the western offshore area, the gas fields in the
western offshore area, and the gas fields in Tripura and Andhra Pradesh Krishna Godavari (KG)
Basin produce most of India’s non-associated gas. The majority of the western offshore gas
supply, including Mumbai High Basin, is expected to gradually die out by 2020.
6. In terms of volume, India’s proven gas reserves at the beginning of 2004 stood at 0.85
trillion standard cubic meters (SCM). The Government has been actively encouraging private
sector investment in exploration and development under the New Exploration Policy (NELP),
which is used to tender concessions to firms in the public and private sectors. The NELP
program has been successful. A recent gas discovery of more than 0.283 trillion SCM in the KG
Basin by the private company Reliance Industries Limited (RIL) increased India’s reserves
significantly, and more is expected to be found. Gujarat State Petroleum Corporation made an
estimated 0.566 trillion SCM discovery in the KG Basin that is potentially the largest gas find in
India. Other companies, such as Oil and Natural Gas Corporation of India (ONGC), also have
found gas in KG Basin. RIL has discovered additional gas reserves in three Bay of Bengal wells
off the coast of Orissa, where potential reserves could total 0.142 trillion SCM. In addition to
natural gas reserves, the Government has developed a policy to extract methane trapped in
coal seams that can be used as an energy source. Coal-based methane resources are
estimated at about 820 billion cubic meters (BCM), with expected production of about 23 million
standard cubic meters per day.1
7. The two national oil companies—ONGC and Oil India Ltd (OIL)—accounted for 79.66%
of the natural gas production in the country, with ONGC accounting for the larger share. The
private sector’s share in natural gas production has increased from 2% in 1997 to 21.34% in
2005, and is expected to rise further as several NELP fields start yielding natural gas.
1
http://www.dghindia.org/cmb_listofblocks.html, last accessed on 7 November 2005

28. 18 Appendix 2
Table A2.2: Company Production of Natural Gas
(MCM)
Year Oil ONGC Private/JV Total
1995/96 1,433 20,875 331 22,639
1996/97 1,496 21,281 479 23,256
1997/98 1,670 23,050 1,681 26,401
1998/99 1,713 22,841 2,874 27,428
1999/00 1,729 23,252 3,465 28,446
2000/01 1,861 24,020 3,596 29,477
2001/02 1,619 24,041 4,054 29,714
2002/03 1,744 24,244 5,407 31,395
2003/04 1,880 23,584 6,491 31,955
2004/05 2,007 22,985 6,782 31,774
OIL = Oil India Ltd., ONGC = Oil and Natural Gas Corporation Ltd., JV = joint
venture, MCM = million cubic meters.
Source Ministry of Petroleum and Natural Gas (2005).
8. In addition to the shortage of domestic gas reserves, the Indian gas market has limited
transmission infrastructure. It consists of small regional pipelines, and the Hazira–Bijaipur–
Jagdeshpur (HBJ) 2,300 kilometer (km) pipeline that carries gas from the offshore Mumbai High
Basin to fertilizer and power plants in North West India. The capacity of the HBJ pipeline is
about 1.18 billion cubic feet per day (bcfd), which is sufficient for about 45% of India’s gas
consumption. The HBJ pipeline, operated by GAIL India Limited (GAIL), carries Petronet LNG
Limited’s (PLL) LNG imports through the state of Gujarat. GAIL is expanding the Dahej–Bijapur
section of the HBJ pipeline; and building the Dahej–Uran gas pipeline, which is scheduled for
completion in 2006. GAIL also is developing the $4.4 billion National Gas Grid, which is
expected to cover the entire country. The 8,000 km project will be implemented in phases over
the next 6–7 years. GAIL intends to build and operate an east-to-west truckline linking Kakinada
port in the Bay of Bengal to Hazira in the Arabian Sea. With the Government permitting private
sector investment in gas transmission infrastructure, RIL intends to build a 1,400 km pipeline
from Kakinada to Ahemdabad via Hyderabad and Uran in Maharashtra. The pipeline would
transport RIL’s reserves in the KG Basin to the Gujarat power plants belonging to National
Thermal Power Corporation. In addition, RIL plans to build a pipeline from Hyderabad on the
east cost to Delhi. Several smaller projects also are being implemented, including (i) a 600 km
pipeline from Visakhapatnam to Secundrabad in Andhra Pradesh; (ii) a 700 km pipeline from
Managalore in Karnataka to Madurai in Tamil Nadu; and (iii) a 575 km pipeline that will connect
PLL’s Kochi LNG terminal to Kerala.
9. Despite the increasing private investment, recent discoveries of domestic natural gas
reserves, and improvements in the transmission network, demand continues to outstrip supply.
To help bridge this gap, some public and private sector companies are pursuing gas importation
options. In 2004, PLL commissioned the first LNG terminal in India at Dahej, Gujarat. The PLL
terminal has a capacity of 5.0 million metric tons per annum (MMTPA). In April 2005, a second
LNG terminal with a capacity of 2.5 MMTPA was commissioned at Hazira, Gujarat by Royal
Dutch Shell Group and Total Gaz Electricite Holdings of France, which are the joint owners and
operators of the terminal. The Hazira plant sources gas from the spot market instead of using
the conventional system of purchasing gas through long-term sales and purchase agreements.
Few other LNG terminals have been planned along the east and west coast of the country.
Details of LNG terminals in India are summarized in Table A3.3.

29. Appendix 2 19
Table A2.3: Details of Commissioned and Proposed LNG Terminals in India
Project and Developers Location and State Capacity Supplier Status
(MMTPA)
Dahej LNG terminal Dahej (Gujarat) 5 (to be Qatar (5.0 + Commissioned in February
(Petronet) expanded to 10) 2.5 MMTPA) 2004, the terminal began
commercial sales in April
2004. Expansion to be
completed by 2008
Dabhol terminal Dabhol (Maharashtra) 5.0 Oman, Complete; commissioning
(GE/Bechtel/MSEB) Abu Dhabi delayed by contractual
dispute
Hazira LNG (Shell) Hazira (Gujarat) 2.5 (phase I), Shell Commissioned in April
5.0 (phase II) Portfolio 2005
Kochi LNG (Petronet) Kochi (Kerala) 2.5 In discussion Project expected to be
completed by 2008
Ennore LNG Ennore (Tamil Nadu) 2.5 Iran Planned
(IOCL, CPCL)
CPCL = Chennai Petroleum Corporation Limited, GE = General Electric, IOCL = Indian Oil Corporation Limited, LNG =
liquefied natural gas, MMTPA = million metric tonnes per annum, MSEB= Maharashtra State Electricity Board.
Source: TERI (2005).
10. Developers are investigating the potential for importing LNG via pipelines from
neighboring countries. Several pipelines have been proposed to serve the Indian market,
originating from Iran, Myanmar, Bangladesh, and Turkmenistan. The most likely international
pipeline is the 2,600 km overland pipeline connecting the South Pars field in Iran with the HBJ
pipeline in India via Pakistan. In June 2005, the Government signed a $20 billion contract with
Iran to import 5.0 MMTPA of LNG for 25 years, beginning in 2009. National Iranian Oil Company
would supply this gas from its South Pars gas field. The destination ports for the gas in India are
the Dahej and Kochi terminals. The negotiated price for the deal is $3.21 per million British
thermal units (MMBTU). This price includes a fixed component of $1.20 per MMBTU and a
variable component linked to the Brent price, which has been capped at $31 dollars per BBL.2
The current status of this deal is unclear, as Iran has asked for an increase in the price of
natural gas and has sought to limit supply to lean gas that excludes various carbon components
unrelated to energy content.
C. Pricing and Regulation
11. In the gas sector, prices are both administratively and market based. ONGC and OIL sell
gas from the pre-NELP blocks to GAIL under the administered pricing mechanism (APM). In
1997, the Government sought to achieve parity between fuel oil prices and gas, though this
policy has been ineffective. As a result, gas sold under the APM continues to be allocated at
prices substantially below market rates for gas and transmission costs. The APM price of gas
for the North Eastern region is approximately 60% of the new price. The matter of fixing the
producer price of natural gas has been referred to the Tariff Commission, a body under the
Ministry of Commerce and Industry that is serving as a de-facto regulator. For gas produced
under the NELP blocks, output can be sold at market-determined prices defined in the
negotiated production sharing contracts and gas sales agreements.
2
Times of India. 2005. India, Iran sign $20-billion LNG deal. 14 June.

30. 20 Appendix 2
12. Similarly, imported regasified LNG sourced from the PLL and Shell plants is sold at
market-determined prices. PLL has signed an agreement with Ras Laffan Liquefied Natural Gas
Company Limited (RasGas) of Qatar for the supply of 5.0 MMTPA of LNG for 25 years at a free
on board (FOB) price of $2.53 per MMBTU for the first 5 years of operation, starting in 2004.
After accounting for items such as shipping, customs duties, pipeline charges, regasification,
and sales tax, the delivered price is $4.25 per MMBTU. After 2009, the fixed price will become a
variable price for a 60-month transition period. The participating parties have agreed to an
increase of $0.13 per MMBTU for each $1.00 increase in the price of oil above $20 per BBL.
This formula does not have a ceiling, allowing the price of LNG to rise to more than $6 per
MMBTU if the price of oil stays at more than $50 per BBL. At this stage, PLL’s delivered gas
price is very competitive relative to the Hazira terminal gas. Royal Dutch Shell, which has been
promoting its Hazira terminal as a merchant terminal, sourced its first LNG consignment from
Australia’s North West Shelf project at a price of $3.70 per MMBTU, which is significantly higher
than PLL’s purchase FOB price. RIL’s gas discovery in the KG Basin will affect the future
competitiveness of LNG imports. RIL recently agreed to supply National Thermal Power
Corporation a delivered consumer price of $2.97 per MMBTU in Gujarat, although this
transaction is seen as a one off loss leader.
13. Demand for natural gas depends primarily on its competitiveness relative to other fuels,
as well as the price absorption capacity of its primary users (power and fertilizer). The use of
natural gas and LNG in the power sector depends on its competitiveness with respect to coal
and liquid hydrocarbons, such as naphtha, low-sulfur heavy stock, and fuel oil (which are used
sparingly). The eastern states of Bihar, Madhya Pradesh, and Orissa hold 70% of the country’s
coal reserves. The pithead coal price in the east averages about $12 per ton, and the freight
cost from east to west can add another $12 per ton. Given coal’s relatively high transport costs,
the economics of gas for power generation differ from one area of the country to another,
resulting in a differentiated electricity market. As a rough guideline, if natural gas is priced at
$3.00–$4.00 per MMBTU in the western and southern parts of the country, it can compete with
coal. LNG is likely to be most competitive in these regions, especially if a power plant is close to
the regasification terminal and transmission costs are avoided. For the fertilizer sector, the
Government provides huge ($2.6 billion) annual subsidies. Many fertilizer plants use expensive
fuel oil and naphtha, because they have little incentive to switch fuels under the Government’s
subsidy program. Recently, however, the Government has been promoting the use of natural
gas as a feedstock in the production of urea, and plans to convert many fuel-fed plants to gas.
As fertilizer imports are a viable long-term option, the netback of gas used in domestic urea
production versus urea imports needs to be priced at about $3.00 per MMBTU to stay
competitive.
14. Transportation fees charged by GAIL for delivering gas over its pipelines are regulated.
The legislation establishing the Petroleum and Natural Gas Regulatory Board, enacted in April
2006, is designed to set up a regulatory body to oversee and regulate the refining, processing,
storage, transportation, distribution, marketing, and sale of petroleum products and natural gas.
The Government’s gas industry policy lays out the role of the regulator in preparing a long-term
plan for the gas pipeline network. The policy proposes that the regulator should adopt a
nondiscriminatory approach when deciding on access arrangements for the gas pipeline, and
should consider the common carrier principle to ensure equal opportunities for all users.

31. Appendix 3 21
REVIEW OF PETRONET LNG’S OPERATIONS
A. Background
1. In 1997, the Government of India (the Government) helped create Petronet LNG Limited
(PLL) to develop and import liquefied natural gas (LNG) at various coastal locations. PLL was to
bridge the large gap between the demand and supply of natural gas in the country. PLL is the
first company in India and South Asia to import LNG and successfully set up a LNG
regasification terminal. The 5.0 million metric tons per annum (MMTPA) LNG receiving and
regasification terminal at Dahej, Gujarat state (the Project) has been constructed and
commissioned in record time at a benchmark cost. During the buildup period in 2004, the Dahej
LNG terminal operated at 50% capacity, but from 2005 onward the plant has been capable of
operating at 100% capacity. Regasified LNG from Dahej terminal is supplying consumers in
Gujarat and along the recently upgraded Hazira–Bijaipur–Jagdishpur (HBJ) pipeline, traversing
the states of Madhya Pradesh, Rajasthan, Uttar Pradesh, Haryana, and Delhi. GAIL (India)
Limited (GAIL) is constructing about 485 kilometers (km) of additional pipeline from Dahej LNG
terminal to Uran in Mumbai.
2. The increased availability of gas has generated important benefits for the Indian
economy. The Project has spurred market liberalization and commercialization of the LNG
industry. PLL’s customer base is broken down as follows: power sector, 70%; fertilizer, 15%;
and others, 5%. As a result, the Project has had the greatest impact in the power sector, which
uses expensive naptha ($15–$18 per million British thermal units [MMBTU]) for generation. The
fertilizer sector has benefited from the Project, as expensive and low-energy naptha has been
replaced with natural gas in many cases to produce urea. Several industries have shifted to
captive power generation systems based on natural gas, which is more efficient. These
developments have freed up power for other sectors. In addition to economic benefits arising
from increasing energy efficiency, natural gas utilization has generated environmental benefits
by producing less carbon dioxide (CO2) emissions than other sources of energy and carbon
feedstocks. Additional benefits could be realized in the future as companies, such as GAIL and
Oil and Natural Gas Corporation Limited (ONGC), are able to extract high carbon components
from the rich PLL gas, without lowering the energy content. This would provide low-cost inputs
for sectors such as petrochemical manufacturing. The PLL plant has provided the Indian gas
sector with much-needed technical expertise in the design, operation, and maintenance of LNG
terminals.
B. Description of Major Project Components
3. The PLL facility is based on a concession agreement signed with Gujarat Maritime
Board, which provided a 99-year lease for a 58.6 hectare site, and a 30-year agreement to
develop and use a port facility. The government of Gujarat had not approved the draft at the
time of the Operations Evaluation Mission. PLL also signed a 25-year LNG supply contract with
Ras Laffan Liquefied Gas Company (Rasgas), based in Qatar, in July 1999. The contract
initiated construction of various facilities for suppliers and buyers of the LNG. Rasgas has
developed offshore gas production facilities in the North field of Qatar, as well as a dedicated
liquefaction train with 5.0 MMTPA capacity. It was commissioned to meet the requirements of
the Dahej terminal, and became fully operational in March 2004. The North field of Qatar is the
largest gas field in the world, which helps ensure the security of LNG supplies throughout the
contract.