Your SlideShare is downloading. ×
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
37905 ind-pper
Upcoming SlideShare
Loading in...5
×

Thanks for flagging this SlideShare!

Oops! An error has occurred.

×
Saving this for later? Get the SlideShare app to save on your phone or tablet. Read anywhere, anytime – even offline.
Text the download link to your phone
Standard text messaging rates apply

37905 ind-pper

842

Published on

0 Comments
0 Likes
Statistics
Notes
  • Be the first to comment

  • Be the first to like this

No Downloads
Views
Total Views
842
On Slideshare
0
From Embeds
0
Number of Embeds
0
Actions
Shares
0
Downloads
0
Comments
0
Likes
0
Embeds 0
No embeds

Report content
Flagged as inappropriate Flag as inappropriate
Flag as inappropriate

Select your reason for flagging this presentation as inappropriate.

Cancel
No notes for slide

Transcript

  • 1. Performance Evaluation ReportProject Number: 37905Equity Investment Number: 7192November 2006India: 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 PolicyNOx – nitrogen oxidesO&M – operation and maintenanceOCR – ordinary capital resourcesOEM – Operations Evaluation MissionOIL – Oil India LimitedOISD – Oil Industry Safety DirectorateONGC – Oil and Natural Gas Corporation LimitedPCG – partial credit guaranteePLL – Petronet LNG LimitedPPER – project performance evaluation reportPPP – public-private partnershipPSD – private sector developmentPSOD – Private Sector Operations DepartmentRasgas – Ras Laffan Liquefied Natural Gas Company LimitedRIL – Reliance Industries LimitedRRP – report and recommendation of the PresidentSCV – standard combustion vaporizerSO2 – sulfur dioxideSPA – sales and purchase agreementSPM – suspended particulate matterSTV – shell and tube vaporizerTA – technical assistanceUSEPA – US Environmental Protection AgencyWACC – 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. KeywordsAsian Development Bank, Dahej Indian gas sector, liquefied natural gas, Petronet LNG public-private partnershipDirector General B. Murray, Operations Evaluation Department (OED)Director R. Adhikari, Operations Evaluation Division 2, OEDTeam leader B. Finlayson, Senior Evaluation Specialist, OEDTeam members J. Dimayuga, Evaluation Officer, OED R. Perez, Senior Operations Evaluation Assistant, OED Operations Evaluation Department, PE-693
  • 5. CONTENTS PageBASIC DATA iiEXECUTIVE SUMMARY iiiI. THE PROJECT 1 A. Project Background 1 B. Project Features 2 C. Progress Highlights 4II. 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 11III. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS 12 A. Project Issues 12 B. Lessons 13 C. Follow-Up Actions 14APPENDIXES1. Private Sector Development Indicators and Ratings 152. Developments in the Indian Gas Market 163. Review of Petronet LNG’s Operations 214. Reevaluation of the Economic Internal Rate of Return 265. Social, Environmental, Health, and Safety Performance 30
  • 6. The guidelines formally adopted by the Operations Evaluation Department on avoiding conflictof interest in its independent evaluations were observed in the preparation of this report. Thefieldwork 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 themanagement of the Operations Evaluation Department, there were no conflicts of interest of thepersons preparing, reviewing, or approving this report.This report contains information that may be subjected to disclosure restrictions agreed betweenADB and the relevant sponsor or recipient of funds from ADB. Recipients should therefore notdisclose its content to third parties, except in connection with the performance of their officialduties. A summary of this report shall be made publicly available in accordance with ADB’sPublic Communications Policy (PCP) and such summary shall not include any confidentialinformation and other information that falls within the exceptions set out in Paragraphs 126, 127and 130 of the PCP.As agreed by Operations Evaluation Department, Office of the General Counsel, Office of theSecretary, and the Department of External Relations, only the 35-paged redacted summary willbe 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 24ADB = 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 = technicalassistance, WACC = weighted average cost of capital.
  • 8. EXECUTIVE SUMMARY In December 2003, the Asian Development Bank’s (ADB) Board of Directors approved areport and recommendation of the President (RRP) for: (i) an equity investment in Petronet LNGLimited (PLL) for a 5.2% shareholding; and (ii) a partial credit guarantee (PCG), without aGovernment guarantee, to support a PLL bond issue of up to Rs7 billion, amounting in exposureterms to Rs3.525 billion. The funds, sourced from ADB’s ordinary capital resources (OCR), wereto be used to construct and operate a liquefied natural gas (LNG) import and regasificationterminal with a 5.0 million metric tons per annum capacity at Dahej in Gujarat state. This projectperformance evaluation report (PPER) assesses ADB’s support to help develop PLL’s LNGplant at Dahej (the Project). The Operations Evaluation Mission (OEM) visited India 24 April–5 May 2006 to reviewthe Project and obtain the necessary data to prepare the PPER. The OEM interviewed projectstakeholders, 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. Theevaluation criteria used for the Project were based on the best practice guidelines identified bythe Evaluation Coordination Group of the Multilateral Development Banks on Private SectorOperations, as well as the criteria presented in ADB’s draft Guidelines for the Preparation ofPerformance 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, theProject 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 primaryjustifications for the Project presented in the RRP were to (i) help meet growing energy demandin 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 tothe power, fertilizer, oil, and transport sectors; (iv) promote the use of clean energy; (v) providean 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 andcommercializing the LNG segment of the Indian gas industry, and encouraging the use of aclean, environmentally friendly fuel. Demand for energy in India continues to grow rapidly, andthe increased availability of clean energy at internationally competitive prices is important for thedevelopment of the country. The Project demonstrated that the successful importation of LNG atcompetitive prices is possible, thereby supporting the liberalization of the gas sector andenhancing the level of private sector participation in the energy sector. PLL has demonstratedthe high standards of performance that can be achieved by a modern, well-run public-privatepartnership managed on a commercial basis. PLL’s business success has been excellent due tolower-than-expected operating expenses and interest costs. Further, the Project hasdemonstrated that the use of LNG technology is feasible in India. As such, additional plants arebeing developed. Economic sustainability was rated excellent due to the substantial benefits derived frommeeting unmet demand, and the cost savings realized by firms that can use gas instead of
  • 9. ivnaptha. The environmental benefits associated with the use of gas, offsetting emissions fromcoal-fired generation, are difficult to quantify. However, they are likely to be substantial. Whilethe Project was assigned an environmental rating of category A at project appraisal, the actualdirect social and environmental impacts have been minimal. The main issues at the plant siterelate to safety of the mooring facilities during the monsoon period. A shareholder in PLL, GDFInternational, which has more than 30 years of LNG experience, is assisting in developing andrefining the mooring procedures. ADB’s investment returns have been excellent, as PLL’s share price has risensignificantly since investment. Offsetting this result, ADB did not issue the PCG that wasoriginally 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 managementfound that ADB’s financial appraisal was performed to a high standard, and investment approvalwas completed promptly. Most assumptions underpinning the Project have been realized largelyas envisaged in the RRP. The main weakness of the Project was the PCG, which was notcommercially 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 ADBstaff to PLL headquarters and the plant site, although most of these visits focused on arrangingfinancing for the phase II expansion. The documents on the subscription agreement andinsurance documents are in order. The main issue with the monitoring arrangements related toenvironmental and social safeguard policies, as regulatory reports were not supplied to ADBquarterly as stipulated in the equity subscription agreement. The OEM confirmed PLL’scompliance with regulations through its review of the regulatory reports submitted to theGovernment. ADB additionality for the Project appears material, and was rated satisfactory. Indiscussions, the management said ADB played a critical role in facilitating the liberalization ofthe gas market. Subsequently, ADB helped mitigate investor and lender concerns regarding anew and untested product and technology in India, where locally available skills and experiencewere limited. ADB was given a position on the board of directors, and contributed toimprovements in corporate governance by heading the PLL audit committee. The main variations from the original project concept were as follows: (i) the price of oiland natural gas increased dramatically, (ii) the construction by GAIL of the Dahej–Uran pipelinewas delayed, (iii) the breakwater was replaced with the construction of a third LNG tank, (iv) theGovernment did not divest its majority shareholding in one the main state-owned shareholdersof 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 ofhelping to catalyze industry reforms through technical assistance to improve the enablingenvironment, and through direct investment that helped reduce financiers’ concerns aboutproject risks. Although the Project has been operating for only 2½ years, the financialassumptions are radically different from the investment appraisal, especially regardinginternational prices for oil and gas, highlighting the importance of an adequate financialassessment. Despite a category A rating at project approval, environmental impacts and socialexternalities at the plant site have not been significant. However, some safety issues still arebeing resolved. Unstable mooring conditions have been more challenging than originallyanticipated, reinforcing the need for an adequate assessment of new technology during duediligence. Some of the original assumptions on privatization of PLL have not materialized, and
  • 10. vthe current ownership structure continues to represent a public-private partnership. A smallshareholding by ADB was required to help make the project viable. This model can bereplicated in future gas projects, which potentially can be financed without ADB support. Themost important lesson that emerges from the Project was the ephemeral demand for PCGs andbond 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 PROJECTA. Project Background1. In December 2003, the Asian Development Bank’s (ADB) Board of Directors approved areport and recommendation of the President (RRP) for: (i) an equity investment in Petronet LNGLimited (PLL) for a 5.2% shareholding; and (ii) a partial credit guarantee (PCG), without aGovernment guarantee, to support a PLL bond issue of up to Rs7 billion, amounting in exposureterms to Rs3.525 billion. The funds were to be used to construct and operate a liquefied naturalgas (LNG) import and regasification terminal (the Project) with a 5.0 million metric tons perannum (MMTPA) capacity at Dahej in Gujarat state. The Project would serve gas users alongthe 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, aswell 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 notexceeding 70:30 and achieve an economic internal rate of return (EIRR) of 23.0%. The Projectbegan operations in April 2004. ADB’s Private Sector Operations Department (PSOD) had notprepared 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 therest of the world, reflecting strong potential for continuing growth in the sector. Rising oil pricesand concerns about environmental impacts stimulated demand for natural gas, which wasenvisaged 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 wasexpected to lower industrial costs. The industrial sector is a heavy user of natural gas, whichcan be used as a substitute for naphtha. At appraisal, about 50% of fertilizer units in India usednatural gas as feedstock. While growth in this sector was not expected to be high, an increasingnumber of plants using naphtha and fuel oil were expected to switch to gas.4. Traditionally, the Government of India (the Government) has dominated production inthe gas sector. At appraisal, the majority state-owned companies Oil and Natural GasCorporation 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-ownedGAIL (India) Limited (GAIL) had a near monopoly on onshore transmission, including the HBJpipeline. The Ministry of Petroleum and Natural Gas (MOPNG) regulated GAIL in areas such assetting gas quality and access standards, and administering monopoly tariffs.5. To help relieve supply constraints, the Government started to liberalize the gas sector in1991 with the opening of oil exploration to small-scale private sector participation. Despite thereforms, domestic production did not keep pace with the increase in demand for natural gas. AsIndia 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 amaster plan for the natural gas industry in India. These studies also assisted with (i) anassessment of the potential for setting up public-private joint ventures to build and operate LNGterminals, (ii) formulation of a project implementation plan, and (iii) development of a structure toenable limited recourse financing. Although the TA studies have not been evaluated formally,
  • 12. 2the sponsors appeared to regard them highly, and they seemed to contribute to the liberalizationand development of the gas sector in India. In 1999, the Government introduced further reformsto allow private domestic exploration, incorporated the TA concept into its Hydrocarbon Vision2025, and removed many of the restrictions on LNG imports.6. As part of these developments, four state companies—Bharat Petroleum CorporationLimited (BPCL), Indian Oil Corporation Limited (IOC), GAIL, and ONGC (collectively referred toas 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 refiningcrude oil, and production and distribution of petroleum products. IOC, the largest company inIndia in terms of sales, is engaged in refining and distributing petroleum products. GAIL is thedominant gas transmission and marketing company, while ONGC produces the majority of thenatural gas in India. In 2002, the sponsors asked ADB for financial assistance to implement theProject in Dahej.B. Project Features7. The Project was designed to build, operate, and transfer the first LNG import andregasification terminal in India, with a phase I capacity of 5.0 MMTPA. The land at the projectsite is part of an industrial complex owned by Gujarat Maritime Board (GMB). At appraisal, PLLhad signed a letter of intent with GMB to enter into a 99-year concession agreement to lease the58.6 hectare site at Dahej, Gujarat, as well as a 30-year agreement to develop and use a portfacility. The concession was not tendered formally, as the market for leasing land at the projectsite was competitive and does not have any monopoly characteristics. The project facilitiescomprised (i) two full-containment LNG storage tanks, each with a gross capacity of 160,000cubic meters (m3); (ii) recovery system for re-condensation of the boil-off gas; (iii) send outfacilities, including “shell and tube” and “submerged combustion” vaporizers; (iv) auxiliaryfacilities, including a 23-megawatt (MW) gas-fired captive power plant; (v) electrical and utilitiesproduction control systems; (vi) metering, fire, and gas detection and protection systems; (vii) ajetty; and (viii) initially, a breakwater. A backup power agreement was signed with the GujaratState Electricity Board, and the plant is connected to the local high-tension network. Atappraisal, the Project had an environmental rating of category A, indicating substantial impactsprimarily 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 regasificationfacility, 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 thestandards that are monitored by their local regional offices.8. Following competitive bidding, PLL signed a sales and purchase agreement (SPA) withRas Laffan Liquefied Natural Gas Company Limited (Rasgas), obligating PLL to purchase up to7.5 MMTPA of LNG for 25 years. The agreement had two stages. In the first stage, PLL wouldtake 5.0 MMTPA on a take-or-pay basis up to 2009. After 2009, PLL could take the remaining2.5 MMTPA subject to the mutual agreement of both parties. The purchase price initially was setat $2.53 per million British thermal units (MMBTU), and it will be rebased regularly inaccordance 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 theworld. An international consortium led by Mitsui OSK Lines provided two dedicated specialpurpose tankers with capacity of 138,000 m3 each to transport LNG to PLL under a 25-yearcontract 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. 3LNG terminal. The offtake contract is take or pay, with terms that are back-to-back with PLL’sSPA.9. As envisaged at appraisal, the offtakers initially were to transport the gas from the PLLterminal to consumers through an expanded 528 km HBJ pipeline system, and eventuallythrough a new 485 km pipeline connecting Dahej to Uran. IOC and BPCL have executed gastransport agreements through GAIL, which is responsible for expanding the existing andproposed pipelines. The offtakers intended to use the gas for internal consumption, or to sell itunder long-term contracts to industrial users. One third of the output would be consumed byIOC and BPCL at their refineries; one third would be sold to large end-use consumers, such asHindustan Petroleum Corporation Limited, ONGC, and a fertilizer company; and the balancesold to smaller end-use consumers, such as power and fertilizer companies that are customersof 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 reflectsactual 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 offtakersadd transport charges and sales tax, $3.80 per MMBTU at the end-user point. This price wasconsiderably higher than the subsidized domestic gas price of $2.84 per MMBTU being chargedat the time of appraisal, though it was commercially attractive due to the substantial demandsupply gap in the market. PLL’s gas was expected to meet demand that was either not met atall, causing capacity underutilization; or replace alternate fuels, such as naptha, that were moreexpensive than PLL’s gas.11. The Project was to be constructed under a lump sum, fixed price, date certain turnkeyEPC agreement with an international consortium selected through international competitivebidding. PLL’s in-house staff was to operate and maintain the LNG terminal with technical inputfrom ONGC and a new strategic shareholder in PLL, Gaz de France International (GDFI). Acombination of equity and short-term bridging debt finance, was to fund project construction. Aspart of the Project, the shareholding structure of PLL would be expanded from the four originalstate-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 theshares. The inclusion of offtakers and the supplier in the shareholding structure was intended tohelp 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 ashareholder to meet its charter requirements for an anchor investment to support its guaranteeoperations, 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 localcurrency ADB-guaranteed bonds (up to approximately 30.0% of total debt) and Indiancommercial bank debt (up to approximately 70.0% of total debt). The bonds were to be issuedafter construction in April 2004. A charge on all of PLL’s assets, project documents, and cashflows were to support the bonds in the first instance. Subsequently, a PCG that covered part ofthe scheduled principal repayments and part of the scheduled interest payments on the bondswas to provide support. ADB was given a position on the board of directors.
  • 14. 4C. Progress Highlights13. PLL and a consortium led by Ishikawajima-Harima Heavy Industries Company Limitedsigned the EPC agreement in January 2001. Construction was completed on schedule, and theplant was mechanically complete in December 2003. At the same time, GAIL doubled thecapacity of the HBJ pipeline by laying a new 82 km pipeline from Dahej to Vemar, Gujarat; anda 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 thetender process, and completion is now targeted for 2007. The first shipment of gas arrived fromQatar in January 2004, initiating the commissioning period. Commercial supply commenced onschedule in April 2004.14. The actual project cost of the PLL plant was less in local currency terms than the initialcost estimate in the RRP. This cost saving resulted from a decision by PLL not to proceed withthe construction of the breakwater that had been included in the original design. Originally, a660-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, PLLconcluded that the breakwater was not required. The plant could accommodate any potentialdelays arising from the lack of a breakwater by increasing storage capacity, and an additionalLNG storage tank would provide greater operating flexibility. As a result, PLL decided toreallocate breakwater funds to construct a third tank, which will be part of the phase IIexpansion that will increase plant capacity to 10 MMTPA by 2009. Operating at 50% capacity in2004, and then increasing to 100% in 2005, the terminal’s technical performance has exceededexpectations at appraisal. LNG has been of high quality, supply and transportation risks havenot materialized, and the delivery of LNG to the regasification plant has not been delayed orinterrupted. Staff from ONGC and GDFI supported PLL staff for the initial period of operationsunder a series of technical support agreements. A possible extension is being negotiated withGDFI, primarily to address ship mooring safety issues.15. The projected financial structure has been changed slightly, with a 34.8% stakeallocated to the public through an initial public offering (IPO) in March 2004. The price pershares at IPO was Rs15, compared with the price at OEM appraisal of Rs60 per share. Themost important material departure from the financial structure presented in the RRP was thefailure to issue a PCG that could be used to support a bond issue. Due to adverse movementsin the Indian capital markets, bond financing was not seen as cost-effective. As a result, ADB’sPCG was not issued, and the Project relied on local currency long-term debt finance from Indianbanks. II. PROJECT EVALUATIONA. Overview16. The evaluation criteria used for the Project are based on the best practice guidelinesprepared by the Evaluation Coordination Group of the Multilateral Development Banks onPrivate Sector Operations, and the derived criteria incorporated in ADB’s draft Guidelines for thePreparation of Performance Evaluation Reports of Private Sector Operations.1 Reflecting thesedevelopments, 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’sadditionality. Overall, the Project was rated satisfactory.1 ADB’s Operations Evaluation Department is preparing the guidelines, which will be finalized in 2006.
  • 15. 5B. Development Outcome17. The initial criterion, development outcome, is rated excellent. It was evaluated using foursubcriteria: (i) private sector development, (ii) business success, (iii) economic sustainability,and (iv) social and environmental impacts. 1. Private Sector Development18. Private sector development impact is rated satisfactory (details are in Appendix 2–4). Inthe RRP, the primary justifications for the Project were to (i) help meet growing energy demandin 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 tothe oil, power, fertilizer, and transport sectors; (iv) promote the use of clean energy; (v) providean 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 ofthe PCG. Overall, the RRP objectives were relevant. With the exception of capital marketdevelopment, the Project helped achieve the envisaged goals. a. Beyond Company Impacts19. In 1996, ADB provided TA to develop a master plan for the development of the naturalgas sector in India. The main objectives of this study were to (i) rationalize the projecteddemand 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 gasinfrastructure 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 naturalgas. The Government accepted ADB’s recommendations on gas industry liberalization andcommercialization, establishing the foundation for investments in a public-private partnershipstructure. In 1997, ADB approved a TA to provide financial, legal, technical, and economicadvice and assistance to PLL to develop LNG importation and regasification facilities in Westernand Southern India. The second TA project focused on formulating a bankable project structurefor 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 thefirst investment that reflected tangible progress in liberalizing and commercializing the LNGsegment of the Indian gas industry, and in encouraging the use of a clean, environmentallyfriendly fuel. Overall, these activities provide an excellent example of how ADB can create anenabling environment through its public sector operations, and then catalyze private investmentthrough its private sector operations.20. Development of the gas sector was important for India due to shortages of energy, aswell as the positive environmental impacts of using natural gas as an energy source. The powersector 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 isgrowing following directives from the Supreme Court of India to increase the use of compressednatural gas (CNG) as a fuel for the transport sector. Indraprastha Gas Limited (IGL) in Delhi andMahanagar Gas Limited (MGL) in Mumbai are developing city gas distribution projects for thesupply of CNG and piped natural gas in these cities. IGL is catering to about 94,246 vehicles ofdifferent categories through 135 CNG stations. MGL has set up 105 CNG stations that serveabout 147,536 vehicles, mainly three-wheelers and cars.
  • 16. 621. Coal is the main source of energy in India, though domestic supplies are low quality andgenerate significant levels of harmful environmental emissions. While most of the coal is inEastern India, the majority of industrial demand is in Western India. This makes coal a high-costform of energy compared to alternative sources, such as LNG. The potential to increase theavailability of energy from other sources, such as nuclear and hydro power, is limited. Oil-basedproducts, such as naptha, have become expensive. Demand for natural gas in the fertilizer andpetrochemical sectors remains high. These circumstances are likely to continue for theforeseeable future due to the continued price differential between natural gas and feedstocksubstitutes, such as naptha.22. The two main constraints on natural gas supply are inadequate reserves and a lack oftransmission capacity. The Bombay High fields and Gujarat produce the bulk of India’s naturalgas. However, these fields are relatively old, output is declining, and production is expected tobe exhausted by 2020. To help offset this decline in production capacity, the Governmentopened the gas sector to private participation by awarding concession rights to public sectorjoint ventures (JV) with private sector operators. In 1999, the Government developed the NewExploration Policy (NELP), under which additional gas exploration concessions have beenawarded to private operators. As a result of these initiatives, a series of major new deep seagas fields have been discovered recently, especially by Reliance Industries Limited (RIL) in theKrishna Godavari (KG) Basin off the coast of Andhra Pradesh in eastern Indian. These areexpected to substitute for the diminishing supplies from the existing fields.23. The Government is developing additional transmission capacity. The Indian gastransmission infrastructure has consisted of small regional pipelines and the HBJ pipelineoperated by GAIL, which carries gas from the offshore Mumbai High basin to fertilizer andpower plants in North West India. However, the capacity of the HBJ pipeline is sufficient to meetonly about 45% of India’s gas consumption. GAIL has expanded the Dahej–Bijaypur section ofthe HBJ pipeline; and is building the Dahej–Uran gas pipeline, which is scheduled forcompletion in 2006. GAIL also is developing a $4.4 billion National Gas Grid, which is expectedto cover the entire country. The 8,000 km project will be implemented in phases over the next6–7 years. With the Government permitting private sector investment in gas transmissioninfrastructure, RIL intends to build a 1,400 km pipeline from Kakinada to Ahemdabad viaHyderabad and Uran in Maharashtra. The pipeline would transport the RIL’s reserves in the KGBasin 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 projectsare also are being implemented.24. Despite these developments in the local gas industry, demand continues to outstripsupply. To help bridge this gap, the Government has removed many of the restrictions onimporting gas, and some public and private sector companies are pursuing gas importationoptions. 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 next4–5 years due to technical or political constraints, and LNG remains the most important sourceof imported energy. India has only three LNG import terminals: (i) PLL’s Dahej plant with acapacity 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, whichis 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 8.8MMSCMD) and began operation in April 2005. Reportedly, the Hazira plant is operating at onlyabout 5% of capacity due to its reliance on a merchant business model that is unsuitable for gasuser requirements. The current gas deficit has prompted PLL to accelerate the phase II
  • 17. 7expansion of its Dahej plant, increasing its capacity to 10.0 MMTPA. PLL also has started thedevelopment of a 2.5 MMTPA LNG plant at Kochi, which was part of the TA conceptinvestigated in 1997. The plant should be operational by 2009. In addition, a new 2.5 MMTPAplant is expected to be developed at Ennore in Tamil Nadu. This plant, which is beingdeveloped independently of PLL, appears to have been catalyzed by the excess demand forgas 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 forapproximately 54% of the market at $1.80 per MMBTU, compared with PLL’s ex-terminal priceof $3.51 and a delivered price of $4.25 per MMBTU. Sourced from ONGC and OIL, thesubsidized gas is sold mainly to nominated consumers in protected sectors, such as power andfertilizer. 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 isexpected to continue to decline over time. The Government subsidies are only sustainable asthe state-owned resources are sold at prices substantially below market rates. Availablesupplies of subsidized gas are expected to fall as state-owned reserves are rapidly becomingdepleted. Approximately 20% of Indian gas consumption is sourced from JVs and privateconcessions 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 pricedat market rates.26. While gas importation and exploration are now substantially competitive markets, GAILcontinues to maintain a near monopoly on onshore transmission. The Petroleum and NaturalGas Regulatory Bill, enacted in April 2006, established an independent gas regulator. The newregulatory body, which will be separate from MOPNG, is expected to be established and staffedlater in 2006. The precise regulatory framework that will be introduced is not clear, although theindependent regulator will be responsible for downstream operations relating to transmissionand distribution. Regulations will be based on competitive principles that will help attract privateinvestment in transmission, and will ensure open access to existing monopoly facilities. Tariffswill be cost-based, which will ensure that private gas supplies are sustainable. Like the powersector, gas supply will be subject to the requirements of the Competition Commission. b. Direct Company Impacts27. PLL has demonstrated the high standards of performance that can be achieved by aPPP managed on a commercial basis. PLL has helped increase firm access to gas at affordableprices in Northern and Western Indian states, and now accounts for 20% of the country’s naturalgas. As natural gas provides 8%–9% of domestic energy consumption, the Project hasincreased the available energy in India by 1%. As the first company to establish and operate acommercial LNG plant in India, PLL has provided strong demonstration effects. Steps are beingtaken to replicate the original concept applied at Dahej at other LNG sites. As relatively fewskills were available in India to operate the plant, PLL has successfully trained local staffthrough the use of a management contract with GDFI, which has more than 30 yearsexperience managing LNG plants. Further, PLL has completed international standardsorganization (ISO) programs for quality, environment, health, and safety procedures, confirmingthat policies and procedures reflect world class norms.28. Management and reporting systems are of a high standard. Accounts are prepared inaccordance with standards for publicly listed companies that reflect international accounting andaudit requirements. ADB has its own independent board representative, who has contributed to
  • 18. 8the development of high corporate governance standards by chairing the audit committee. Theprivate sector participated directly in the ownership of PLL through a highly successful initialpublic offering (IPO) of 34.8% of the company’s shares. Offsetting these positive results, theobjective of stimulating bond market development was not achieved due to an adverse shift inthe cost of this form of finance, which obviated the need to issue a PCG and PLL bonds. 2. Business Success29. Business performance is rated excellent.2 The recalculated real financial FIRR beforephase II expansion was higher than the estimate at loan approval. The assumptions andanalysis underpinning the FIRR calculation are in Appendix 5. The recalculated FIRR exceedsPLL’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 advantagerelative 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, andBPCL 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 perMMBTU, 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 ofstate-owned gas is declining, and not enough gas is available to meet consumer needs. LNGimports from Dahej for the first 5 years have an external price of $3.51 and a delivered price toend users of $4.25 per MMBTU. Although this price is slightly more than the market price oflocal 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 Japancrude oil cocktail (JCC) price, with a cap and floor. The move to a floating rate will increaseofftake risks, though this risk is substantially moderated by the rolling average cost of gas thatwas secured contractually when gas prices were much lower than current market rates. Table 1: Key Financial Ratios of Petronet LNG LimitedItem 2004A 2005A 2006 2007 2008 2009Net Profit Margin (%) (0.01) 4.57 3.51 3.73 3.84 2.88Return on Average Assets (%) - 15.30 12.19 12.69 13.45 12.85Return on Average Equity (%) - 18.01 13.03 13.48 14.45 13.38Current Ratio 1.65 3.01 2.84 2.32 2.11 2.00Long-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 hasbeen strong. In its first year of operations, PLL recorded a net loss of Rs284 million in 2004 asthe plant ran at 50% capacity. In 2005, the plant utilized 100% of its capacity utilization andachieved a profit of Rs1,755 million, more than five times the appraisal estimate of Rs335million. This improvement in projected performance, which is attributed to lower-than-expectedoperating 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 LNGprice, indicate that the FIRR is reasonably robust. Long-term debt as a percentage of totalassets does not exceed 50%. PLL has raised additional debt for the development of the Kochi2 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. 9plant, and might raise additional finance through the international sale of a convertible bond onthe Singapore exchange. This underscores the financial success of the PLL venture. 3. Economic Sustainability32. Economic sustainability is measured by the EIRR generated by the Project, which aimsto capture the effects of competition, as well as externalities associated with social andenvironmental impacts. The recalculated EIRR is 32.6%, which is excellent.3 Appendix 6 showsthe assumptions underpinning the EIRR calculation. The recalculated EIRR is higher than theappraisal estimate of 23.0%. The end users for PLL gas are predominantly industrial usersalong the expanded HBJ pipeline, consisting of fertilizer (40%), power (20%), petrochemical andchemical (20%), and others (20%). These benefits are derived from the Project meeting unmetdemand (incremental), and generating substantial cost savings for firms that can switch fromnaptha to gas (non-incremental). Sensitivity analysis indicates that these results are robustunder a wide range of scenarios. 4. Social and Environmental Impacts33. While the Project was assigned an environmental rating of category A at appraisal, theactual negative social and environmental impacts have been minimal. The main issues relate tosafety of the mooring facilities during the monsoon period. Details on social and environmentalimpacts 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 bythe 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 operationsat the plant, and 50 staff are employed at the head office in Delhi. An additional 176 staff areemployed 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 forindustrial use, addressed the associated issues before the Project started. The main forms ofcompensation provided to the resettled parties were comparable land, and accommodation andcash grants financed by PLL to cover daily living expenses during the construction of newpremises.34. LNG is a cleaner source of energy than oil and coal. The environmental benefits of theproject arising from offsetting the use of coal are likely to be substantial due to the reduction inenergy-related emissions, such as carbon dioxide (CO2). Natural gas is about 32% cleaner thancoal. 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 dueto difficulties in precisely quantifying them. Additional economic benefits are being generated bythe project site, where the high quality of the technology and strong management team haveresulted in virtually zero emissions. However, some safety issues still are being resolved. TheLNG terminal has limited environmental impacts. PLL has complied with all necessaryenvironmental regulations. Independent third parties audit the annual and quarterly reports,which are submitted to MOEF, GPCB, and Forests and Environment Department of thegovernment of Gujarat. The terminal has received ISO certification for its processes andprocedures for quality (ISO 9001), environmental management (ISO 14001), and occupational3 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. 10health and safety management (ISO 18001). PLL’s Dahej plant was the first LNG facility in theworld to achieve accreditation within 1 year of operation.35. The Project’s major environmental risks are associated with safety. PLL has preparedvarious emergency response plans. The terminal has achieved 2.73 million accident-free hoursof operation to date. In October 2005, the National Safety Council conducted a safety audit andmade recommendations for improving systems and procedures. The main issues that havearisen involve the safety of the jetty and ship mooring operations due to strong currents, highwinds, and large waves during the monsoon season (May to September). As originallyenvisaged, 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 breakwaterwould not mitigate these effects. A program is being developed to remove rock debris that wasbeing used to construct the breakwater, and this will increase ship maneuverability. GDFI isproviding assistance to develop and refine safe mooring procedures. In the event of an accidentat the terminal, the effects probably would not extend beyond the boundaries of the plant site.C. ADB’s Investment Returns36. PLL is in a strong financial position, which is reflected in the substantial appreciation inADB’s equity shareholding in the company. Offsetting this result, ADB did not issue the PCG asenvisaged at appraisal because it was not commercially attractive. While no direct costs arosefrom the PCG, an opportunity cost was associated with the facility.D. ADB’s Effectiveness37. 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 Project38. Screening, appraisal, and structuring are rated satisfactory. Screening refers torelevance of the Project in achieving ADB’s strategic objectives, as defined in its country andsector strategy documents; and in complying with policies on private sector development, andsocial and environmental protection. The Project met these requirements to a high degree. Byestablishing a commercially viable and environmentally friendly LNG plant, the Projectsupported the country strategic program (CSP) objectives of removing impediments to theliberalization and growth of privately financed energy infrastructure in India. In the view of PLLmanagement, ADB’s appraisal was of a high standard, and the investment approval processwas performed rapidly. The assumptions underpinning the Project have materialized largely asenvisaged in the RRP. The primary weakness in the Project related to ADB’s performance wasthe PCG, which proved not to be commercially viable. This was due mainly to unforeseenadverse movements in the market. 2. Monitoring and Supervision Quality39. Monitoring and supervision quality was satisfactory. Monitoring appears to have been ofa high standard. PSOD staff visited PLL headquarters and the plant site regularly, althoughmost of these visits focused on arranging financing for the phase II expansion. The documentson the subscription agreement and insurance documents are in order. The main issue with themonitoring arrangements involved environmental and social safeguard policies, whereregulatory reports were not supplied to ADB quarterly as stipulated in the equity subscription
  • 21. 11agreement. Following a review of the regulatory reports submitted to the Government, theOperations Evaluation Mission (OEM) confirmed PLL compliance with regulations.E. ADB’s Additionality40. Additionality is defined as the extent to which something happens as a result of anintervention that would not otherwise have occurred in the absence of the intervention. TheProject has been successful from the perspective of stimulating development, liberalizing theenergy market, encouraging private sector investment, and creating a strong company that hashad significant demonstration impacts. In discussions with the OEM, PLL management saidADB played a critical role in liberalizing the market before the investment. While the constructionprogram was largely complete by the time PSOD participated, ADB helped mitigate investor andlender concerns regarding a new and untested product and technology in India, where locallyavailable skills and experience were limited. ADB also helped facilitate corporate governancethrough the introduction of an independent private director to the board. ADB’s direct boardrepresentative, 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 PCGequivalent to $65 million. As a result, ADB did not stimulate the development of the local bondmarket. This bond transaction never materialized due to adverse market movements that werebeyond the control of the participants. In 2001, the International Finance Corporation hadsuccessfully issued PCGs to support the mobilization of local currency financing for severallarge Indian companies, such as Bharti Mobile Limited. Thus, the product appeared attractiveand feasible. However, subsequent movements in interest rates meant that firms could accessfunds 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 sourceof local currency.F. Overall Rating42. The Project received an overall rating of satisfactory. The evaluation criteria weredevelopment outcome, ADB’s investment profitability, ADB’s operational effectiveness, andproject 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 PartlyItem Unsatisfactory Satisfactory Excellent SatisfactoryDevelopment Outcome XPrivate Sector Development XBusiness Success XEconomic Sustainability XContribution to LivingStandards XEnvironmental Performance XADB’s InvestmentProfitability XADB’s Effectiveness XScreening, Appraisal, andStructuring XMonitoring and Supervision XADB’s Additionality XADB = Asian Development Bank.Source: ADB Operations Evaluation Mission.43. Development outcome is rated satisfactory based on an assessment of the following fivesubcriteria: (i) private sector development was rated satisfactory, as the objectives of catalyzingprivate investment in a competitive natural gas industry are being achieved to a significantextent, and PLL has demonstrated strong corporate performance, though capital marketdevelopment goals were not attained; (ii) business success is rated excellent, as therecalculated FIRR exceeds the WACC; (iii) economic sustainability is rated excellent, as theEIRR of 32.6% was higher than expected due substantial cost savings and incremental demandarising 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 materialresettlement 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 improvedavailability of gas offsetting the use of coal. In addition, the plant site has generated virtuallyzero 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, investmentprofitability, 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’sadditionality is satisfactory. While not participating until construction was almost complete,ADB’s presence helped crystallize industry reforms, strengthen corporate governance, andsupport partial privatization of PLL. III. ISSUES, LESSONS, AND FOLLOW-UP ACTIONSA. Project Issues44. Due to ADB’s involvement in the Project only a few months before operationscommenced, 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 differenceswere 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. Lessons45. Based on the developments outlined in Section II, ADB could improve its performanceby considering the following factors when designing projects:46. Private Sector Development. ADB played a central role in the liberalization and reformof the Indian gas sector, and then catalyzed a series of important PPP investments in LNGfacilities. As such, the Project provides an excellent example of how ADB’s Private SectorDevelopment Strategy can work in practice. Some of the most important private sectordevelopment benefits involved discoveries of domestic gas by Indian private sector companies,independent of PSOD participation. An important issue that emerges from the analysis ofprivate sector impacts is the long gestation period required for enabling environment reforms toflow through to tangible PSOD investments and loans. In many respects, these delays werenecessary to provide the Government time to implement reforms before ADB and privateinvestors could commit funds. A precondition for the investment was the certainty that theplanned changes would occur within the industry. The sponsors did not perceive access toADB’s funding per se as the most important benefit of ADB participation. Rather, the sponsorswere more interested in the leveraging effect of ADB involvement, even through a small equityparticipation.47. Revenue and Cost Projections. The price forecasts for PLL gas in the RRP werebased on an assumed price of $29 per barrel, well below the price of approximately $75 perbarrel at the time of the OEM. Similarly, significant cost savings on capital expenditure wererealized, even though ADB participation occurred only months before project completion. Theseadjustments highlight the random volatility inherent in commodity products, as well as the needfor aggressive sensitivity analyses—especially for downside scenarios—to ensure that creditrisks are managed adequately.48. Social and Environmental Impacts. The Government was well organized when dealingwith social impacts, keeping risks associated with resettlement with the public sector agency,Gujarat Industrial Development Corporation. Similarly, GAIL retained the risks associated withthe development of the gas transmission network, effectively eliminating any negative social andenvironmental impacts from construction and commercial performance. PLL’s operations havehad positive impacts through employment, with an increasing number of local staff beingemployed over time. Environmental operational impacts have been negligible due to the natureof LNG, and the associated technology that resulted in almost zero emissions. The safety of themooring operations is the primary outstanding issue associated with externalities. Safety riskhas very localized physical impacts. The more serious risks involve PLL compliance withcommercial take-or-pay obligations, which probably would fall under force majeure provisions.
  • 24. 1449. Ownership Structure. As envisaged in the RRP, a chain-type ownership structurewould be adopted, allowing the Government, buyers, and a supplier to have an ownershipinterest in the facility that would help minimize commercial risks. In many cases, equityownership can complicate buyer and supplier incentives unnecessarily. Ideally, reliance shouldbe placed on input and output contracts wherever possible to minimize risks of conflicts ofinterest. Another important feature associated with PLL’s ownership structure was anassumption 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 notoccurred, it does not appear to have created a problem. However, international evidencesuggests 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 securedbasis due to the financial strength of the buyers and the high level of Government involvementin the Project. As the lead arranger and financier of PLL, the Government-owned State Bank ofIndia 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 relativelysophisticated banking sector, India still lacks access to sufficient long-term funds to financenecessary 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 PCGwere one of ADB’s primary motivations for participating in the Project. However, the PCG wasnot used due to adverse movements in the market. At loan appraisal, international financialinstitutions, such as the International Finance Corporation, had used guarantees successfully tosupport local currency bond issues. Subsequently, however, corporate bond market activity waslimited, and the market for raising local currency through the use of swaps became much moreactive. ADB has the capacity to participate in this market on favorable terms due to its AAAcredit rating.C. Follow-Up Actions52. No follow-up actions are required, although ADB is recommended to exit its equityparticipation as soon as practicable. The main development objectives of the equityparticipation—i.e., allaying financiers concerns and strengthening governance provisions—havebeen largely achieved. ADB can exit safely through the share market. No outstanding social andenvironmental actions are required by ADB. Given the potential for substantial shifts in themarket between ADB’s approval and financial drawdown, a degree of flexibility needs to beincorporated 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 CombinedChange Attributable to the PSO to Datea Impact Riskb Rate JustificationA. Beyond Company Impacts1. Improved laws, frameworks, and sector 4.0 4.0 4.0 4.0 ADB has played an importantinstitutions role developing the enabling environment for natural gas2. Pioneering or increased private sector 4.0 4.0 4.0 4.0 Private investment is occurringrole in the country’s natural gas sector in LNGand more widely3. Pioneering or enhanced competition (to 4.0 4.0 4.0 4.0 Private competition is beingstate natural gas monopolies, early introduced into the LNG sectorconcession operators, or others)4. Relative to investments, significant 3.0 3.0 4.0 3.0 Project is helping to stimulateeconomic links to previously underserved private investment in Northregions and business sectors (including West IndiaSMEs); and more productive employmentfor reached social groups for povertyreduction, including women5. Pioneering or catalytic finance to 2.5 3.0 4.0 3.0 ADB could not use its partialenhance market funding prospects for credit guarantee to support amore investments in the natural gas bond issue, although asector subsequent follow-on ADB financing facility has been approvedB. Direct Project Company Impacts1. Know-how: internalized management 3.5 3.0 4.0 3.5 Leading-edge LNG technologyand operational skills introduced2. Achieved standards of the company:(i) against global industry performance 3.5 3.0 4.0 3.5 Standards compare withand 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 governancesecurity3. 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 RatingLNG = 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 MARKETA. Overview of the Natural Gas Sector in India1. Liquefied Natural Gas (LNG) is one of the fastest growing fuels in the world, withaverage annual usage rising about 8% over the past 5 years. Natural Gas is a clean andenvironment-friendly fuel that can comply with stringent emission standards in power generationand industrial processes. It is also used as compressed natural gas (CNG) in the transportsector, helping reduce vehicle emissions. In India, substantial reserves of natural gas have beendiscovered onshore and offshore. While the availability of gas is expected to improve, thedemand for energy is expected to grow more quickly. At –160O C, natural gas becomes liquidand 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 aclean source of energy, but also as a cost-effective fuel. Several industries in the country areusing more expensive liquid fuels (naphtha and fuel oil, low-sulfur heavy stock) as sources ofenergy and carbon feedstocks. The indigenous availability of natural gas is unable to meet thedemand of natural gas, and the reserves are declining steadily. As such, the importation of LNGis increasingly important. India is strategically located close to the large gas reserves in theMiddle East and the Asia-Pacific countries. These countries hold 70% of the world’s LNGliquefaction and export facilities. Globally, gas accounts for nearly 23% of commercial energyconsumption. Natural gas accounts for only 9% of the Indian energy basket due to domesticsupply constraints. The Government of India (the Government) is seeking to identify options toincrease natural gas consumption within India.B. Demand and Supply of Natural Gas3. Lack of access constrains the demand for natural gas. If additional supplies of LNG weremade available within the country, through discoveries of further reserves and expansion of ofpipeline distribution capacity, the use of gas could be much higher. Table A2.1 shows varioussupply 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 2 174. In 2005, the Ministry of Petroleum and Natural Gas (MOPNG) estimated in its annualreport that the energy sector accounted for 69% of natural gas consumed in India, while the restwas used primarily as feedstock in the fertilizer and petrochemical industries. The energy andfertilizer sectors are allocated state-owned gas at subsidized prices, although they are free topurchase gas from private sources at market rates if they wish. The most rapid sources ofgrowth between 2004 and 2005 are the domestic fuel sector (269%), followed by industrial fuel(16%) and petrochemicals (10%). Domestic fuel consumption is growing following directivesfrom 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 aredeveloping 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. MGLhas 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 ofdistribution 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 ofIndia’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 associatedwith oil. The south basin and Tapti fields in the western offshore area, the gas fields in thewestern 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 gassupply, 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 0.85trillion standard cubic meters (SCM). The Government has been actively encouraging privatesector 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 NELPprogram has been successful. A recent gas discovery of more than 0.283 trillion SCM in the KGBasin by the private company Reliance Industries Limited (RIL) increased India’s reservessignificantly, and more is expected to be found. Gujarat State Petroleum Corporation made anestimated 0.566 trillion SCM discovery in the KG Basin that is potentially the largest gas find inIndia. Other companies, such as Oil and Natural Gas Corporation of India (ONGC), also havefound gas in KG Basin. RIL has discovered additional gas reserves in three Bay of Bengal wellsoff the coast of Orissa, where potential reserves could total 0.142 trillion SCM. In addition tonatural gas reserves, the Government has developed a policy to extract methane trapped incoal seams that can be used as an energy source. Coal-based methane resources areestimated at about 820 billion cubic meters (BCM), with expected production of about 23 millionstandard cubic meters per day.17. 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. Theprivate sector’s share in natural gas production has increased from 2% in 1997 to 21.34% in2005, 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 limitedtransmission 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 HighBasin to fertilizer and power plants in North West India. The capacity of the HBJ pipeline isabout 1.18 billion cubic feet per day (bcfd), which is sufficient for about 45% of India’s gasconsumption. The HBJ pipeline, operated by GAIL India Limited (GAIL), carries Petronet LNGLimited’s (PLL) LNG imports through the state of Gujarat. GAIL is expanding the Dahej–Bijapursection of the HBJ pipeline; and building the Dahej–Uran gas pipeline, which is scheduled forcompletion in 2006. GAIL also is developing the $4.4 billion National Gas Grid, which isexpected to cover the entire country. The 8,000 km project will be implemented in phases overthe next 6–7 years. GAIL intends to build and operate an east-to-west truckline linking Kakinadaport in the Bay of Bengal to Hazira in the Arabian Sea. With the Government permitting privatesector investment in gas transmission infrastructure, RIL intends to build a 1,400 km pipelinefrom Kakinada to Ahemdabad via Hyderabad and Uran in Maharashtra. The pipeline wouldtransport RIL’s reserves in the KG Basin to the Gujarat power plants belonging to NationalThermal Power Corporation. In addition, RIL plans to build a pipeline from Hyderabad on theeast cost to Delhi. Several smaller projects also are being implemented, including (i) a 600 kmpipeline from Visakhapatnam to Secundrabad in Andhra Pradesh; (ii) a 700 km pipeline fromManagalore in Karnataka to Madurai in Tamil Nadu; and (iii) a 575 km pipeline that will connectPLL’s Kochi LNG terminal to Kerala.9. Despite the increasing private investment, recent discoveries of domestic natural gasreserves, 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 importationoptions. In 2004, PLL commissioned the first LNG terminal in India at Dahej, Gujarat. The PLLterminal has a capacity of 5.0 million metric tons per annum (MMTPA). In April 2005, a secondLNG terminal with a capacity of 2.5 MMTPA was commissioned at Hazira, Gujarat by RoyalDutch Shell Group and Total Gaz Electricite Holdings of France, which are the joint owners andoperators of the terminal. The Hazira plant sources gas from the spot market instead of usingthe 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 IndiaProject 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 2008Dabhol terminal Dabhol (Maharashtra) 5.0 Oman, Complete; commissioning(GE/Bechtel/MSEB) Abu Dhabi delayed by contractual disputeHazira LNG (Shell) Hazira (Gujarat) 2.5 (phase I), Shell Commissioned in April 5.0 (phase II) Portfolio 2005Kochi LNG (Petronet) Kochi (Kerala) 2.5 In discussion Project expected to be completed by 2008Ennore 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 fromneighboring countries. Several pipelines have been proposed to serve the Indian market,originating from Iran, Myanmar, Bangladesh, and Turkmenistan. The most likely internationalpipeline is the 2,600 km overland pipeline connecting the South Pars field in Iran with the HBJpipeline in India via Pakistan. In June 2005, the Government signed a $20 billion contract withIran to import 5.0 MMTPA of LNG for 25 years, beginning in 2009. National Iranian Oil Companywould supply this gas from its South Pars gas field. The destination ports for the gas in India arethe Dahej and Kochi terminals. The negotiated price for the deal is $3.21 per million Britishthermal units (MMBTU). This price includes a fixed component of $1.20 per MMBTU and avariable component linked to the Brent price, which has been capped at $31 dollars per BBL.2The current status of this deal is unclear, as Iran has asked for an increase in the price ofnatural gas and has sought to limit supply to lean gas that excludes various carbon componentsunrelated to energy content.C. Pricing and Regulation11. In the gas sector, prices are both administratively and market based. ONGC and OIL sellgas from the pre-NELP blocks to GAIL under the administered pricing mechanism (APM). In1997, the Government sought to achieve parity between fuel oil prices and gas, though thispolicy has been ineffective. As a result, gas sold under the APM continues to be allocated atprices substantially below market rates for gas and transmission costs. The APM price of gasfor the North Eastern region is approximately 60% of the new price. The matter of fixing theproducer price of natural gas has been referred to the Tariff Commission, a body under theMinistry of Commerce and Industry that is serving as a de-facto regulator. For gas producedunder the NELP blocks, output can be sold at market-determined prices defined in thenegotiated production sharing contracts and gas sales agreements.2 Times of India. 2005. India, Iran sign $20-billion LNG deal. 14 June.
  • 30. 20 Appendix 212. Similarly, imported regasified LNG sourced from the PLL and Shell plants is sold atmarket-determined prices. PLL has signed an agreement with Ras Laffan Liquefied Natural GasCompany Limited (RasGas) of Qatar for the supply of 5.0 MMTPA of LNG for 25 years at a freeon 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 avariable price for a 60-month transition period. The participating parties have agreed to anincrease 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 perMMBTU if the price of oil stays at more than $50 per BBL. At this stage, PLL’s delivered gasprice is very competitive relative to the Hazira terminal gas. Royal Dutch Shell, which has beenpromoting its Hazira terminal as a merchant terminal, sourced its first LNG consignment fromAustralia’s North West Shelf project at a price of $3.70 per MMBTU, which is significantly higherthan PLL’s purchase FOB price. RIL’s gas discovery in the KG Basin will affect the futurecompetitiveness of LNG imports. RIL recently agreed to supply National Thermal PowerCorporation a delivered consumer price of $2.97 per MMBTU in Gujarat, although thistransaction 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 ofnatural gas and LNG in the power sector depends on its competitiveness with respect to coaland liquid hydrocarbons, such as naphtha, low-sulfur heavy stock, and fuel oil (which are usedsparingly). The eastern states of Bihar, Madhya Pradesh, and Orissa hold 70% of the country’scoal reserves. The pithead coal price in the east averages about $12 per ton, and the freightcost 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 withcoal. LNG is likely to be most competitive in these regions, especially if a power plant is close tothe regasification terminal and transmission costs are avoided. For the fertilizer sector, theGovernment provides huge ($2.6 billion) annual subsidies. Many fertilizer plants use expensivefuel oil and naphtha, because they have little incentive to switch fuels under the Government’ssubsidy program. Recently, however, the Government has been promoting the use of naturalgas 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 ureaproduction versus urea imports needs to be priced at about $3.00 per MMBTU to staycompetitive.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 April2006, 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-termplan for the gas pipeline network. The policy proposes that the regulator should adopt anondiscriminatory approach when deciding on access arrangements for the gas pipeline, andshould consider the common carrier principle to ensure equal opportunities for all users.
  • 31. Appendix 3 21 REVIEW OF PETRONET LNG’S OPERATIONSA. Background1. 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 tobridge the large gap between the demand and supply of natural gas in the country. PLL is thefirst company in India and South Asia to import LNG and successfully set up a LNGregasification terminal. The 5.0 million metric tons per annum (MMTPA) LNG receiving andregasification terminal at Dahej, Gujarat state (the Project) has been constructed andcommissioned in record time at a benchmark cost. During the buildup period in 2004, the DahejLNG terminal operated at 50% capacity, but from 2005 onward the plant has been capable ofoperating at 100% capacity. Regasified LNG from Dahej terminal is supplying consumers inGujarat and along the recently upgraded Hazira–Bijaipur–Jagdishpur (HBJ) pipeline, traversingthe 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 LNGterminal to Uran in Mumbai.2. The increased availability of gas has generated important benefits for the Indianeconomy. The Project has spurred market liberalization and commercialization of the LNGindustry. 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, whichuses expensive naptha ($15–$18 per million British thermal units [MMBTU]) for generation. Thefertilizer sector has benefited from the Project, as expensive and low-energy naptha has beenreplaced with natural gas in many cases to produce urea. Several industries have shifted tocaptive power generation systems based on natural gas, which is more efficient. Thesedevelopments have freed up power for other sectors. In addition to economic benefits arisingfrom increasing energy efficiency, natural gas utilization has generated environmental benefitsby producing less carbon dioxide (CO2) emissions than other sources of energy and carbonfeedstocks. Additional benefits could be realized in the future as companies, such as GAIL andOil and Natural Gas Corporation Limited (ONGC), are able to extract high carbon componentsfrom the rich PLL gas, without lowering the energy content. This would provide low-cost inputsfor sectors such as petrochemical manufacturing. The PLL plant has provided the Indian gassector with much-needed technical expertise in the design, operation, and maintenance of LNGterminals.B. Description of Major Project Components3. The PLL facility is based on a concession agreement signed with Gujarat MaritimeBoard, which provided a 99-year lease for a 58.6 hectare site, and a 30-year agreement todevelop and use a port facility. The government of Gujarat had not approved the draft at thetime of the Operations Evaluation Mission. PLL also signed a 25-year LNG supply contract withRas Laffan Liquefied Gas Company (Rasgas), based in Qatar, in July 1999. The contractinitiated construction of various facilities for suppliers and buyers of the LNG. Rasgas hasdeveloped offshore gas production facilities in the North field of Qatar, as well as a dedicatedliquefaction train with 5.0 MMTPA capacity. It was commissioned to meet the requirements ofthe Dahej terminal, and became fully operational in March 2004. The North field of Qatar is thelargest gas field in the world, which helps ensure the security of LNG supplies throughout thecontract.
  • 32. 22 Appendix 34. PLL has signed two shipping time charter agreements with a consortium led by MitsuiOSK Lines for transportation of LNG from Qatar to Dahej for 25 years. Mitsui has constructedtwo special purpose vessels to transport LNG from Qatar to the Dahej LNG terminal in Gujaratfor 25 years. Mitsui contracted Daewoo Ship Building and Marine Engineering Company,Republic of Korea, to construct the LNG tankers, which were completed on time and at agreedcost. PLL appointed a consortium consisting of PSA Marine Private Limited, Singapore, andOcean Sparkle Limited, India, to operate the port at Dahej. The port operator, which is providingtugs, marine crafts, and crew at the Dahej port, is responsible for safe berthing of LNG tankersat the jetty and other related marine services. The port operator has formed a special purposecompany, named Sealion Sparkle Port and Terminal Services (Dahej) Limited, to provide theservices to PLL. Finally, the port operator has mobilized the required manpower, tugs, andboats at the site, and berthing operations are in process.5. The construction of the LNG terminal at Dahej was executed through a lump sumturnkey engineering, procurement, and construction (EPC) contract issued by a consortium ofcompanies led by Ishikawajima Harima-Heavy Industries Corporation Limited (IHI), Japan. Theother members of the consortium are Ballast Nedam International BV-Netherlands, ToyoEngineering India Limited, Toyo Engineering Corporation, Itochu Corporation, and MitsuiCompany Limited. IHI is one of the most reputable construction companies in the world in thefield of LNG regasification terminals. PLL commissioned India’s first LNG receiving andregasification terminal at Dahej in February 2004. Following the arrival of the first LNG tanker atDahej and the mechanical completion of the terminal facilities, the EPC contractor completedthe commissioning in April 2004, allowing the commencement of commercial operations. FosterWheeler Energy Limited was the project management consultant responsible for the regularreview, monitoring, and execution of the Project according to the EPC contract.6. The LNG port facilities include an approximately 2.5-kilometer (km) jetty and theequipment necessary to unload LNG from special purpose ships. The Dahej facilities alsoinclude two full containment LNG storage tanks, each with gross capacity of 160,000 cubicmeters, and a gas recovery system for re-condensation of boil-off gas. Send out facilitiesinclude seven air-heated shell and two tube vaporizers (STV) and submerged combustionvaporizers (SCV). The STVs and air heaters with 112 fans have the capacity to evaporate 88.2tons per hour of LNG. The STVs are heated indirectly through a glycol-water system, whichcirculates in a closed loop and uses the ambient air as a heat source. Most LNG plants useseawater for evaporation of the LNG. The traditional water gasification system was not adoptedin Dahej, because the plant is located in an estuary where the seawater is muddy. PLL wouldhave to go approximately 50 km offshore to obtain clean seawater for regasification, whichwould not be cost-effective. Each SCVs can process 100 tons per hour of LNG using hot watersourced from the waste heat of the gas turbine flue gases. Two of the three gas turbines arealways in operation, while one is on standby. Auxiliary facilities include three 7.5-megawatt (MW)gas turbines in a captive power plant facility, and a high-tension backup power supplyarrangement from the Gujarat Electricity Board. The only major technical deviation from thedesign reviewed at appraisal was the substitution of a full containment LNG storage tank for theconstruction of the proposed breakwater. The EPC contractor is building the new tank as part ofthe phase II expansion program.C. Plant Operations and Safety Aspects7. The two special purpose LNG tankers deliver the LNG at the jetty that has been builtspecially for unloading these tankers. The jetty has three unloading arms and a return regasifiedgas line. The facility has one of the longest LNG jetties in the world, with about 2.5 km of
  • 33. Appendix 3 23pipelines for the transportation of the LNG from the jetty to the storage tanks. The two LNGtankers have a capacity of 138,000 cubic meters each, and they utilize a membrane technologyto keep the gas cool in a liquid state. The water depth at the ship mooring is 16 metersmaximum, and the tidal variation is 10.4 meters.8. Qualified graduate engineers trained by Gaz de France (GDF), which is a stakeholder inPLL, manage and maintain plant operations. GDF, which is responsible for carrying out safetyaudits regularly, has signed off on PLL operations as efficient with boil-off gas half that of thedesigned values. The plant is operated in accordance with international practices and normsspecified for LNG terminals. Safety is the primary issue associated with the plant. In response,GDF has recommended that unloading during the monsoon period be carried out underpredefined parameters. These are related to local weather conditions, which should cover thewind speeds, wave height, and water currents that have caused difficulties during mooringoperations. PLL has been advised to appoint a local weather consultant for this activity, andsimulation exercises with the assistance of an international consultant have been recommendedto define the safe limits for unloading during the monsoon period.D. Risk Mitigation9. During the Project, the events that constitute critical safety risks at the LNG terminal are(i) a collision of LNG tankers with other ships, or LNG tankers running aground; (ii) an LNG leakduring unloading; (iii) an LNG leak from safety valves at the top of the storage tanks; and (iv)major earthquakes. The likelihood of these events has been minimized through strict applicationof rigorous standards in the design and operations of the terminal, and throughinstitutionalization of a standard emergency response plan and a disaster management plan.Safety aspects are incorporated in the design of the project facilities using well-establishedstandards. The national design codes are the Oil Industry Safety Directorate OISD–194. Thedesign standards internationally adopted are the European standard, EN–1473, the US NationalFire Protection Association standard, NFPA–59A, and British Standard BS7777. The design ofthe existing facilities adopted these standards. They also will be applied to the new facilities withsome non-safety-related modifications to suit the site specificities, such as the choice of indirectLNG regasification using glycol water-air heating system instead of the conventional open rackvaporizers. The air heating system has proved to be environmental friendly, producing asignificant volume of clean water from condensation of humidity in the air.10. The two existing LNG storage tanks are full-containment tanks that are safer than themore conventional single- or double-containment tanks. In addition to safety considerations, full-containment tanks have the following advantages over single- and double-containment tanks: (i)higher operating pressure, thus reducing boil-off gas during unloading operation; (ii) loads ofpiping structure and accessories not transferred to the primary container; (iii) no risk of leaksfrom tank; and (iv) secondary container can withstand external impacts without collapse, andcan hold LNG if it leaks from the primary container. For these reasons, the two new storagetanks under the phase II expansion also will be full-containment tanks. Several other safetymeasures adopted in the design of the existing LNG terminal will be incorporated in the phase IIfacilities. Some examples of the existing plant safety measures include (i) locating the isolationvalve of the pig launcher station closer to the plant boundary to provide additional protectionagainst backflow from the transmission network that could feed fires and damage the tank; (ii)providing a pressure sensor on the glycol side of the STVs to trigger LNG shutdown in the eventof a leak; (iii) installing a rupture disk on glycol side (shell) for overpressure protection; and (iv)providing blast-proof construction in accordance with local regulations. The control room,administration building, and other inhabited buildings are constructed with minimal or no
  • 34. 24 Appendix 3windows towards the production process, and their overall window area has been minimized.Firewater tank and pumps are located as far away from the process areas as possible. As theproject site is in a region classified as earthquake class 3, the terminal facilities were designedbased on the assumption of an earthquake-induced lateral movement once in 1,000 years.11. The terminal has been designed to accommodate accidents due to fire and LNG vaporleakage, in accordance with the United States Environmental Protection Agency standard EN1473. The thermal exclusion zone and the vapor dispersion zone were calculated for thefollowing possible scenarios: (i) rupture of one of the unloading arms during discharge of LNG from the tankers, and (ii) release of LNG from the three relief valves on top of one of the tanks.12. The thermal exclusion zone and the vapor dispersion zone were calculated using themodels recommended in EN 1473 for the storage tank leak, and the models recommended bythe USEPA for the unloading arm leak. The findings of the consequence analysis aresummarized in Table A3. The exclusion zones in the case of the storage tanks are within theboundaries of the terminal complex. In the case of the unloading arms, the exclusion zones arewithin the distance between the jetty and the complex. Table A3: Summary of the Consequence Analysis Exclusion Zone Rupture of Unloading Arms Storage Tank Leak (meters) (meters) Thermal 700 77 Vapor dispersion 250 57 Source: Petronet LNG Limited estimates.13. PLL has prepared and institutionalized an emergency response plan (ERP) and adisaster management plan (DMP). The ERP prescribes actions and procedures to be takenwhen dealing with major releases, unignited releases, and fire and explosion emergencies. TheERP is supported by (i) gas detection, (ii) safety shutdown and fire protection systems, (iii)safety and security zones, (iv) ship and facility emergency response plan, (v) coordination withthe Gujarat Maritime Board and the coast guard, and (vi) evacuation plans and procedures. TheERP will be revised to cover the expanded operations. The DMP prepared by PLL is effective inpreventing and managing any incidents or accidents in and around the terminal complex, jetty,and waterfront. PLL has established and maintained suitable systems; employed or contractedskilled and trained personnel; and installed efficient communication equipment, as well as otherequipment and facilities, required for prompt application at any stage of DMP procedures. PLLorganizes periodic exercises and simulations with the port operator and LNG tanker crew basedon various simulated accident scenarios. PLL will revise the DMP as appropriate to cover theexpanded operations, in line with the Ministry of Environment and Forestry’s conditions forenvironmental clearance.14. For jetty operations, PLL has engaged an experienced port operator to provide servicesthat include hazard prevention, as well as health, safety, and environment services related tojetty operations. With the assistance of the port operator, the Health, Safety and EnvironmentalUnit is involved in prevention activities on the waterfront. PLL personnel have been trainedextensively in firefighting at LNG terminals operating in France and Qatar. The port operatoralso has deployed trained personnel to manage the waterfront activities. The wastemanagement plan complies with International Convention for the Prevention of Pollution of
  • 35. Appendix 3 25Ships. A mutual aid system is in place with other companies operating in the Dahej industrialestate. In the event of a major incident, the management team can call upon other companies inthe area to assist within their resources and make them available as required.15. To enhance safety further during unloading operations, wind speeds and wave heights inthe vicinity of the jetty are monitored continuously, and the data are transmitted to a centralunloading control room at the jetty. Emergency responses are prescribed for various wind andwave conditions, as well as LNG leaks; and procedures are established and ready forimplementation. The jetty terminal is fully equipped with firefighting equipment. The watersaround the jetty also are patrolled regularly to ensure security. These safety operations areoutsourced to a qualified port operator. The Gujarat Maritime Board regulates and inspectsregularly the emergency and safety measures. Terminal operations are centrally controlled bycomputer. A computerized control system continuously measures and monitors all processparameters, such as pressure, temperature, flow rate, and mass. The real-time data areprocessed by computer and interpreted to ensure efficient process control and safety. Thecomputerized control system allows immediate identification and location of leaks in the terminalsystem. Emergency signals and alarms are sent out automatically for immediate response.E. Marketing and Sales16. PLL’s business model is based on back-to-back long-term contracts. The purchase ofthe 5.0 MMTPA of LNG imported from Rasgas over 25 years under a sales and purchaseagreement has been tied to gas sales and purchase agreements (GSPA) with three offtakers:GAIL, Indian Oil Company, and Bharat Petroleum Corporation Limited (collectively referred toas the offtakers). Under the GSPA, PLL’s sales obligation to the offtakers is completed on thedelivery of regasified LNG to the GAIL pipeline at the Dahej terminal. From there, GAILtransports the gas through the HBJ pipeline at the offtaker’s risk.17. While the offtakers’ take-or-pay obligations ensure a market for the entire production,some commercial risks remain. All the major participants in the Indian hydrocarbon sector haveplans to enter the natural gas industry. In addition to Indian firms, multinational companiesentering the Indian market are creating new competition. Improvements in explorationtechnology, and economies of scale in gas liquefaction and transportation, are helping to drivedown delivered costs. Offsetting these concerns, the global price of LNG has increased due torising costs of crude oil. Scarcity of gas in domestic and international markets will help underpincontinued high prices.F. Construction Costs and Financial Projections18. At the exchange rate of Rs45 per $1, project costs was well within the range of currentinternational projects. For example, the Mitsubishi Flour Daniel LNG Terminal Project wasestimated to cost approximately $885 million. Financial projections, based on conservative priceprojections and operating costs, indicate excellent financial returns to sponsors, as well asadequate security for debt financiers.
  • 36. 26 Appendix 4 REEVALUATION OF THE ECONOMIC INTERNAL RATE OF RETURNA. Methodology1. The economic internal rate of return (EIRR) was recalculated for 2000–2028, covering 4years of pre-operating activity (2000–2003) and 25 years of operations of the Project. Costs andbenefits are measured using domestic prices, with traded items being adjusted by an exchangerate factor and expressed in constant 2006 prices.7 Figures were adjusted to exclude taxes andinterest. However, they include capital costs of associated facilities, such as the expandedelements of the Hazira–Bijaypur–Jadgishpur (HBJ) pipeline. The shadow exchange rate usedin the analysis was 1.1, which was the same as in the original assessment.B. Valuation of Benefits and Costs 1. Valuation of Benefits2. Economic benefits arising from the Project have been estimated separately for thefertilizer and the power sectors, which are the major consumers of natural gas. Other gas-consuming sectors are transport and steel production. Benefits are based on: (i) Switched (non-incremental) demand or resource cost saving, which reflects the benefits derived from savings using liquefied natural gas (LNG) instead of naphtha. This figure is derived by using the supply market price, which is the cost of production at cost insurance freight (CIF) prices. (ii) Unmet (incremental) demand that is valued by using the demand price based on the free on board (FOB) prices, reflecting the price that consumers are willing to pay for the LNG product.3. Volume demand by end users, as verified from interviews with stakeholders,8 is shown inTable A4.1. Table A4.1: Demand Forecasts (MMSCMD) Sector Demand Fertilizer Unmet demand = 10 MMSCMD Switched demand = 8 MMSCMD Power Switched demand = 7 MMSCMD MMSCMD = million metric standard cubic meters per day. Source: Asian Development Bank estimates.7 Benefits associated with environmental benefits of using clean gas rather than coal have been excluded from the analysis due to difficulties in quantifying them. However, these could be substantial, ranging from $4 million to $24 million per annum.8 GAIL (India) Limited and Indian Oil Corporation Limited.
  • 37. Appendix 4 274. An important feature of these estimates is the combined demand from the fertilizer andpower sector, which exceeds the 5.0 million metric tons per annum plant capacity at Dahej. Thisresult raises two important points: (i) additional plant capacity is needed to meet therequirements of users in the fertilizer, power, and other sectors; and (ii) the switching ofconsumers from expensive alternatives, such as naphtha, will create demand for natural gasfrom existing suppliers. 1. Valuation of Costs5. Financial capital costs were converted to economic costs by excluding taxes and interestduring construction. Traded components were converted to the domestic numeraire by using ashadow exchange rate factor of 1.1. The capital cost included those costs associated with theLNG terminal and the expansion of the HBJ pipeline.6. Besides capital expenditures, the valuation included operations and maintenance cost ofthe LNG terminal and expanded HBJ pipeline, with the latter accounting for about 2.0% of thecapital cost of the HBJ pipeline. The valuation also takes into account the cost of imported LNG,net of duties.C. Economic Internal Rate of Return6. The recalculated EIRR in 2006 prices is estimated to be 32.6% (Table A4.2), comparedwith the appraisal estimate of 23.0%. The higher EIRR is attributed to the substantial price gapbetween natural gas and naphtha, which contributed to higher resource cost savings (thushigher benefits) derived from switching to gas. Sensitivity analysis indicated that the EIRR isrobust under a wide range of scenarios (Table A4.3).
  • 38. 28 Appendix 4 Table A4.2: Petronet LNG Limited Economic Internal Rate of Return (Rs million) CAPEX of Associated O&M O & M of CAPEX Facilities Cost of Associate Cost of of LNG (Expanded LNG d Imported Net Year Terminal HBJ) Terminal Facilities LNG Benefits Benefit 2000 (487.1) (487.1) 2001 (4,824.7) (4,824.7) 2002 (6,054.6) (6,054.6) 2003 (10,954.6) (10,954.6) 2004 (24,207.2) (1,062.4) (484.1) (17,335.0) 25,209.9 (17,878.8) 2005 (1,756.9) (463.5) (33,270.6) 58,669.0 23,177.9 2006 (1,761.1) (450.0) (33,286.1) 58,254.7 22,757.6 2007 (1,788.9) (434.8) (33,044.2) 57,940.2 22,672.4 2008 (1,840.0) (434.8) (36,506.4) 59,184.9 20,403.7 2009 (1,919.2) (434.8) (46,347.5) 59,200.3 10,498.8 2010 (2,101.9) (434.8) (54,338.8) 59,678.5 2,803.0 2011 (2,171.3) (434.8) (62,655.4) 60,133.5 (5,127.9) 2012 (2,206.0) (434.8) (47,688.7) 65,176.5 14,847.0 2013 (2,390.3) (434.8) (49,363.7) 67,093.3 14,904.5 2014 (2,484.4) (434.8) (50,724.9) 69,066.7 15,422.6 2015 (2,521.0) (434.8) (52,383.0) 71,098.0 15,759.2 2016 (2,735.1) (434.8) (53,954.5) 73,189.1 16,064.8 2017 (2,808.2) (434.8) (55,442.7) 75,341.8 16,656.1 2018 (2,881.0) (434.8) (57,254.5) 77,557.6 16,987.4 2019 (3,139.7) (434.8) (58,840.1) 79,838.8 17,424.2 2020 (3,226.2) (434.8) (60,760.6) 82,186.9 17,765.3 2021 (3,316.7) (434.8) (62,595.1) 84,604.2 18,257.5 2022 (3,625.0) (434.8) (64,322.5) 87,092.6 18,710.2 2023 (3,733.5) (434.8) (66,442.9) 89,654.0 19,042.9 2024 (3,837.9) (434.8) (68,269.5) 92,291.0 19,748.8 2025 (4,201.5) (434.8) (70,517.5) 95,005.3 19,851.5 2026 (4,317.6) (434.8) (72,653.8) 97,799.6 20,393.3 2027 (4,439.2) (434.8) (74,668.3) 100,676.1 21,133.8 2028 (4,870.4) (434.8) (77,127.5) 103,637.0 21,204.4 EIRR 32.6%( ) = negative, EIRR = economic internal rate of return, CAPEX = capital expenditure, O&M = operations andmaintenance, LNG = liquefied natural gas, HBJ= Hazira-BIjaypur-Jadgishpur.Source: Asian Development Bank estimates.
  • 39. Appendix 4 29Table A4.3: Petronet LNG Limited Sensitivity Analysis Item EIRR (%) Base Case 32.6 15% Increase in O&M Cost 31.9 20% LNG Price Increase 22.2 10% Decrease in Benefits 21.5 All four adverse scenarios at the same time 3.9 EIRR = economic internal rate of return, O&M = operations and maintenance, LNG = liquefied natural gas. Source: Asian Development Bank estimates.
  • 40. 30 Appendix 5 SOCIAL, ENVIRONMENTAL, HEALTH, AND SAFETY PERFORMANCEA. Petronet LNG Limited Facilities1. Petronet LNG Limited (PLL) has set up a liquefied natural gas (LNG) receiving, storage,and regasification facility at Dahej, Gujarat state. The LNG terminal has a designed capacity of5.0 million metric tons per annum (MMTPA) in phase I, with an expansion envisaged to 10.0MMTPA in phase II. GAIL (India) Limited distributes natural gas from this terminal to consumersthrough a pipeline from Dahej to Vijaypur, which runs parallel to the existing Hazira–Bijaipur–Jagdishpur (HBJ) pipeline.2. At the Dahej site, the Gujarat Maritime Board allotted 55 hectares of land to set up theLNG terminal. The facilities at the existing Dahej terminal include: (i) marine facilities: 2.43-kilometer (km) jetty; mooring dolphins, breasting dolphins, unloading platforms, a gangway tower, walkway bridges. (ii) unloading facilities: LNG loading arms (3), LNG arm (1), unloading line (2), vapor return line, and de-superheater. (iii) LNG storage tanks: two tanks (full-containment type), each with 160,000 cubic meter (m3) gross capacity. (iv) boil-of-gas recovery system: cryogenic compressors (3); suction gas de-superheater and recondensor. (v) send out facilities: low-pressure in-tank pumps. (vi) high-pressure in-tank: pumps, shell and tube vaporizers, submerged combustion vaporizers. (vii) auxiliary facilities: gas turbine generators—3 units each of 7.6 megawatts (MW)); and a transmission line (220 kilovolt ampere from Gujarat Electricity Board).3. The terminal started commercial operations on 9 April 2004. The Operations EvaluationMission (OEM) focused on the evaluation of activities in phase I of the construction andoperation of the Dahej LNG terminal.B. Social Impacts4. A public hearing is a mandatory requirement by Ministry of Environment and Forests(MOEF), before it can grant Environmental Impact Assessment (EIA) clearance. The GujaratPollution Control Board conducted the public hearing for phase I on 19 November 1999, andnotices were published on 14 February 2001 in two newspapers. No objections were raised.5. At the project site, some 15 unauthorized occupants were provided alternate plots ofland by Gujarat Industrial Development Corporation (GIDC), an ex gratia payment forconstructing new dwellings, and a sustenance amount of funding. PLL made the monetarypayment to GIDC, which paid the occupants.6. PLL is undertaking corporate social responsibility activities, such as constructing atemple, and contributing infrastructure for drinking water and roads. The company also hasrecruited local people to provide security services, firefighting, and green belt maintenance.Further, PLL has given the contract for housekeeping to a local person.
  • 41. Appendix 5 31C. Description of the Environment7. During construction of the terminal, the environmental impacts were limited. The EIA andenvironmental management plan suggested adequate preventive measures. In the currentoperational phase, the plant is meeting the environmental standards and conditions asprescribed by enforcement and regulatory bodies. The details on compliance are as follows: 1. Terrestrial Environment a. Air8. Ambient Air Quality. An agency approved by Gujarat Pollution Control Board (GPCB)regularly monitors sulfur dioxide (SO2), nitrogen oxides (NOX), suspended particulate matter(SPM), and hydrocarbons and flammable gases in the plant premises. Ambient air qualityimpacts are found to be within the standards prescribed by GPCB. For example, in April 2006,the 24 hourly ambient air quality values at various locations in and around the plant premises(near main gate, near fire station, near tank 101, and near canteen) were well below the GPCBstandards (Table A5). Table A5: Ambient Air Quality Values at PLL, Dahej (April 2006) Range of Ambient Std. No. Pollutant Unit GPCB Limit Concentrations 1 Suspended particulate matter μg/m3 500 112–145 (SPM) 2 Oxides of sulphur (SO2) μg/m3 120 18–29 3 Oxides of nitrogen (NOx) μg/m3 120 25–34 4 Hydrocarbon μg/m3 160 25–38 GPCB = Gujarat Pollution Control Board, μg/m3 = micrograms per cubic meter. Source: Asian Development Bank estimates.9. Stack Gas Emissions. The stack gas emissions from the gas turbine generators (GTG)in the terminal are constantly monitored, and are within the standards prescribed by GPCB. Asthe three GTGs run on natural gas, the emissions of SPM and SO2 are small. NOX is the onlysignificant potential pollutant. To address this issue, the GTGs are equipped with “lean-burn”technology to control the amount of NOx emissions. The submerged combustion vaporizers forLNG gasification also operate on natural gas, and are a potential source of NOx emissions.However, they are used only occasionally during the winter months, which minimizes this risk.Their contribution to NOx emissions is small compared with the emissions from the GTGs. Thestack gas emission monitoring results from the GTGs in April 2006 indicated SPM values of 39milligrams per normal cubic meter (mg/Nm3), well below the GPCB limit of 150 mg/Nm3.Likewise, the NOX values were 20 parts per million (ppm), less than half the GPCB limit of 50ppm; and the SO2 emissions were zero, compared with the GPCB limit of 100 ppm. b. Water10. As PLL gets industrial water from GIDC, no groundwater is used. No wastewater isdischarged outside the plant premises.
  • 42. 32 Appendix 5 c. Noise Level11. Noise levels are generally within the standards (except at a few locations in the plant). d. Hazardous Waste12. A small quantity of waste oil is generated, which is disposed of through a GPCB-accredited contractor. 2. Coastal Environment13. As indicated by the high levels of suspended solids, the coastal water adjacent to theDahej LNG facility is very turbid. The concentration of suspended solids, originating naturallyfrom the dispersion of bed sediment in the water, varies widely. High tidal influence and strongcurrents mix the water column well. The overall productivity of marine resources is low, and thelevels of phytoplankton pigments are markedly low. Considering the quantitative and qualitativenature of zooplankton, the area can be rated moderate to poor in secondary production.Consequently, the Gulf of Khambat has no active commercial fishing.14. Potential impacts on the marine environment during the operational phase of the Projectinvolve (i) an LNG spill, (ii) release of wastes generated by ships or port terminals, and (iii)large-scale release of fuel or chemicals due to accident or collision. Although an LNG spill wouldnot cause serious damage to the marine environment, it would create considerable risk of fireand explosions. Major accidental spills of oil, though rare, have the potential to contaminate themarine environment. Such spills can occur due to accidents, such as ship or tanker collisionsand ship grounding, which in turn are dependant on traffic density. Since the LNG tankers runon natural gas and not diesel oil, the potential oil spill from an LNG tanker would be smallcompared with that from ships running on diesel oil or from oil tankers. An appropriate trafficcontrol scheme and adequate navigational aids would reduce the frequency of such encounters.PLL will participate in the traffic control management plan for the Dahej port and the Gulf ofKhambat, which the Gujarat Maritime Board will prepare.15. Due to unpredictable climatic conditions during the monsoon season, the original projectdesign included a breakwater to reduce the potential for accidents while ships are mooring atthe jetty. PLL has conducted some independent studies, which concluded that the breakwaterwas not essential for safe ship operations. Based on the recommendation of several consultants,PLL decided not to construct a breakwater at Dahej. Instead, it is constructing an additionalLNG storage tank, which will provide the necessary operational flexibility during the monsoonseason. While the decision not to build the breakwater will reduce environmental impacts, themarine safety issues at the jetty are being reviewed with assistance from Gaz de France (GDF)and other international consultants.D. Health and Safety16. The comprehensive environmental impact assessment studies for the LNG terminal,which were carried out by the Institute for Petroleum Safety and Environment Management, Oiland Natural Gas Corporation Limited, and Water and Power Consultancy Services Centre forEnvironment, assessed the fire and explosion risks under different scenarios. The studies foundthat under most scenarios the impacts would be within the plant premises. As designed, theLNG installation is intrinsically safe. Except in a war-like situation, when the tank would leakconsiderably, the nearest inhabitants are not under threat. In addition, Sofregaz conducted a
  • 43. Appendix 5 33rapid risk analysis of the LNG terminal at Dahej for three different types of LNG storage tanks,9and recommended a full-containment type tank. The impacts of gas release from the safetyvalves of the full storage tank showed that this scenario had no effect outside the battery limitsof the terminal.17. As these results show, apart from possible risks associated with the jetty, operatingconditions are safe. To date, the Dahej LNG terminal has achieved 2.73 million accident freeman-hours of operation since the start of operations. The National Safety Council, whichconducted a safety audit of the plant in October 2005, made recommendations for improving thesafety programs, procedures, and systems. GDF also carried out a safety audit of the Dahejterminal and submitted its final report in November 2005 with recommendations. In particular,GDF highlighted that the jetty remains one of the main safety issues for Dahej. GDFrecommended that a review of the nautical procedures be implemented to ensure they areappropriate for the current jetty configuration. PLL has had three near misses in the past 2 years,which is higher than the global average of about 0.3 near misses per year.E. Mitigation Measures for Environmental and Safety Risks18. Because LNG is a clean energy source compared with oil and coal, the Project improvesthe environment while meeting the rising energy requirements of the country. The LNG terminalhas minimal environmental impacts. However, due to the nature of the product being handled,safety issues are a high priority. The Dahej terminal has adopted a variety of measures that areenvironmentally friendly and contribute to enhanced safety, including the following: (i) Terminal operations are centrally controlled by computer using a system that continuously measures and monitors all process parameters, and allows immediate identification and location of leaks in the terminal system. Emergency signals and alarms then are sent out for immediate response. (ii) An unloading control room is situated at the jetty to receive continuous data on wind speed and wave heights in the vicinity. Emergency responses to wind and wave conditions, as well as LNG leaks, are prescribed, and procedures for implementation are established. The jetty terminal is equipped for firefighting. Another important feature is the system for automatic disconnection of the unloading arm from the ship in case of an emergency. (iii) For jetty operations, PLL has engaged an experienced port operator to provide services that include hazard prevention, as well as health, safety, and environment services related to jetty operations. With the assistance of the port operator, the Health, Safety and Environment Unit is involved in prevention activities on the waterfront. (iv) The two existing LNG storage facilities are full-containment tanks that are safer than double-containment tanks. The tanks have other advantages in addition to safety, such as reduced boil-off gas during unloading operations (due to higher operating pressure), and less risk from ruptures and accidents. (v) Due to the site conditions, instead of conventional open rack vaporizers, PLL has adopted an indirect LNG regasification system that uses a glycol water air9 Version dated 5 November 1998.
  • 44. 34 Appendix 5 heating system. The air heating system has proved to be environment-friendly, producing a significant amount of clean water from condensation of humidity in the air. PLL has started collecting this water for cleaning and plant irrigation. (vi) The fire protection and safety measures at PLL Dahej include spill detector, fire detector, gas detector, water curtain, and deluge spray systems. (vii) A mutual aid system is in place with other companies operating in the Dahej industrial estate.19. In accordance with legal requirements, PLL has prepared various management plans tohandle an emergency situation. These plans are as follows: (i) PLL has prepared an emergency response plan (ERP) to mitigate potential damage to health and the environment from fires, explosions, and toxic releases. The ERP prescribes actions and procedures for dealing with major releases, un- ignited releases, and fire and explosion emergencies. The ERP also is supported by (a) gas detection, (b) safety shutdown and fire protection systems, (c) safety and security zones, (d) a ship and facility emergency response plan, (e) coordination with Gujarat Maritime Board and the Coast Guard, and (f) evacuation plans and procedures. (ii) An offsite emergency management plan was prepared in July 2003 for Dahej area (Vagra Taluka), though it needs to be updated. The local crisis group (chaired by the deputy collector) and the district crisis group (chaired by the district collector) were formed in the district in accordance with the Chemical Accidents (Emergency Planning, Preparedness, and Response) Rule 1996 under the Environment (Protection) Act 1986 to combat any disasters or emergency situations that might endanger the safety and health of public. PLL is a member of the Disaster Management Centre, Dahej. (iii) PLL has prepared an oil spill contingency plan for its Dahej marine terminal, which details the arrangements for responding to oil pollution incidents at the tanker jetty. It also shows the relationship of the plan to the National Oil Spill Disaster Contingency Plan, and to the district and regional Plans.F. Institutional Arrangements and Monitoring Program20. The PLL Dahej terminal complies with legal requirements related to environment andsafety. PLL has been reporting the status of its operations in accordance with regulatorystandards to various government bodies, such as MOEF and GPCB, which monitor theconditions under which clearances are granted. As a proactive measure, PLL has had its Dahejoperations audited, and obtained third-party certifications for environment, health, and safety.Reputable organizations also have conducted some additional safety audits, and haverecommended improvements to PLL.
  • 45. Appendix 5 3521. Specific legal compliance requirements are as follows: (i) MOEF, New Delhi cleared the EIA report for the Dahej terminal, subject to certain conditions. 10 Since then, PLL has been submitting compliance reports on conditions stipulated by MOEF to the regional office of MOEF at Bhopal. (ii) The Forests and Environment Department of the government of Gujarat also stipulated certain conditions for Coastal Regulation Zone clearance for construction of the LNG import terminal at Dahej. 11 PLL submits compliance reports to the state Forests and Environment Department every 6 months. (iii) GPCB provided a no-objection certificate in 200012 for setting up the LNG project, and subsequently gave a consolidated consent and authorization to operate in 2004,13 subject to certain conditions. The consents were issued under the Air Act 1981, Water Act 1974, and Authorization under the Hazardous Waste (Management and Handling) Rules 1989, and its subsequent amendments under the Environment Protection Act 1986. GPCB monitors compliance to ensure that the conditions stipulated under the consent are being met. PLL submits quarterly environmental monitoring reports, as well as an annual environmental statement to GPCB. (iv) The chief controller of explosives has provided licenses for liquid nitrogen storage and diesel storage, and provided a no-objection certificate for commissioning the LNG storage tanks. (v) PLL has taken out a public liability policy.22. The Dahej LNG terminal received International Standards Organization (ISO) 9001certification for quality management system in its first year of operation. The terminal also hasreceived Occupational Health and Safety Management system 18001 certification, and ISO14001 certification for its Environment Management System in 2005.10 Letter dated 27 December 2000.11 Letter dated 29 September 2000.12 Dated 2 February 2000.13 Dated 28 September 2004.

×