Tunisia - Second Natural Gas Pipeline Project

Document of The World Bank FOR OFFICIAL USE ONLY Report No. 8754 PROJECT PERFORMANCE AUDIT REPORT TUNISIA SECOND NATURAL GAS PIPELINE PROJECT (LOAN 1864-TUN) JUNE 13, 1990 Operations Evaluation Department This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. COUNTRY EXCHANGE RATES Tunisian Dinar (DT)IUS$ Appraisal Estimate US$1.00 0.400 Actual July 1981 = 0.425 April 1982 = 0.526 Average 1984 = 0.7768 Average 1985 - 0.8345 Average 1986 = 0.7940 Average 1987 = 0.8207 Average 1988 = 0.8578 ACRONYMS AND ABBREVIATIONS Bbla - Barrels of 42 US gallons BOPD - Barrels of oil per day ERR - Economic rate of return FRR - Financial rate of return MMCM - Million cubic meters MEM - Ministry of Energy and Mines PCR - Project Completion Report PPAR - Project Performance Audit Report SAR - Staff Appraisal Report STEG - Societe Tunisienne de VElectricite et du Gaz TMP - Trans-Mediterranean Pipeline TOE - Ton oil equivalent To* WORLD 8ANK M0OMIM1KOHLY Washington. DC 20433 US.A. June 13, 1990 MEMORANDUM TO THE EXECUTIVE DIRECTORS AND THE PRESIDENT SUBJECT: Project Performance Audit Report on Tunisia Second Natural Gas Pipeline Project (Loan 1864-TUN) Attached, for information, is a copy of a report entitled OProject Performance Audit Report on Tunisia - Second Natural Gas Pipeline Project (Loan 1864-TUN)* prepared by the Operations Evaluation Department. This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. FOR OFFICIAL USE ONLY PROJECT PERFORMANCE AUDIT REPORT TUNISIA SECOND NATURAL GAS PIPELINE PROJECT (LOAN 1864-TUN) TABLE OF CONTENTS Page No. Preface ................................................ .......... Basic Data Sheets ...............................................1 Evaluation Summary ............................................... v PROJECT PERFORMANCE AUDIT REPORT I. BACKGROUND .......................................... Origin of the Project ........................... 1 Project Objectives .................................. 2 Project Description................................ 3 Implementation Arrangements . ............. 3 Experience Under Previous Projects .................. 3 II. IMPLEMENTATION EXPERIENCE ................................ 4 Changes in Project Scope ............................ 4 Implementation Delays ............................... 5 Procurement and Disbursement ........................ 6 Project Cost and Financing .......................... 7 The Performance of the Borrover .................... 8 The Performance of the Bank ......................... 8 III. PROJECT OUTCOME......................................... 9 Operating Performance ............................... 9 Economic Reevaluation ............................... 10 Financial Performance................................ 10 IV. FINDINGS AND ISSUES ...................................... 11 Overall Assessment .................................. 11 Project Design and Preparation ...................... 12 Sustainability ...................................... 15 Lessons of Experience .................... ......... 15 This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. TABLE OF CONTENTS (Cont'd) Page No. PROJECT COMPLETION REPORT ................................... 17 I. THE SECTOR AND BANK ROLE ............................. 19 II. THE TRANS-MEDITERRANEAN PIPELINE AND GAS AVAILABILITY..... 20 A. The Trans-Mediterranean Pipeline .................. 20 B. Gas Availability ................................... 21 III. GAS DEMAND AND PRICING ................................... 23 A. Gas Demand ......................................... 23 B. Price of Imported Gas .............................. 25 C. Domestic Prices .............. ..... ..... ......... 26 IV. PROJECT PRICING AND APPRAISAL ........... 27 A. Project Origin ..................................... 27 B. Project Description ................................ 27 C. Changes in Project Scope ........................... 28 V. PROJECT IMPLEMENTATION ................................... 29 A. Project Cost ....................................... 29 B. Procurement and Disbursement ....................... 29 VI. IMPLEMENTATION PERFORMANCE ............................... 31 A. Spurlines ......................................... 31 B. Distribution ....................................... 32 C. Conversion ......... .............................. 32 D. Sales Engineering Activities ...................... 32 E. Project Appraisal and Supervision by the Bank ...... 33 F. Performance of Consultants, Suppliers and Contractors ..................................... 33 G. Training ........................................ 33 VII. OPERATIONAL PERFORMANCE .................................. 34 A. Gas System Operation ................................. 34 B. Environmental Aspect and Safety .................... 34 VIII. INSTITUTIONAL ASPECTS ................................... 35 IX. FINANCIAL ASPECTS ......................... 36 A. Separation of Accounts ............................. 36 B. Financial Performance ............................. 38 C. Financing Plan ................................. 40 D. Conclusion ......................................... 41 X. ECONOMIC REEVALUATION .................................... 41 XI. CONCLUSIONS ............................. ................. 42 PCR ANNEXES 1. Consumption of Petroleum Products ......................... 45 2. Northern Gas Activity ..................................... 46 3. The Pricing of Natural Gas ................................ 47 4. Detailed Project Description .............................. 58 5. Disbursement Performance Analysis ....................... 60 6. Project Implementation Chart .............................. 61 7. STEG - Imported Gas Operations ............................ 62 8. Economic Rate of Return Calculation ....................... 65 MAP: IBRD 148491 PROJECT PERFORMANCE AUDIT REPORT TUNISIA SECOND NATURAL GAS PIPELINE PROJECT (LOAN 1864-TUN) PREFACE 1. This is a Project Performance Audit Report (PPAR) on the Second Natural Gas Pipeline Project, involving an IBRD loan in the amount of US$37.0 million to Societe Tunisienne de l'Electricite et du Gaz (STEG), with the objective of assisting the construction of a natural gas transmission and distribution infrastructure. The loan was approved on June 5, 1980. The Loan Agreement was amended on July 15, 1981, and became effective on December 9, 1981. US$10.0 million of the loan amount was cancelled in September 1985 at the request of the Borrower. The clsing date of December 31, 1983 was extended to December 31, 1986. Final disbursement was made on January 25, 1988. Cofinancing in the amount of US$16.0 million was provided by suppliers and commercial banks. 2. The PPAR was prepared by the Operations Evaluation Department (OED) and the Project Completion Report (PCR) was prepared by the Europe, Middle East and North Africa Regional Office. The PPAR is based on the attached PCR, the Staff Appraisal and the President's Reports, the loan documents, the transcripts of the Executive Directors' meetings at which the project was considered, on a study of project files, and on discussions with Bank staff. An OED mission visited Tunisia in November 1989, and discussed the effectiveness of the Bank's assistance with STEG and the Ministry of Planning. Their kind cooperation and valuable assistance in the preparation of this report is gratefully acknowledged. 3. The PCR provides a very good account and assessment of the project experience, and discusses the performances of the Bank and the project executing agency. The PPAR elaborates on particular aspects of project implementation, the design and definition of the project and the performance of the Bank. 4. Following standard OED procedures, copies of the draft PPAR were sent to the Borrower. No comments were, however, received. - iii - PROJECT PERFORMANCE AUDIT REPORT TUNISIA SECOND NATURAL GAS PIPELINE PROJECT (LOAN 1864-TUN) REY PROJECT DATA Appraisal Actual or Actual as 2 of Item Expectation Current Estimate Appr. Estimate Total Project Cost (US$ million) 88.0 45.6 51.8 Loan Amount (US$ million) 37.0 27.0 72.9 Cofinancing-Total (US$ million) 30.0 16.0 53.3 Suppliers'/Commercial Credits 30.0 16.0 53.3 Date Physical Components Completed 03/82 12/87 282 La Economic Rate of Return (Z) 28 14 50.0 Institutional Performance Satisfactory Satisfactory /a From loan signing to project completion. CUMULATIVE ESTIMATED AND ACTUAL DISBURSEMENTS (US$ million) As of June 30, 1981 1982 1983 1984 1985 1986 1987 1988 (i) Appraisal Estimate 20.0 34.0 37.0 37.0 37.0 37.0 37.0 37.0 (ii) Actual 0.0 8.2 16.1 18.1 21.3 22.8 26.2 27.0 (iii) (ii) as X of (i) 0.0 24.1 43.5 48.9 57.6 61.6 70.8 73.0 Date of Final Disbursement: 01/25188 PROJECT DATES Original Plan Revised Actual First Mention in Files 02/05/79 Negotiations 04/00/80 - 04/21/80 Board Approval 06/05/80 - 06/05/80 Loan Agreement Date 10/22/80 - 10/22/80 Amendment Date - - 07/15/81 Effectiveness Date 09/01/80 12/09/81 12/09/81 Closing Date 12/31/83 12/31/86 12/31/86 - iv - STAFF INPUT (Staff-Weeks) Bank FY 1980 1981 1982 1983 1984 1985 1986 1987 1988 Totals Preappraisal 8.4 8.4 Appraisal 34.5 34.5 Negotiations 15.2 15.2 Supervision 0.6 31.7 9.2 5.9 53.7 15.7 14.8 9.6 10.1 151.3 Other 1.0 1.0 Totals 59.7 31.7 9.2 5.9 53.7 15.7 14.8 9.6 10.1 210.4 MISSION DATA month/ No. of No. of Date of Year Weeks Persons Manweeks Report Identification 06/79 3.0 2 6.0 07/10/79 Preappraisal 10/79 2.0 4 8.0 11/08/79 Appraisal I 11/79 1.0 2 2.0 11/27/79 Appraisal II 02/80 1.0 3 3.0 02/29/80 Supervision I 04/82 1.0 2 2.0 04129/82 Supervision II 03/83 1.0 1 1.0 04/13/83 Supervision III 07/84 1.0 3 3.0 07/27/84 Supervision IV 01/85 1.5 4 6.0 02/13/85 Supervision V 07/85 2.0 4 8.0 08/30/85 Supervision VI 06/86 2.0 2 4.0 08/14/86 Total 15.5 43.0 OTHER PROJECT DATA Borrower: Societe Tunisienne de l'Electricite et du Gaz (STEG) Executing Agencys STEG Fiscal Year of Borrower: January 1 - December 31 Follow-on Projects: None - v - PROJECT PERFORMANCE AUDIT REPORT TUNISIA SECOND NATURAL GAS PIPELINE PROJECT (LOAN 1864-TUN) EVALUATION SUMMARY Introduction 1. The Second Natural Gas Pipeline Project was the Bank's second operation in Tunisia's petroleum subsector. The first project was a US$7.5 million loan to finance a pipeline to deliver gas from the El Bormah field to the industrialized Gabes area. The El Bormah's declining production did not make worthwhile, however, to extend the network northward. When the Trans-Mediterranean Pipeline carrying Algerian gas to Italy was near completion (with delivery to begin in 1981), the Government of Tunisia realized that it offered a unique opportunity to increase gas usage in the northern part of the country. The Second Natural Gas Pipeline Project supported the Government's energy sector strategy (PCR, para. 1.01; PPAR, para. 3). It comprised the construction of part of the infrastructure needed for the transmission and distribution of the natural gas to be supplied through the Trans-Mediterranean Pipeline (TMP) between Algeria and Italy, as well as the gas to be available in the future from the development of domestic gas fields, along with studies and technical assistance (PCR, para. 4.02-4.06; PPAR, para. 9). The project was implemented by the Societe Tunisienne de 'Electricite et du Gaz (STEG), with assistance from expatriate consultants (PCR, paras. 1.04 and 5.04; PPAR, para. 10). The total project cost was estimated originally at US$88.0 million, of which 422 (US$37.0 million) would be financed by the Bank loan. Cofinancing in the amount of US$30.0 million was expected from various official export credit agencies and commercial banks (PCR, paras. 9.12-9.14; PPAR, para. 24). Obiectives 2. The principal objectives of the project were to improve Tunisia's energy situation by substituting imported natural gas for fuel oil, and to introduce energy planning and pricing measures required for the development of a rational energy policy (PPAR, para. 4). Implementation Experience 3. Soon after the approval of the loan, the economic viability of the project was impaired due to prospects of a large increase in the price of the Algerian gas. As a result, the scope of the project was modified to - vi - suit the new objective of using smaller volumes of imported gas to replace premium fuels, instead of high-sulphur fuel oil as originally intended (PCR, paras. 4.05-4.08; PPAR, paras. 13-16). Pipeline construction was deferred pending the finalization of a new gas supply agreement with Algeria. This resulted in a project completion delay of about two years (PCR, paras. 2.02, 2.06, 6.01, and Annex 6; PPAR, para. 17). The disbursement of the loan took three years longer than estimated, due to late start of procurement and construction and delays in the implementation of the gas distribution and customer conversion components of the project (PCR, Annex 5 and 7; PPAR, para. 20). As a result, the availability of loan funds as measured by the average loan life was significantly reduced (PPAR, para. 21). 4. Actual project costs (US$49.4 million) were 44Z lower than the appraisal estimates in U.S. dollar terms, but there was a 4Z cost overrun in terms of Tunisian dinars. The main reason for the cost underrun in terms of U.S. dollars was the strong appreciation of the dollar vis-a-vis European currencies in which major contracts were denominated (PCR, paras. 5.01-5.03, 6.02, 11.03, and Table 2; PPAR, paras. 22-23). Due to lower actual project costs, only US$16.0 million of cofinancing in suppliers' credits and commercial borrowing was used. The unused portion of the Bank loan (US$10.0 million) was cancelled in September 1985 at the request of the Borrower (PCR, paras. 5.06 and 9.12-9.16; PPAR, para. 24). Results 5. The branch pipelines constructed under the project became operational toward the end of 1983 and early 1984. Gas delivery to Tunisia from the TMP started in November 1983 and built up to 911,000 tons of oil equivalent (TOE) in 1987. This is about 38% of the appraisal estimate. The short-fall is due mainly to STEG's policy )f not using gas when it is priced higher than the fuel oil. and the slow penetration of natural gas into the premium fuels market. So far, the imported gas has replaced mainly a portion of the fuel oil and only a modest portion of the premium fuels which it was intended to substitute (P:?, paras. 2.05-2.07, 3.01-3.08, and 6.01; PPAR, para. 29). Due to low imported gas consumption, the utilization of the system capacity has remained low, and this excess capacity is expected to persist in the medium term (PCR, para. 7.02; PPAR, para. 32). The mechanical operation of the pipeline system is satisfactory, except three measurement centers whose operations continue to be affected by design and construction faults (PCR, paras. 5.06-6.07; PPAR, para. 33). 6. The reevaluated economic rate of return (ERR) of the project (14%) is lower than the appraisal estimates (28-50%), due mainly to the higher- than-expected cost of the Algerian gas, small amounts of premium fuels substituted, and the low pipeline capacity utilization (PCR, paras. 10.01-10.04 and Annex 8; PPAR, para. 34). At present STEG is the main user of the imported gas. Although it does not prepare separate cash accounts for its imported gas activities and does not revalue its assets on an annual basis, accounts prepared at the Bank's urging for the Algerian Gas - vii - division indicate that the project's financial rate of return (FRR) remains considerably below the covenanted 81 return on revalued assets (PCR, paras. 9.01-9.08 and Annex 7s PPAR, paras. 35-36). Sustainability 7. The sustainability of the economic benefits derived from the project appears to be assured, since even under currcnt unfavorable conditions the project shows an acceptable ERR, and SThG has already developed the technical skills required for a gas distribution concern (PCR, paras. 7.04 and 8.02-8.05; PPAR, para. 48). Although half of the level anticipated at appraisal, the ERR was still relatively high for an infrastructure project (14Z). This is mainly due to the gap between the cost of the Algerian gas and the price billed to users which accrues to the economy. Financial sustainability is, however, in doubt given that debt service in principal and interest absorb all cash flows (PPAR, paras. 36 and 51). Findings and Lessons 8. This was a successful project on technical grounds, but its financial viability has yet to be demonstrated. It has achieved its primary objective of installing a gas distribution infrastructure in Northern Tunisia where most of the country's population lives. Although less than expected, imported natural gas has made significant inroads into Tunisia's premium fuels market. With the exception of ensuring separately the financial viability of STEG's purchased gas and power activities, the institutional objectives of the project were also attained through training and consultancy services. The project's main policy objective of rationalizing domestic petroleum product prices was achieved to a large extent, both as a result of the gradual increase in domestic prices and the collapse of international oil prices after 1986 (PCR, paras. 3.13, 6.08, 7.04, 8.05, 9.06, and Annex 3; PPAR, para. 17). 9. The project was related to one of the largest international gas projects (TP), with all the complexities which are inherent to such projects, such s long lead planning time, heavy front end investment, long-term contractual arrangements, as well as pricing issues. Nevertheless, the Bank and the Borrower committed themselves to the project before uncertainties surrounding the size of the potential gas market, the volume and the price of the Algerian gas, and the domestic gas development plans were clarified. Later, some of the assumptions on which the project concept was based proved to be unrealistic, necessitating the redesign of the project in mid-course (PCR, paras. 3.01, 3.09, 11.01, 11.04 (a), and Annex 3; PPAR, paras. 38-46). The project was prepared, amended, and implemented under considerable time pressure, and this resulted in overlooking several important aspects, such as customer conversion, market development, gas distribution and utilization standards, and reliable supervisory control and data acquisition system (PPAR, para. 28). Due to the prevalence of long lead time activities, such as pipe manufacturing, - viii - contractor mobilization, etc., little time was available for adequate consideration of all critical project issues (PCR, para. 11.04(a); PPAR, para. 46). 10. A lesson drawn from previous Bank-financed natural gas transmission and distribution projects is the need for careful planning and timely implementation of those activities that are critical to building up sales rapidly in early years, such as market development and conversion of customers' equipment. Experience under the project reinforces this lesson (PPAR, para. 49). Another lesson emerging from the project experience relates to the need to assess through concrete risk analysis all the factors which can affect negatively the project performance before embarking on a project involving long lead time activities (PPAR, para. 50). If, as it is the case for this project, well into the repayment period of the loan the corresponding project barely covers debt service an(4 has no margin to self-finance future investments, the future creditworthiness of that borrower is impaired. This undesirable side- effect could be prevented if project site and financing are better -ailored to a more realistic assessment of the ability to borrow (PPAR, para. 51). PROJECT PERFORMANCE AUDIT REPORT TUNISIA SECOND NATURAL GAS PIPELINE PROJECT (LOAN 1864-TUN) I. BACKGROUND Origin of the Project 1. Hydrocarbons are the major source of energy in Tunisia, representing about 95% of the commercial energy consumption. For the foreseeable future, Tunisia will have to depend on these sources of energy because opportunities for greater use of hydropower and coal or renewable sources are limited. When the Second Natural Gas Pipeline Project was prepared in 1979, the country was a net exporter of oil. However, consumption had been growing at 8% per annum since 1972, and was expected to maintain the same growth rate through the 1980s, while production from known reserves was anticipated to decline sharply. 2. Although relatively large reserves of natural gas had been discovered at the offshore Miskar gas field, the Government had deferred the ex-'oitation of this field, mostly because of the high cost of develop:- .t, estimated at US$620 million, including its related onshore distribution system (President's Report, para. 36). Given the estimated consumption growth, the forecast decline in crude oil production was expected to result in a net petroleum import position by the mid-1980s. In order to maintain to the extent possible oil exports at their then current level, Tunisia intended to substitute imported natural gas for fuel oil (President's Report, para. 24). 3. Under an existing international agreement, Tunisia would be receiving royalty gas (or its equivalent in cash) from the Trans- Mediterranean Pipeline (TMP) between Algeria and Italy, beginning October 1981. Depending on the throughput of gas in the TMP, the amount of royalty gas was expected to increase from 200 million cubic meters (MMCM) in 1982 to 800 MMCM in 1986. In addition, Tunisia and Algeria were in the process of finalizing a gas purchase agreement enabling Tunisia to import an additional 500-1,200 MMCM per year of Algerian gas via the TMP (PCR, paras. 2.01-2.07, and Table 1). It was expected that the availability of favorably priced natural gas and its substitution for oil would help ensure Tunisia's energy supply up to the 1990s and, by making more fuel oil available for export, would reduce the impact of the decline in crude oil production (President's Report, para. 25). -2- Project Objectives 4. The President's Report (para. 41) lists the objectives of the project ass (i) to help improve Tunisia's energy situation by substituting natural gas for fuel oil, thereby decreasing domestic fuel oil consumption and increasing fuel oil exports; and (ii) to introduce energy planning and pricing measures which would permit Tunisia to develop a rational energy policy for its future, beyond mid-1990s, when it might no longer be able to rely or, domestic hydrocarbons as its major primary energy resource. 5. Aeplacing domestic fuel oil with imported natural gas, or royalty gas '...: did not need to be taken in kind, was economically viable only when tsi Algerian natural gas destined to both the Italian and Tunisian markets was priced significantly below fuel oil, and the surplus fuel oil could be exported without incurring heavy price penalties into the already saturated European market. 6. During project appraisal, Bank staff were shown the pricing clauses of the gas supply contract between Algeria and Italy. Although they were awarel/ of the Algerian government's intention of narrowing over time the gap between the gas price at the border and the international fuel oil price, they chose to accept the price to Italy as an imautable ceiling for the cost of the Algerian gas to Tunisia. The risks connected with exporting large amounts of displaced fuel oil were dismissed summarily (President's Report, para. 57).2/ 7. However, the description given in the President's Report shows clearly that the project was part of a long-term master plan for gas development. It was to constitute the first phase in the construction of a gas distribution network in Tunisia. A second phase, to start up by 1985, would extend the system by adding connecting lines to Bizerte and Gafsa (see Hap IBRD 14849R1). At a later stage Sousse would be linked, and eventually the Miskar gas field would be connected to the onshore system. Pipe diameters had been optimized on the basis of 1990 forecast demands. The final system was expected to provide maximum operational flexibility and would be capable of receiving gas from almost any field off Tunisia's east coast (President's Report, paras. 44-45). Within this concept the project made good economic sense since (i) in late 1979 after the so-called Osecond oil price shock* expectations were for continually rising energy prices, and (ii) large amounts of natural gas had already been discovered offshore Tunisia and prospects for additional discoveries were judged to be favorable (SAR, paras. 1.02-1.05). 11 Project Brief and Issues Paper, November 9, 1979, para. 2.05. 2/ The President's Memorandum (Secretary's No. R81-179, June 22, 1981, para. 11) notes that the amendment of the project in a way to substitute premium fuels with royalty gas had fliz1minated the risk of not finding export markets for large quantities of fuel oil, thus implying that the fuel oil export issue was not satisfactorily resolved at appraisal. - 3 - 8. The second objective has been one of the major goals of the Bank's energy program. It was already incorporated into the Second Power Loan (Loan No. 1355-TUN of 1977), under which the Government had agreed to undertake a pricing policy study for oil, gas and electricity. The scope of this study was later expanded into a sectoral planning study for preparing an energy master plan covering all potential sources of energy as well as detailed demand analysis. A foreign consultant had been selected to perform the study and to develop an energy planning model which was expected to be ready by the end of 1980 (President's Report, para. 32). Project Description 9. The project consisted of the construction of part of the infrastructure needed for the transmission and distribution of the natural gas to be supplied through the TMP and to be available in the future from the development of domestic gas fields. It included approximately 290 km of 18-200 diameter branch pipelines to main consumption centers (North Tunis, Sousse, Gafsa, Kasserine and Tadjerouine), 170 km of distribution mains and service connections with ancillary facilities, an unspecified number of conversions of customers' oil-using plants to dual firing, consultancy services, and training of the Borrower's staff (PCR, paras. 4.02-4.04). Implementation Arrangements 10. The project was implemented by the Societe Tunisienne de 1'Electricite et du Gaz (STEG), the national utility in charge of electric power activities and gas distribution, with assistance from international consultants for design, engineering, construction supervision, special studies and training. The construction work was entrusted to prequalified international pipeline contractors (PCR, paras. 1.04 and 5.04). Experience Under Previous Projects 11. The project was the Bank's second operation in Tunisia's natural gas subsector. The first Bank loan (Loan No. 724-TUN, approved in January 1971) financed the natural gas pipeline from the El Borma field to Gabes, also implemented by STEG. The PPAR on this project has found that the project was completed with minor delays and cost overruns. Excepting initial operating problems in the compression and gas and cooling water treatment plants, which took a relatively long time to solve, the operating performance of the project was generally satisfactory and the ERR was higher than the appraisal estimate due to higher petroleum prices. STEG's implementation performance had been satisfactory. However, the loan covenant about preparing a study on power tariffs and adjusting them according to the results of the study was not completely adhered to. The study was completed after the lengthy delays, but tariffs were not revised.3/ 3/ PPAR - Tunisias El Borma-Gabes Gas Pipeline Project (Loan No. 724-TUN), IBRD Report No. 1078, March 12, 1976, paras. 3.01, 3.03-3.04, and 5.05. 12. The aforementioned PPAR (para. 3.07) also noted that *time pressure at all stages of pipeline design and construction had a number of undesirable side effects. It meant that the Bank approval had to be given for tender documents before the loan was signed and at very short notice. There was, therefore, little time available for extended consideration of the technical factors involved.* Time pressure was a factor adversely affecting also the implementation of the Second Natural Gas Pipeline Project (PPAR, para. 16). II. IMPLEMENTATION EXPERIENCE Changes in Project Scope 13. Before the Loan Agreement was signed, the Government informed the Bank that, in the light of the new situation created by the prospect of a large increase in the price of Algerian gas, it had opted to build a distribution system for the use of the royalty gas only.4/ Subsequently, a Bank mission visited Tunisia in September 1980 to discuss with the Government and the Borrower the details of a revised project.5/ While the revised project concept was still under review in the Bank, the Loan Agreement was signed on October 22, 1980.6/ 14. By that time, the Borrower had entered into major contracts for engineering and supervision and for part of the materials and equipment.7/ Therefore the Government's options to cancel or even drastically restructure the project were constrained. Although the Bank had the option of reconsidering its involvement in the project, it chose not to do so for the following reasons: (a) the basic objective of the project (i.e., to help improve Tunisia's energy situation by substituting imported gas for petroleum derivatives and to introduce energy planning and pricing measures leading to a rational energy policy) remained unchanged; (b) the configuration of the distribution network was only partially altered; and (c) the Tunisians had relied on the previous Bank commitment in their contract discussions with certain suppliers of materials. STEG hoped to sign the first contracts in late February 1981 and would not wish to go 4/ Memo to Files, August 13, 1980, paras. 1-2. I/ Back-to-Office Report, October 2, 1980, paras. 1-4. 6/ The PCR (para. 4.05) should be read in the light of this chronology to avoid the mistaken impression that the Bank became aware of the Government's decision to revise the project after the signing of the Loan Agreement. 7/ The SAR (para. 2.21) estimates the value of contracts placed during the first five months of 1980 at US$24 million (27Z of the project cost). -5- back to its suppliers on this point.81 Subsequently, the scope of the Bank project was modified to suit the new objective of using royalty gas to replace premium fuels, instead of high-sulphur fuel oil as originally intended (PCR, para. 4,05). 15. The major changes in the project content were the addition of a branch line to Cap Don and the deferral of the pipeline to Gafsa. This resulted in relatively minor changes in the lengths of the branch lines, distribution mains and service connections. However, the number of consumer metering and regulating stations increased approximately eight- fold (PCR, paras. 4.06-4.07). Since the pipelines constructed under the project were to constitute an essential part of the country's future gas infrastructure, pipe diameters were left unchanged. 16. Given the uncertainty surrounding the value of royalty gas, the Bank reserved the right of not disbursing against the Sousse and Tadjerouine branch lines until the value of the royalty gas would be known, and the Bank would be satisfied that these lines would yield satisfactory rates of return.91 Due to the constrained implementation schedule and the need for awarding contracts for materials as well as mobilizing pipeline contractors in advance of the actual construction work, the above conditionality imposed immense pressure on both the Borrower and the Bank staff.10/ In a sense, this open-ended project definition was instrumental in the Bank's failure to have any significant impact on the physical aspects of the project. A case in point is the Kasserine-Tadjerouine pipeline which the Bank refused to finance because of its dubious economic viability. Nevertheless STEG went ahead and built it without using Bank financing (PCR, para. 4.10). Implementation Delays 17. The project was completed with a delay of about two years compared to appraisal estimates (PCR, para. 6.01 and Annex 6). This delay was due essentially to deferring the actual construction pending the finalization 81 Memorandum by Vice President, EMENA, to Senior Vice President, Operations, January 30, 1981, para. 3. 91 President's Memorandum, Secretary's No. R81-179, June 22, 1981, para. 9. 10/ As an example, the Bank agreed to the economic viability of the North Tunis distribution network and parts of the Sousse-Monastir gas distribution system on August 6, 1984, about ten months after the delivery of Algerian gas to Tunisia st%rted (Letter to STEG dated August 6, 1984. Despite this, the Bank was requesting a copy of the feasibility study for gas distribution in Sousse and Monastir as late as November 1985 (Telex to STEG, November 27, 1985, para. bbb). - 6 - of a new gas supply agreement between Algeria and Italy (PCR, paras. 2.02 and 2.06). The actual construction times for the major branch pipelines were comparable to appraisal estimates, which were realistic. Procurement and Disbursement 18. The original Loan Agreement dated October 22, 1980 (Schedule 4, Section A, para. 1) stipulated that all procurement under the loan would be through international competitive bidding (ICB). Although provision was made for the Bank to forego prior review of bidding documents, no clear criterion, such as contract amount, was given for this to happen (Loan Agreement, Schedule 4, Section C, para. 3). This omission remained uncorrected in the amended Loan Agreement dated July 15, 1981. 19. The ambiguity of the loan documents regarding prior review resulted in a certain amount of confusion between the Bank staff and the Borrower. The correspondence files are replete with examples of the Borrower informing the Bank of its decision to award important contracts before the Bank had formally reviewed and cleared bidding documents and contract award decisions as stipulated by the Loan Agreement.11/ However, expost reviews by the Bank staff confirmed that, with the exception of the contract for metering stations which the Bank refused to finance because of irregularities in procurement, all the contracts submitted to the Bank had been awarded in accordance with the Bank's Procurement Guidelines. 20. Disbursement of the loan started with a delay of 18 months and, despite the cancellation of part of the loan in September 1985, took six years instead of three years foreseen at appraisal (PCR, Annex 5). The initial delay was due to the late start of procurement and construction (PPAR, para. 17). Later lags in loan disbursement are explained by the delays which occurred in the implementation of the distribution and customer conversion components (PCR, Annex 7). The closing date of the loan was extended to December 31, 1986, and the loan account was kept open until December 31, 1987, on an exceptional basis, to enable payment for laboratory and maintenance equipment and spare parts.121 11/ Some of these cases are illustrated by STEG telexzs to the Bank dated December 9, 1980 (valves), March 13, 1985 (North Tunis engineering), July 2, 1985 (laboratory equipment), December 26, 1985 (extension of gas network), February 26, 1986 (materials for North Tunis), November 4, 1986 (valves), December 30, 1986 (conversion equipment); STEG letters to the Bank dated May 18, 1984 (conversion and pipe laying), April 10, 1986 (spare parts for conversion), April 23, 1986 (North Tunis, Monastir and Sousse pipe laying); and Bank telexes to STEG dated December 3, 1980 (line pipe), December 19, 1986 (burners), and February 19, 1987 (trucks). 12/ Telex to STEG, June 29, 1987. - 7 - 21. The Bank loan had an expected average loan life at the time of appraisal of 9.5 years. The average loan life is the sum until maturity of the loan balances outstanding at the end of each year divided by the loan amount. This indicator measures the number of years during which the entire loan proceeds lay effectively at the borrower's disposal. The faster the disbursements and the slower the repayments, the longer the availability of loan funds. In the case of Loan 1864-TUN, the delays in starting construction cut this availability to 6.6 years, and the exchange risk due to the currency-pooling system both realized on past repayments and accumulated until September 1989 cut it further to 5.1 years. This indicates that the actual terms of the Bank loan were not matching the requirements of the project which assumes a very long cash-flow generation horizon. In terms of Tunisian dinars, the Bank loan had an average life of only 3.4 years which underscores a significant refinancing problem in the currency of operations. Project Cost and Financing 22. The actual project cost compares with the appraisal estimates as follows (PCR, para. 5.01, and Table 2): Currency SAR Revised Actual US$ million 88.0 75.7 49.4 DT million 35.2 32.2 36.8 Thus, there is a cost underrun on the order of 44% in dollar terms, but, in terms of Tunisian Dinars (DT), there is a cost overrun of about 4%. 23. The PCR attributes cost savings in dollar terms to: (M) significant reductions in pipeline construction costs as a result of favorable terms obtained from international competitive bidding (ICB); (ii) substantial devaluation of the Tunisian Dinar vis-a-vis the U.S. dollar; and (iii) changes in project scope (PCR, paras. 5.01-5.03 and 11.03). Apparently ail of these factors affected the actual project cost. However, the audit would caution against imputing much meaning to the cost underrun in dollar terms because, first, during project implementation the U.S. dollar appreciated considerably vis-a-vis European currencies in which major contracts were denominated; and, second, important project elements, such as gas distribution facilities and conversion, were not clearly defined either in the SAR or the amended loan documents, thus precluding a meaningful comparison of estimated and actual costs (PCR, para. 6.02). 24. The original project financing plan included US$30 million of export credits and commercial borrowings representing approximately 33% of the estimated total financing required (PCR, paras. 9.12-9.14). At project completion STEG had used US$16 million of suppliers' credits and commercial borrowings, corresponding to about 31% of the actual project cost (PCR, para. 9.14). This is roughly comparable to original expectations. Due to the decrease in project costs, the Government's contribution was reduced - 8 - from US$25 million equivalent to US$9 million equivalent (PCR, para. 9.16). Upon the request of the Government and the Borrower, US$10 million of the Bank loan was cancelled in September 1985 (PCR, para. 5.06). Except for some limited advances repaid by the Government, STEG did not self-finance any portion of the investment although it is its main beneficiary. The Performance of the Borrower 25. The Bank has had a long standing involvement with STEG both in the power sector and in the financing of the El Borma-Gabes pipeline. During that period STEG had developed into one of the most important state economic enterprises in Tunisia, setting an example in efficiency and effective management. In the implementation of the Second Natural Gas Pipeline, STEG has given proof of its considerable project implementation capability. Nevertheless, the sudden change of the project's character in mid-course (PPAR, paras. 13-15), and the need to take a series of quick actions under conditions of uncertainty have imposed undue strain on STEG. Partly because of these pressures and partly because of its limited gas distribution experience, STEG failed to provide for a satisfactory gas market and network development plan and conversion program (PCR, para. 11.04(c)). This deficiency was one of the reasons for the sub-optimal utilization of the facilities built under the project (PCR, paras. 3.03-3.08; PPAR, para. 29). 26. The gas conversion initially lagged behind forecasts, but since the project was completed (1985) conversion targets have been better approached every year: 20% in 1985, 41Z in 1986, 88% in 1987, and 96% in 1988. Domestic conversion targets have always been over-achieved, mainly due to the conversion of all Tunis households completed in mid-1988, while commercial targets proved too ambitious. A sustained effort has yielded impressive results with hotels where all new projects are connected to gas. Results have been disappointing with industry because several large gas- consuming projects did not materialize. Since 1988, the effort has been refocussed on small and medium-size enterprises, but the campaign has met some resistance when owners realize that they have to pay for connections and conversion of their equipments. The Performance of the Bank 27. Throughout project implementation, the Bank staff maintained satisfactory working relationship with the Government and the Borrower. However, project supervision in the field was somewhat inadequate. Considering the number and importance of issues left unresolved at appraisal (PPAR, paras. 40-45), intervals of 11-16 months between supervision missions during the first two years were probably too long for the Bank to have a significant impact on project implementation. 28. The Bank's performance during project appraisal and subsequent amendment of the Loan Agreement left much to be desired. When the project was first appraised, it was at a very advanced stage of preparation. Pipeline route serveys and optimization studies had already been undertaken - 9 - by a foreign consultant, and most of the detailed design had been completed. Consultants were selected and contracts were signed for consultancy, engineering, and construction supervision services (SAR, paras. 2.13 and 2.15). Therefore, prospects for any significant impact by the Bank on the shaping of the project or on the implementing institution were rather slim. Nevertheless, the Bank could have pressed for coordinated action on the distribution and conversion aspects of the project, the installation of a dependable supervisory control and data acquisition system, and the adoption of national standards for gas distribution and utilization, when these aspects assumed a critical importance at the time the Loan Agreement was modified in 1981 (PCR, paras. 3.07, 6.02, and 7.04). This illustrates the difficulties inherent in restructuring a project in mid-course, especially when it includes major long lead time activities, and emphasizes the need for adeqiate project preparation and appraisal, including systematic risk/uncertainty analyses (PPAR, para. 50). III. PROJECT OUTCOME Operating Performance 29. The branch pipelines constructed under the project became operational toward the end of 1983 and early 1984 (PCR, para. 6.01). Gas delivery to Tunisia from the TMP started in November 1983 and built up to 911,000 tons of oil equivalent (TOE) in 1987. This is about 38Z of the appraisal estimate (PCR, paras. 2.05-2.07). The shortfall is due mainly to STEG's policy of not using gas when it is priced higher than the fuel oil, and the slow penetration of natural gas into the premium fuels market. So far, the imported gas has replaced mainly a portion of the fuel oil and only a modest portion of the premium fuels which it was intended to substitute (PCR, paras. 3.01-3.08). 30. The main user for gas was intended and still is STEG. The gas price charged to STEG is based on the market price of a basket of crude oils, thus generally reflecting the price of fuel oil on a heat equivalent basis. However, in the past there were instances of the gas price being higher than the landed cost of fuel oil (PCR, Annex 3, para. 11)." 31. Although STEG is in the process of implementing programs to increase the penetration of natural gas into the premium fuels market, the amount of premium fuels substituted by natural gas is expected to remain considerably below appraisal estimates, casting doubt on the quality of gas market studies on which the modified project was based (PCR, para. 3.05). - 10 - 32. Due to low imported gas consumption, the system capacity utilization vas about 301 in April 1988, indicating substantial overcapacity (PCR, para. 7.02). This excess capacity was unavoidable since pipeline diameters were left unchanged at the time the project was modified (PPAR, para. 17). It was thought then that any excess capacity would disappear if and when the already discovered domestic gas fields were developed. The sharp decline of the international petroleum prices and the expectation of low energy prices till the end of the current century make this a remote possibility. Therefore, barring any developments favoring higher gas consumption, such as a sudden jump in international petroleum prices or discovery of inexpensive domestic gas resources, the overcapacity is likely to persist in the medium term. 33. The mechanical performance of the pipeline system is in general satisfactory, with the exception of three measurement centers. It appears that the unsatisfactory performance of these centers is due to faulty design and construction, reflecting on the performance of STEG's engineering and supervision consultants (PCR, paras. 6.06-6.07). However, given the qualification and experience of these consultants, the audit tends to consider this shortcoming as one of those imperfections which creep into large construction projects implemented under time pressure. The PCR (para. 6.07) rightly argues that, due to their high-technology content, the measurement centers should have been packaged separately from the pipeline construction and handled directly by specialized contractors. The Borrower drew the same conclusion and has replaced all measurement units through separate procurement. Economic Reevaluation 34. The reevaluated economic rate of return (ERR) of the project is 141. This compares with 282 forecast for the original project (SAR, para. 5.08; and PCR, paras. 10.01-10.04 and Annex 8).13/ The decline in the project's ERR is due mainly to the higher-than-expected cost of the Algerian gas, small amounts of premium fuels substituted, and the low pipeline capacity utilization. Although substantially lower than the forecasts, the ERR is still acceptable for an infrastructure project. Financial Performance 35. At present STEG is the main user of the imported gas. It does not prepare separate cash accounts for its imported gas activities and does not revalue its assets on an annual basis. Therefore, a comparison of the project's financial rate of return (FRR) with appraisal estimates is of necessity conjectural. Nevertheless, diagnostic gas accounts prepared at 13/ As the feasibility of certain branch pipelines depended on the then unknown cost of the Algerian gas, no overall ERR for the amended project was calculated. It was estimated, however, that at a gas price of US$6 per MOBtu, the economic rates of return of individual branch lines would vary between 152 and 50% (President's Memorandum, Secretary's No. R81 179, June 22, 1981, para. 10). - 11 - the Bank's urging indicate that the project's FRR remains considerably below the covenanted 82 return on revalued assets (PCR, paras. 9.01-9.08). However, there appears to be a steady improvement, since the estimated financial return on STEG's northern gas activities increased from a negative 262 in 1984 to a positive 62 in 1987 in parallel to the improvement of the margin between the weighted average selling price and the purchase price of the Algerian gas (PCR, Annex 7). 36. Independently audited accounts for the gas activities during 1986 and 1987 are available for the Algerian Gas division which corresponds to the Northern Tunisia. Although this is short of the objective of having separate accounts for the entire gas operations, these accounts provide a reliable financial picture of the pipeline network financed with the Bank loan. In 1986, STEG's Algerian Gas division posted a net loss (US$3.6 million equivalent at the average exchange rate for 1986) although it was mostly not related directly to operations. For the first time after four years of losses, 1.7 showed a profit (US$2.2 million) for the same reason, mainly a decrease in provisions for exchange risk. Results related to operations were positive In both years, but by small amounts (US$0.8 million in 1986 and 0.2 million in 1987). The returns on sales of gas was poor: 5.1% in 1986 and 1.2Z in 1987. Cash flows from operations were substantial (US$3.5 million in both years), which allowed potential self- financing (before debt-service) of 68.12 of investment (excluding fixed assets revaluation) made in 1987. After debt-service, however, self- financing was reduced to 20.0%; exceptioAl, thus non-recurrent, gains lifted it to a respectable 58.62 in 1987. Financial expenses amounted to 15.4% of average long-term debts in 1987; together with scheduled principal repayments they consumed 1632 of operational cash flows or 992 of total cash flows. Under these conditions, financial sustainability of the project is threatened. Overall gas activities show a surplus, but it is mainly because the El Bormah gas consumed by STEG is costed at zero. In addition, no provision is set aside for the replacement cost of the dwindling field. Combined electricity and gas operations are loss-making and the trend has worsened in 1988. Losses amounted to US$54.8 million on sales of US$277.5 million (or 19.72). Accounts receivable totalled US$36.4 million, or over 1.5 months of sales. The current ratio was lower than 0.5 and debt service in principal scheduled for 1989 was greater than cash flows, which both raised a solvency issue. TV. FINDINGS AND ISSUES Overall Assessment 37. The project has achieved its primary objective of installing a gas distribution infrastructure in Northern Tunisia where most of the country's population lives. Although less than expected, imported nadfral gas has made significant inroads into Tunisia's premium fuels market (PCR, para. 7.04). With the exception of ensuring separately the financial viability of STEG's purchased gas and power activities, the institutional objectives - 12 - of the project were also attained through training and consultancy services (PCR, par4s. 6.08. 8.05 and 9.06). The project's main policy objective of rationalizing domestic petroleum product prices was achieved to a large extent, both as a result of the gradual increase in domestic prices and the collapse of international oil prices after 1986 (PCR, para. 3.13, Annex 3, paras. 13-15). Given these achievements, the audit considers the project successful. Project Desian and Preparation 38. Despite adversities in project implementation and unexpected developments in international commercial relations (PPAR, paras. 13-16), the project still has an ERR slightly above the opportunity cost of capital in Tunisia. This can be taken as a proof of the soundness of the basic project concept. Notwithstanding this, it is clear that the project was not prepared to standards adequate for a Bank project. The timing of the project was certainly less than optimal. 39. The PCR (para. 11.01) notes that the project was related to one of the largest international gas projects (the Trans-Mediterranean Pipeline), with all the complexities which are inherent to such projects, such as long lead planning time, heavy front end investment, long-term contractual arrangements, as well as pricing issues. These complexities should have normally deterred both the Borrower and the Bank from rushing the project. However, this was not the case. The Borrower and the Bank committed themselves to the project before uncertainties surrounding the size of the potential gas market, the volume and the price of the Algerian gas, and the domestic gas development plans were clarified. 40. Gas Market. The abundant supply of hydrocarbons over the 1970s and the lack of alternative energy sources had led to a limited Government role in energy planning and coordination (Pr-jsident's Report, para. 31). The Energy Department of the Ministry of Energy and Mines had only recently been reorganized to handle long-term energy planning and the study and review of the economic, financial, and legal aspects of alternative energy development plans (SAR, para. 1.28). The energy master plan for Tunisia under preparation by a foreign consultant was not expected to be ready before the end of 1980, about one year later than the start of the project appraisal (PPAR, para. 8).141 Feasibility studies for the supply of gas to 141 This study had a curious fate. Due to inadequate input data and the poor performance of the consultant, the completion of the study was delayed. Before the work was completed the consultant declared bankruptcy. The study was, however, continued by another consultant which prepared a preliminary report of a very poor quality. The Government rejected the conclusions of this report, and all efforts to complete this study were abandoned (PCR - Tunisia: Second Power Project (Loan No. 1355-TUN), April 22, 1983, IBRD Report No. 4456, para. 7.4). - 13 - households and small scale industrial consumers in selected areas of Tunisia were to be done under the project (Loan Agreement, Schedule 2, Part C, para. 1). As a result, the SAR contained only limited information on the potential gas market to be served by the project, and this was based mostly on the assumptions that the natural gas would replace fuel oil used in the power sector and in certain industries (PCR, para. 3.01 and Footnote 1). The project's failure to meet demand targets forecasted at appraisal is to some extent a presentational problem. This evaluation ascertained that the 2.4 million TOE target was for the whole country after completing the second phase of investments. Given that only the first phase supported by the Bank loan has been implemented, a pro rata target is more appropriate to evaluate the accuracy of the market studies used to recommend the project. 41. Volume and Price of Algerian Gas. The economic viability of the project depended on the provisions of three international agreements governing the volume and the price of the Algerian gas to be supplied to Tunisia. These were the Algeria-Tunisia gas supply contract, still under negotiation at the time of appraisal, the Algeria-Italy gas supply agreement, which would be renegotiated soon after Board presentation, and the Tunisia-Italy common carrier and royalty agreement. The Bank needed these contracts to ascertain, among other things, (a) the security of gas supply, on which the whole project hinged, (b) the basis on which the price of the Algerian gas would be established and adjusted, which was a critical element for the economic and financial aspects of the project, and (c) the exact amount of gas to be made available to Tunisia 3n terms of royalties and purchases, and the nature of transit rights and obligations of Tunisia. 42. Throughout the appraisal of the project, the Tunisian authorities refused to give the Bank copies of these contracts on grounds of confidentiality.151 Nevertheless, the Bank proceeded with the processing of the loan without an in-depth examination of the relevant international contracts.16/ Instead, it was agreed that the Tunisian authorities would confirm that the SAR reflected the substance of the supply contracts, and that the Tunisian legal opinion to be subsequently submitted would certify that the contracts were effective and binding (PCR, para. 3.10 and Annex 3, para. 5). 43. In the absence of exact gas price data, the Bank based project appraisal on the optimistic assumption that the Algerian gas would cost 60-70Z of the international fuel oil price (PCR, para. 3.09). This 151 Project Brief and Issues Paper, November 9, 1979, para. 3.17. 161 Before starting negotiations, the Tunisian delegation allowed the Bank staff to review the contracts in their presence, but not to keep copies (Memorandum to Vice President, EMENA, April 30, 1980, para. 2). The royalty agreement between Tunisia and Italy was finally given to the Bank in October 1980 on condition that its contents be kept secret (Back-to-Office Memorandum dated October 17, 1980). - 14 - optimism was proven to be unwarranted soon after the Board presentation of the project (PCR, Annex 3, para. 7). In retrospect, the audit finds it difficult to justify the appraisal mission's optimism on natural gas price, since the Bank was well aware of the Algerian Government's declaration of narrowing, over time, the gap between the gas price at the border and the international fuel oil price.17/ 44. Despite the uncertainty regarding the cost of the Algerian gas supplies, no sensitivity analyses showing the price ranges within which importing gas and exporting domestic fuel oil would be advantageous were given. The only information that can be obtained from the SAR in this respect is that, "should the gas purchase contracts be renegotiated such that the only saving was the differential between transmission costs to Italy and Tunisia (which is seen as the minimm benefit in the long-term), the project's rate of return would be 28Z.' The fact that the project failed to achieve even this predicted minimum (PPAR, para. 34) underlines the urgency for the Bank to refine its risk assessment techniques, as suggested in past Annual Reviews of Project Performance Results.18/ 45. Development of Domestic Gas Resources. The project was designed to accommodate also the development of domestic gas resources in the future (PPAR, para. 7), but no firm gas development plans were at hand at the time of project appraisal. The only certainty was the Government's decision to defer for an unspecified length of tine the development of the offshore Miskar gas field for "both strategic and economic considerations (President's Report, para. 24).0 Thus, future domestic gas development plans and the project's relevance to them were not to be known until the completion of the previously mentioned energy master plan.19/ 46. As the previous discussion shows, the project was prepared under considerable time pressure, because it was accepted a priori that the timing of the pipeline construction had to fit with the commissioning of the TMP expected to take place in late 1981.20/ This is rather difficult to explain since the gas purchase contract between Tunisia and Algeria had not been finalized, and Tunisia had the option of taking the royalty in cash. Due to the prevalence of long lead time activities, such as pipe manufacturing, contractor mobilization, etc., little time was available for adequate consideration of all critical project issues. The PCR (para. 11.04(a)) concludes that the implementation of the project should have been delayed until agreement was reached on gas pricing. The audit agrees with 17/ Project Brief and Issues Paper, November 9, 1979, para. 2.05. 18/ See, for example, Annual Review of Project Performance Results 1986, October 19, 1987, IBRD Report No. 6976, paras. 1.46-1.48. 19/ Back-to-Office Report, October 2, 1980, para. 9. 20/ Project Brief and Issues Paper, November 9, 1979, para. 3.20. . 15 - this view, since the proposed approach would have eliminated the need for ad hoc changes in project scope and design after Board presentation, and have prevented idle investment for about one year. This experience illustrates the need for a clear basis for project evaluation and planning (PPAR, para. SO). 47. The Bank has later incorporated the lessons of its experience under the project into its Guidelines for Petroleum Lending.11/ The Bank now requires long-term salesipurchase contracts as a pre-condition for presenting a loan for the construction of gas using facilities to its Board of Executive Directors, except when firm preliminary commitment from the producer and purchaser is cesidered satisfactory. In this latter case, the execution of a satisfactory sales/purchase contract becomes a condition of loan effectiveness. If the OMS 3.82 were In force at the time this project was prepared, it is highly likely that many of the surprises encountered during project implementation would have been avoided. Sustainability 48. Despite unfavorable circumstances, such as long implementation delays, underutilization of the facilities built, and slow entry of gas into the premium fuels market, the project shows an acceptable ERR (PPAR, para. 31). This economic benefit is derived from the difference between the cost of the Algerian gas and the landed cost of the fuels it replaces. Since the contract price of the imported gas is tied to crude oil prices and the prices of the petroleum products is a function of international crude oil prices, the future economic benefits of the project should remain at least at their current levels. Moreover, STEG has already developed the technical skills required for a gas distribution concern (PCR, paras. 8.02-8.05), and satisfactory national standards for gas distribution and utilization are either in force or under preparation (PCR, para. 7.04). The audit, therefore, considers the sustainability of the project benefits assured at the technical level. Lessons of Experience 49. No detailed gas market development and customer conversion programs were provided in either the orivinal project or the amended project (PPAR, para. 28). As a result, the major portion of the imported gas is still being used to replace fuel oil, instead of premium fuels, to the detriment of the project's ERR (PPAR, paras. 27-31). This experience reinforces the following lesson drawn from previously reviewed natural gas transmission and distribution projects.221 211 Operational Manual Statement (OMS) No. 3.82, November 1984, para. 44. 22) See PPAR - Egypt: Cairo Gas Distribution Proiect (Credit 1024-EGT), June 24, 1987, IBRD Report No. 6860, para. 30; and PPAR - Bangladesh: Bakhrabad Gas Development Project (Credit 1091-BD), October 14, 1987, IBRD Report No. 6975, para. 44. - 16 - Because of heavy front-end investment requirements for gas distribution systems, it is particularly important to build up sales rapidly in the early years. Therefore, related activities that are critical to the achievement of this goal, such as market development and conversion of customers' equipment, should be carefully planned, and provisions made for their timely implementation. 50. The project experience also shows the difficulties inherent in changing in mid-course the scope of a project involving activities with long lead times, such as pipeline construction. When the gas price assumptions made at appraisal did not materialize, and the objective and scope of the project had to be modified, the Bank could only check to see if certain project elements were still economically viable, without ascertaining their optimality. Under time pressure, several elements critical to the success of the modified project were overlooked (PPAR, para. 28). The following lesson, which may also apply to other infrastructure projects with long lead times, emerges from the project experience: In preparing projects with long lead time activities, every effort should be made to ascertain all the factors which are critical to successful project performance. In case some of these cannot be sufficiently ascertained before committing to a project, advanced risk/uncertainty analysis techniques should be utilized to better account for uncertainties in the planning environment and their potential impact on the project. 51. On financial grounds, the pipeline project financed by the Bank loan has failed to strengthen STEG yet. The refusal by STEG up to this day to disclose unconsolidated financial results for its gas and electricity activities has prevented a full assessment of the financial viability of gas operations. With its full share if debt service and a provision for the replacement cost of the El Bormah field, gas is in recurrent deficit (PPAR, para. 36). The following lesson, which may apply to other infrastructure projects which require large debt financing, can be suggested: In preparing capital-intensive projects with corresponding large debt financing, special attention should be paid to the financial prerequisite to sustainability. If it can be anticipated that the project will not be able to generate enough cash flows to, concomitantly, cover the debt service (including foreign exchange losses) and finance depreciations, measures should be scheduled in advance to assist the borrower in meeting its obligations (e.g., recapitalization, refinancing of debts, insurance for the exchange risk, tariff increase, sale of some assets). - 17 - PROJECT COMPLETION REPORT TUNISIA SECOND NATURAL GAS PIPELINE PROJECT (LOAN 1864-5-TUN) November 3, 1988 Industry and Energy Division Technical Department Europe, Middle East & North Africa Regional Office - 19 - TUNISIA Second Natural Gas Pipeline Project (Loan 1864-5 TUN) Project Completion Report I. THE SECTOR AND BANK ROLE 1.01 The El Bormah field, in southwest Tunisia, accounts for most of the domestic production of natural gas, all in the form of associated gas. The gas is used for the most part for power generation, but also for a number of industries in the vicinity of Gabes (see map IBRD 14849R1). In the northern part of the country, gas became available only in the early 1980's, with the completion of the Trans-Mediterranean Pipeline (TMP), a major multinational undertaking involving gas exports from Algeria to Italy which not only entitles Tunisia to royalties (for the rights of passage) but also gives Tunisia the option to buy gas under separate arrangements. The Project was designed to enable Tunisia to take advantage of these new opportunities by developing the infrastructure required to transport and distribute the gas domestically, and by acquiring the equipment required to convert major plants to natural gas. 1.02 While this Project was designed to use imported gas, it also took into account the impact, at a future date, of the development of the offshore Miskar gas field, the largest undeveloped hydrocarbon field in Tunisia with reserves of about 60 billion m3. Consideration had already been given as early as the mid-1970's to develop that field, and the Project was reexamined at various times until the mid-1980's, but its economics were found marginal at best. The collapse of oil prices of 1986 could postpone the development of Miskar further, although an international oil company has recently indicated tentative interest in developing the field. 1.03 The Bank has been active in Tunisia's gas sector since the early 1970's when it made a US$7.5 million loanto finance the gas pipeline from the El Bormah field to Gabes. In the late 1970's, the Bank encouraged the Government to consider gas supply options other than Miskar when the cost of developing that field became excessive. This ultimately resulted in the decision to develop the market for gas in northern Tunisia on the basis of imported gas, in retrospect a wise decision, which led to the present Project. 1.04 The gas sector in Tunisia is closely intertwined with the power sector, since most of the gas is used for power generation, and the power utility Societe Tunisienne de l'Electricite et du Gaz (STEG) is also in charge of the acquisition, transport and distribution of natural gas. In addition to 1/ Loan 724-TUN of Feb. 1971. Project Performance Audit Report No. 1078 of March 12, 1976. - 20 - two loans for gas transport and distribution, the Bank has made three loans to STEG for electricity generation, transmission and distribution.1' II. THE TRANS-MEDITERRANEAN PIPELINE AND GAS AVAILABILITY A. The Tran,;-Mediterranean Pipeline 2.01 The Hassi R'Mel gas field in Algeria, discovered in 1956, remains one of the largest gas fields in the world. This field is the source of gas for a number of ongoing major international liquefied natural gas (LNG) or pipeline gas projects including the TMP. 2.02 A memorandum of agreement signed betwean Algeria and Italy in 1973 provided for 25 years export of natural gas from Hassi R'Mel to Italy. The agreement was contingent upon technical feasibility of a state-of-the-art deep undersea pipeline crossing the Sicily Channel and Straits of Messina at depths of 550 m. and 350 m., respectively. The technical feasibility which included short pipe laying tests, was completed in 1974 and showed that the deep undersea crossings were feasible. This led to tri-country agreements in 1977 among SNAM (ENI Group of Italy), Sonatrach (Algeria) and the Tunisian Government for the export of 12 billion cubic meters (M3) of Algerian natural gas per year to Italy plus delivery of about 600 million m3 royalty gas per year to Tunisia in the plateau periods . Delivery was to begin in 1981, reaching full capacity at the end of 1984. As a result of the oil price upheaval in the early 1980's, gas pricing became a contentious issue between Italy -and Algeria. Consequently, it took two years to reach a new agreement on gas prices, with a corresponding delay in gas deliveries. 2.03 The TMP from Hassi R'Mel in Algeria to Minirbio in Italy is about 2,500 km long of which 550 km is in Algeria, 370 km in Tunisia, 160 km in the Sicily Channel and 1,420 km in Italy. The pipeline is 48" in Algeria, Tunisia, Sicily and the greater part of its route through Italy, while decreasing gradually on the last section connecting it to the Northern Italian network. The Sicily Channel has three 20" subsea lines plus a 20" spare, the Messina Straits have three 20" lines and a 10" spare. The transmission system includes 8 compressor stations with a total installed horsepower of 425 MW of which three stations, including the 120 MW Cap Bon station, are installed in Tunisia. The pipeline design allows for adding compressor stations in order to increase the capacity to about 18 billion m3 per year. Although construction of the pipeline progressed as planned with commissioning scheduled in October 1981, because of the protracted renegotiations primarily aimed at price adjustment, delivery of gas started in August 1983 and the 1/ Loan 815-TUN of March 19, 1972, Loan 1355-TUN of December 23, 1976, Loan 2003-TUN of May 26, 1981, and Loan 2455-TUN of June 27, 1984. Project Performance Audit Reports have been issued for the first three (Report 2521 of May 24, 1979, Report 4456 of April 22, 1983 and Report 7326 of June 23, 1988). In general, they concluded that project implementation was satisfactory, but that, on the other hand, the financial and economic objectives of Bank lending had not been attained fully. - 21 - total delivery to Italy in that year was only about 2 billion M3. By 1987,however, gas delivery through the pipeline had increased to about 11 billion m3. 2.04 Sonatrach was responsible for the building of the Algerian section of the gas pipeline (550 km. of 48"). In Tunisia, SNAM was responsible, through its wholly-owned Tunisian subsidiary, Scogat, for the building of 370 km. of 48" pipeline and the construction of three compressor stations. The crossing of the Sicily Channel was carried out by a company jointly-owned by SNAM and Sonatrach and the Italian section of the pipeline, including the crossing of the Straits of Messina, was built by SNAM. B. Gas Availability 2.05 The SAR reflects the original agreement among the three parties according to which supply of gas to Tunisia was to start in October 1981, simultaneously with the beginning of regular supplies to Italy which was to increase gradually from about 800 million m3 (equivalent to about 800,000 TOE) in 1982 to 2,400 million m3 in 1987. 2.06 As a result of the delay in the commissioning of the TMP, the ongoing bidding process for the construction of the spurlines in Tunisia was delayed from June 1980 to March 1982. Actual gas delivery to Tunisia started in November 1983 with only 6 million m3 of royalty gas delivered in that year. The Tunisian entitlement for royalty gas is 5.25% up to 12,000 million M3 of the gas leaving Tunisia and 6% for the quantities in excess. 2.07 A contract was signed between Tunisia and Algeria in January 1984 for additional annual delivery of 100,000 TOE increasing to 300,000 TOE (contracted gas) within three fiscal years starting from October 1, 1984. A second contract signed in December 1986 stipulated the annual deliveries for the following three calendar years. These deliveries were: Year MTOE 1987 150 1988 200 1989 250 In addition, the same contract gave the right to Tunisia to request from time to time, gas in addition to the contracted quantities (excess gas). The actual gas delivered to Tunisia increased from 380,000 TOE in 1984 to 911,000 TOE in 1987. This compares with SAR estimates of 835,000 TOE in 1982, increasing to 1,145,000 TOE in 1984 and 2,400,000 TOE in 1987, respectively. Table 1 compares the actual royalty gai and contracted gas deliveries with the SAR estimates. . 22 - Table 1. GAS SUPPLY TO TUNISIA FROM TRANS-MEDITERRANEAN PIPELINE Actual vs SAR Estimatg (Thousand Tons of Oil Equivalent) 1982 ZRal 1 18 1985 -198 _JUZ aa AuUal IM Actual 9 &Aa M Acnal a& AcItal fM Actual Rnvaty Gas (i) Entitlement - - - 114 - 352 - 460 - 436 - 579 (ii) Delivery 200 - 370 6 k/ 52S 254 620 408 800 142 800 311 Contracted Gas (Mii) Contract Qty. - - - - - 100 - 250 - 300 C/ - 150 (iv) Delivery 635 - 490 - 620 100 1,175 237 1.200 195 1.200 150 (v) Excess Gas - - - - - 26 - - 400 - 400 450 4/ Total Actual Deli- very (ii)+(iv)+(v) 835 - 860 6 1.145 380 1,795 678 2.400 337 2,400 911 A/ Gas delivery to Tunisia started in November 1983 (para 2.06). h/ Includes the line pack, about 2.7 TOE. c/ This quantity includes deliveries for three additional months (October. November and December) for transition from fiscal year to calendar year. d/ Of this quantity, about 120 KTOE was a gift from Algeria to Tunisia. - 23 - III. GAS DEMAND AND PRICING A. Gas Demand 3.01 When the project was appraised, expectations were that gas would essentially replace fuel oil in the power sector and in certain industries-'. Therefore, fuel oil consumption was forecast to decrease from an estimated 1,040 thousand TOE (44% of the total consumption of petroleum products) in 1980 to 155 thousand tons (less than 8% of total consumption of petroleum products) in 1987, with imported gas amounting that year to 2,400 thousand TOE'. In other words, gas was expected to replace 85% of the fuel oil consumed in 1980, and meet the full demand growth in the 1980-87 period (limited substitution was anticipated since the consumption of diesel oil was forecast to increase by 5-6% per annum over 1980-87, and that of LPG by 10% per annum during the same period). 3.02 As a result of the significant increase in the price of Algerian gas, the Project was restructured during 1980-81 and targeted to the premium fuels substitution market, instead of the fuel oil market. The potential market was estimated at 300 thousand TOE annuallyl'; it was also envisaged to replace fuel oil in the power plant at Sousse, up to 500 thousand TOE annually, subject to the prices in effect. Annex 1 shows the actual 1980-87 demand for petroleum products, and indicates that: (a) while demand for hydrocarbon over the period 1980-87 grew on average by 4% per annum, demand for gas increased by 17% per annum (essentially because of the introduction of northern gas), and fuel oil demand declined on average by 4% annually; (b) the combined share of gas and fuel oil increased from 48% in 1980 to 52% in 1987; and (c) demand for northern gas varied considerably from one year to the next, because of its price in relation to that of fuel oil. 1/ The Appraisal Report contains limited information on the potential market for natural gas, which could be attributed to the lack of domestic experience in energy forecasting (para. 1.17). This was expected to be remedied with the help of the consultants. 2/ Source: SAR, Annex 1.01. It was further assumed that Tunisia would not be in a position to take all the royalty gas available to it in kind, and that 400 thousand tons would be taken in the form of cash. Of course, the quantity of royalty gas available to Tunisia depends on the pipeline throughput over which Tunisia has no control. 3/ President's Memorandum of June 22, 1981 (para 4). - 24 -. 3.03 Therefore, northern gas has mainly taken up a portion of the fuel oil market, and only a modest share of the market for premium fuels, its priority target from an economic standpoint. 3.04 A breakdown of northern gas sales appears at Annex 2, and can be summarized as follows: Gas Market (Thousand TOE) Growth Rate (Z) Target 1984 1987 1984-87 1991 1. Prime Fuels Replacement Domestic Consumption 18 28 14% 41 Hotels 0 18 n.a. 25 Miscellaneous 1 11 n.a 16 Subtotal 19 57 32 82 Add: STEG Gas Turbines 169 89 -19% - a/ Total Premium Fuels 188 146 -8% 82 2. Fuel Oil Replacement Heavy Industries 33 61 24% 155 Add: STEG Steam Plants 157 688 63% - a/ Total Fuel Oil Rep. 190 749 58% 155 Total Sales 379 894 33% Source: STEG, Gas Directorate, May 1988 a/ STEG expects to use between 200 thousand TOE And 1,120 thousand TOE by 1991 depending on the price of imported gas in r4lation to fuel oil. 3.05 The premium fuels replacement market (mostly domestic, hotels, small industries and crafts) has increased from 19 thousand TOE in 1984 to 57 thousand TOE in 1987. It is increasing fast, but on the other hand started from a low base. Considering that this market segment includes the Tunis town gas (27,000 connections) for which the distribution network was already in place, results have been less than impressive. By 1991 (last year of the Seventh National Development Plan), the target of 82 thousand TOE appears particularly low considering that in 1981 expectations were for a potential premium fuel market of 300 thousand TOE (no target year was mentioned). - 25 - 3.06 Regarding fuel oil replacement, STEG has connected a number of cement plants and other major industries. Another important cement plant is expected to be supplied starting in 1988 so that the consumption in this industrial activity is anticipated to increase significantly in the coming years. 3.07 For power generation, one has to make a distinction between the gas turbines and steam units. Regarding the former, their consumption is dictated by economic considerations, and certainly does not represent a significant market for imported gas in the long term unless they are converted to combined cycle. Regarding steam units, STEG is aware of the necessity to monitor continuously the prices of gas and fuel oil in order to ensure that they use the fuel that is cheapest to the economy; this explains wide annual variations in the consumption of gas in STEG's steam units.-' In order to better optimize load dispatch, STEG is now considering the acquisition of a modern Supervisory Control and Data Acquisition system (SCADA) that will enable it to switch fuels more rapidly and efficiently than in the past. 3.08 In conclusion, the growth of the premium fuels market has been much slower than anticipated in 1981, with power generation accounting for most of the utilization of northern gas. This situation is likely to continue in the foreseeable future. Supervision missions, particularly following the beginning of the conversion activity, urged STEG to initiate appropriate promotional efforts. STEG's Gas Directorate is presently strengthening its capability in the areas of market surveys and prefeasibility studies which may improve the future situation. B. Price of Imported Gas 3.09 The price of imported gas had a considerable impact on the project's design, implementation and economic rate of return, as well as the formulation of most covenants. Throughout project preparation and appraisal, it was thought that the price of imported gas would be highly attractive, i.e., 60-70% of the international price of fuel oil. In view of the importance of gas pricing, its evolution during the implementation of the Project is reviewed in detail in Annex 3. Tunisia is, through a contract with Italy, entitled to royalty gas (para 2.05); part or all of royalty gas could be taken in kind or cash at the contract price of gas to Italy. In addition, under a take-or-pay contract with Algeria, Tunisia is committed to buy certain quantities of gas (para 2.07), at a price linked to a basket of 8 crudes which changes every quarter. 3.10 Throughout the appraisal process, the Bank, with considerable reluctance, decided to accept Tunisia's position to proceed with the Project without examining formally the gas supply contracts on confidentiality grounds, and, instead, received a confirmation that the Staff Appraisal Report reflect the substance of the supply contracts, and made the submission of a Tunisian legal opinion certifying that the contracts are in effect, a condition of effectiveness of the Loan. However, the Bank was informed 1/ Monthly data given to the mission indicate that gas was also used in steam units during 1986, and the last two months of 1987 when that option was clearly uneconomic. However, STEG was forced to this decision because test runs were conducted at the new power station at Rades and because the availability of other power plants was low. - 26 - shortly after Board Presentation (June 1980) of a possible substantial increase in the price of Algerian gas and the Project had to be redesigned for the premium fuels market. Tunisia was also to forego the option of purchasing gas from Algeria and only use its royalty gas for the premium market when economically justified. The amended Project was approved by the Board on a no-objection basis in July 1981. 3.11 Since the price of gas was still uncertain at the time the loan was amended, the justification of certain Project components was in doubt.Analyses made at the time indicated that three pipelines were justified,", but for two, the submission of satisfactory evidence on their economic viability was made a condition of disbursements. This approach seems to have been appropriate under the circumstances. 3.12 Data presently available suggest that Algerian gas was, with the exception of the first quarter of 1986 (when prices declined rapidly), more attractive on a calorific eqvivalent basis than LPG, naphtha or diesel oil. But, this was not the case for fuel oil substitution particularly in 1982, 1986, and early 1988 (out of 25 quarters, fuel oil was a more attractive source of heat than natural gas during 9, or 36% of the time). The Bank's concern with pricing in general and the gas contracts in particular was undoubtedly justified. C. Domestic Prices 3.13 At appraisal, domestic prices of petroleum products to be replaced by natural gas were considerably below border prices so that imported gas could only be sold domestically if correspondingly subsidized. As a result, agreements were reached during negotiations (April 1980) whereby: (i) the price charged by the Government to STEG for royalty gas would be gradually raised to reach full import parity by the end of 1986 (Section 3.03 of initial Guarantee Agreement); and (ii) the domestic price of fuel oil would be at least equivalent to that of natural gas. These two covenants together ensured, from the Bank's standpoint, that the price of fuel oil would reach import parity by early 1987. When the loan was first amended (July 1981), these agreements were replaced by new covenants providing for gradual increases in the prices paid by STEG for royalty gas to reach international levels by early 1987, and increases to international levels in the prices of oil products gas was intended to replace, to be reached by the same target date. Calculations made by the mission indicate that: () in 1987, STEG paid on average a higher price for royalty gas than the border price of purchased gas; and (ii) as a result of both the gradual increases in domestic prices, and the collapse of international oil prices in 1986, domestic prices are now above import parity for all products; for instance, the price of fuel oil was 18% above import parity in early 1987 and 55% in early 1988. All in all, considering the pricing policies in effect when the loan was approved (the price of fuel oil was about 33% of its opportunity cost), considerable progress was achieved in restructuring petroleum products prices with a view to stop their subsidization. 3.14 Progress was also achieved in introducing a gas tariff in June 1987 (Annex 3, Appendix 2)-until then, the structure of gas tariffs was informal. 1/ Subject to the installation of a gas turbine in one location (Kasserine). - 27 - An important outstanding issue, however, is the tariff being charged for gas used for power generation. In the South, STEG acquires considerable albeit declining quantities of gas from the El Bormah field (about 260,000 TOE in 1987) at virtually no cost; the appraisal mission was aware of the issue but consciously decided not to raise it since El Bormah's gas production was anticipated to cease in 1986 (SAR, para 4.10). With the slower depletion of the reserves, El Bormah gas production is now expected to remain above 100,000 TOE until 1994. There are, therefore, valid grounds for concern that southern gas will be used to subsidize the power sector. IV. PROJECT PREPARATION AND APPRAISAL A. Project Origin 4.01 The possibility of importing gas from Algeria has been an issue sincethe conclusion of the Algeria/Italy gas supply contract in 1973 and the corresponding transit agreement for a pipeline from Algeria across Tunisia to Italy. In 1974, the Miskar structure was discovered. During appraisal of the Miskar project in 1977, the Bank suggested investigation of purchasing gas from Algeria as an alternative to investing US$600 million in a single gas field. On this basis the Second Natural Gas Pipeline Project was prepared. A Bank appraisal mission in 1979 concluded that investment in the onshore gas pipeline project was feasible, and project implementation was formulated. However, as mentioned in para 2.02, the agreement between Italy and Algeria was renegotiated in response to the oil price upheaval in 1980-81. As a result, project implementation was delayed for about two years. B. Project Description 4.02 The SAR describes the project under which the Bank considered financing, among other things, the construction of four pipelines (spurlines) tapping the TMP and delivering gas to Tunis, Sousse, Gafsa and Tadjerouine. 4.03 The project was described as follows: (a) a 70-km 20" spurline heading north to Tunis; (b) a 70-km 20" spurline heading south to Sousse; (c) a 60-km 18" spurline to Gafsa; (d) a 90-km 8" spurline to Kasserine and Tadjerouine; (e) 170-km of laterals (distribution mains and service connections connecting the spurlines to consumers; () cathodic protections, block valves, scrapes, trays for the pipelines; (g) three injection terminals (measurement centers) at the offtake points; (h) conversion of customers' oil-using plants to dual firing (oil and gas); (i) consultancy services for both project engineering and feasibility studies; and (j) training both in Tunisia and abroad. 4.04 The project did not provide a well-defined description for distribution (item (e)) and a well-defined program for the conversion component. These two items are particularly important for market development and penetration of gas in the premium market which was an essential objective - 28 - of this project. The distribution component should have defined explicitly the system by which gas could be transmitted from the spurlines to the consumer gates, and the conversion component should have indicated explicitly the type and number of consumers to be converted in each year, i.e., a well-defined conversion program. Experience shows that lack of detailed planning for conversion has always caused significant delay in market development, despite timely completion of the main project components such as transmission and distribution networks. In view of the above and the two years delay in project implementation (para 2.02), the project scope and conditionalities went through a number of changes. These are discussed below. C. Changes in Project Scope 4.05 The Loan Agreement was signed in October 1980. In 1981, the Government informed the Bank that renegotiation of the agreement between Algeria and Italy remained inconclusive. To avoid further delays, the Government wished to modify the project to rely on royalty gas alone, substituting premium fuels such as gas oil, liquefied petroleum gas (LPG) and naphtha (reformed for production of town gas for the city of Tunis), rather than primarily replacing high-sulphur, heavy fuel oil as originally envisaged. 4.06 The modification to the original project added a spur line to Cap Bon for replacing premium fuels used by commercial consumers, particularly hotels in the area, while deleting the pipeline to Gafsa which was intended to replace non-premium fuels. This change increased the total estimated length of the spurlines from about 290 km to 300 km, while the total length of lateral pipes (distribution mains and service connections) decreased from about 170 km to 90 km. Due to the increase in the number of prospective consumers, most of which used less gas than under the original project, the number of consumer metering and regulating stations increased from 18 to 150. 4.07 As a result, the Project scope was ultimately as follows: (a) Tunis, Cap Bon and Kasserine, spurlines including conversion and studies; (b) Tadjerouine spurline; and (c) Sousse spurline. 4.08 Disbursement against the portion for Kasserine was made subject to the condition of installing the gas turbine, and for the Sousse and Tadjerouine portions, the condition of disbursement was made subject to their economic viability being satisfactory to the Bank. 4.09 Since the wording of the project description in the Loan Agreement was not clear on the distribution component, which resulted in the Bank putting disbursements on hold, a second amendment was agreed between the Bank and the Borrower in July 1984 under which: (a) clarifications were given for financing the distribution system including the installation of gas customers' connection, carcassing and the conversion of appliance/burners; and (b) financing of the Kasserine-Tadjerouine pipeline and a distribution system in Sousse/Monastir was subjected to an economic justification satisfactory to the Bank. - 29 4.10 Upon review of the economic merits of the Kasserine-Tadjerouine pipeline, the Bank decided that construction of this pipeline was not economically justified, and no disbursement was made for this component. However, the government financed this component from other sources. 4.11 The project as completed now consists of four gas systems which include three measurement centers at the off-take points of the TMP, four high pressure spurlines, distribution mains and service lines for supply of gas to 5 power plants, 6 industrial plants, and about 35,000 commercial and residential consumers. The four gas systems are: (i) Tunis, (ii) Sousse, (iii) Cap Bon and (iv) Kasserine-Tadjerouine. These four systems are described in detail in Annex 4 and are shown on Map No. 14849R1. V. PROJECT IMPLEMENTATION A. Project Cost 5.01 The actual total project cost was US$49.4 million against the appraipal and loan amendment estimates of US$88.00 million and US$75.7 millior-, respectively. Table 2 gives a comparison of the estimated and actual costs of the project itemized by major items. 5.02 The above project cost comparison is based on the completion of the four gas systems (para 4.11) and consumer conversions as of end-1987. The SAR does not explicitly quantify the conversion component which is an ongoing activity. 5.03 The project was completed with a 44% underrun in dollar terms which is due mainly to: (a) significant reductions in pipelaying cost as a result of favorable terms obtained from the ICB procurement-the actual cost was US$15.7 million compared with US$41.7 million (including contingencies), in the SAR estimates; (b) substantial devaluation of the Tunisian currency vis-a-vis the US dollar--one dinar which was equivalent to 2.5 dollars at the tisee of the project appraisal has now decreased to 1.24 dollars; and (c) marginal changes in the project scope (paras 4.05 through 4.11). B. Procurement and Disbursement 5.04 Equipment, materials, construction and consultant services financed under the Bank loan were procured in accordance with the Bank procurement guidelines in 51 packages. Procurement delays were caused by the unforeseen and protracted price renegotiation between Algeria and Italy. Consequently, the bidding process which was progressing on schedule, stagnated between June 1980 and March 1982. Bidders for the pipelaying, the largest single package, were permitted to bid separately for the four pipelines or in combination. As a result of bid evaluation and with Bank concurrence, the contract was awarded on the basis of the combined lowest bid which seemed to be fair and Table 2. COMPARISON OF ESTIMATED AND ACTUAL PROJECT COSTS Tunisian Dinar Million USs Million a/ SAR Estimate Amended / Actual SAR Estimate Amended Actual Local Enrein Iotal LoUl Earisn 101 Locaal Loaoreig IgW l Eari Iotal Local Fares lotal Lacal acon Ilal Studies 0.9 0.8 1.7 0.5 0.5 1.0 0.9 1.0 1.9 2.2 2.0 4.2 1.4 1.2 2.6 1.4 1.6 3.0 Line Pine 0.2 4.7 4.9 0.2 5.4 5.6 0.0 10.2 10.2 0.5 11.7 12.2 0.6 13.7 14.3 0.0 14.5 14.5 Pipelaying and Cathodic Protection 6.9 6.3 13.2 5.4 4.7 10.0 6.8 6.3 13.2 18.4 16.0 34.4 13.6 11.8 25.4 8.2 7.5 15.7 Valves and Fittings 0.1 1.4 1.5 0.1 1.8 1.9 0.0 0.7 0.7 0.2 3.6 3.8 0.2 4.5 4.7 0.0 1.0 1.0 Land and Right of Way 0.2 0.0 0.2 0.3 0.0 0.3 0.0 0.0 0.0/ 0.5 0.0 0.5 0.7 0.0 0.7 0.0 0.0 0.0./ Measurement Centers 0.7 0.7 0.8 0.6 2.0 2.5 0.2 0.6 0.8 2.1 7.5 9.6 1.4 6.0 6.4 0.1 1.1 1.2 Conversion g/ Consumers (Tunis) 1.2 1.5 2.7 1.5 1.9 3.4 Gas Turbines 0.7 0.4 1.1 1.1 0.5 1.6 "otels ---- - - RA Z- R 1 LA Sub-total 1.1 2.0 3.1 0.7 1.2 1.9 1.9 3.9 5.8 2.9 4.9 7.8 1.8 3.1 4.9 2.6 6.2 8.8 0 Spare Parts 0.0 2.0 2.0 0.0 2.5 2.5 Miscellaneous - - - - - - -..3 .1 0 W - - - - - - LA L L2 Total Base Costs 10.7 18.3 29.0 7.8 IS.S 23.3 11.1 25.7 36.8 26.8 45.7 72.5 19.7 39.3 59.0 13.8 35.6 49.4 Physical Contingencies 0.6 1.1 1.7 0.6 1.0 1.7 1.6 2.7 4.3 1.6 2.6 4.2 Price Contingencies .LA M L. LA Id L2 - - - 1.A L 1W LA A UA -1- Total Costs 13.0 22.2 35.2 10.2 19.7 29.9 11.1 25.7 36.8 32.5 SS.S 88.0 25.8 49.9 75.7 13.8 35.6 49.4 a/ Exchange rates prevailing during period: SAR Estimates: US$1 = 0.4 OT Amended Estimate: US;1 = 0.395 OT Actual (Weighted Ave.):US$1 = 0.747 DT k/ Local/Foreign currency breakdown assumed to be in same proportion as SAR estimates. C/ Included in Miscellaneous. d/ No details provided in SAR Estimates and the Loan Amendment. - 31 - practical. The procurement table (Table 4) compares the SAR and actual Bank loan used for various components of the project. The SAR estimates i .Iluded US$5 million unallocated. This, combined with the lower actual project cost and non-disbursement for the Tadjerouine spurline, resulted in the cancellation of US$10 million of the Bank loan and an actual disbursement of US$27 million compared to the SAR estimate of US$37.0 million. Table 4. Procurement Table (US$ Million) SAR Actual 1. Studies 0.60 0.55 2. Line pipes ( 9.00 3. Pipelaying ( 17.30 11.20 4. Valves and fittings ( 8.50 5. Regulating stations ( 3.8 0.55 6. Spare parts ( 1.28 7. Measurement centers 8.1 1.10 (metering main off-takes) 8. Conversion, Tunis ( 0.64 9. Conversion, gas turbines ( 2.2 0.52 10. Miscellaneous - 1.31 11. Unallocated 5.0 - Total 37.0 27.00 5.05 On disbursement performance, the Project exceeded revised appraisal estimates only in its first semester, when actual disbursements run at 109% of estimates. Thereafter, actual disbursements averaged about 66.7% of estimates as shown in Annex 5. 5.06 Under the revised estimates, the Project was to have been fully disbursed on December 31, 1985. In September 1985, US$10 million of the loan was cancelled at the Government's request because of anticipated project cost savings (paras 5.03 and 5.04). Despite the cancellation, the loan was not fully disbursed until January 1988 because of the major delay in the project implementation (para 2.06). VI. IMPLEMENTATION PERFORMANCE A. Spurlines 6.01 The project implementation chart (Annex 6) compares the actual implementation performance with that originally planned for the individual major components. The project was delayed by about two years (para 2.02 and para 2.06) and some major components were changed and/or clarified after the project was appraised. Construction of Tunis, Sousse and Kasserine- Tadjerouine spurlines which were planned for completion in late 1981 early 1982, were completed in July, May and April 1983, respectively, and commissioning took place a few months later toward the end of 1983 and early 1984. The spurline to Gafsa was replaced by the spurline to Cap Bon which was completed in December 1983 and commissioned in February 1984. Disregarding the two years postponement of the project which was beyond STEGs control, construction of the spurlines was completed in about the same length of time as foreseen in the SAR and appears to be satisfactory. - 32 - B. Distribution 6.02 The distribution and conversion components of the project were not well defined and the project did not provide sufficient financing for these components, even though the SAR and loan amendments recognized and emphasized the importance of the premium markets. These components, along with an active market development strategy, are the only means for penetrating gas into the premium markets of commercial, residential and small industrial consumers who are the users of high value fuels, such as LPG, kerosene, gas oil or naphtha (for town gas consumers). C. Conversion 6.03 Table 3 shows that in a four-year period (1984-87), about 28,000 consumers were converted from liquid fuel or town gas to natural gas. A review of this table along with the distribution network development indicated that despite STEG's effort, growth in the number of consumers has been slow and consequently the share of gas being utilized in the premium markets is still small, i.e., 13% in 1987. This is primarily caused by the relatively inadequate sales engineering activities, slow conversion program and lack of sufficient distribution network infrastructure. Table 3. CONVERSION TABLE (No. of Consumers, Cumulative) 1983 1984 1985 1986 1987 1. Power Plants - 3 4 5 5 c/ 2. Large Industries - 2 3 4 6 c/ 3. Town Gas Manufacturing Plant, Naphtha-based a/ 1 1 0 0 0 4. Town Gas Manufacturing Plant, Natural Gas-based a/ 0 0 1 1 1 c/ 5. Residential and Commercial, Town Gas 27,000 27,000 25,875 18,357 6,300 6. Residential and Commercial, Natural Gas 6,000 b/ 8,400 11,325 20,543 34,200 c/ 7. Hotels 9 b/ 13 80 94 122 c/ a/ The town gas manufacturing plant was converted from naphtha to natural gas. b/ These consumers were using indigenous gas. c/ All these consumers are now using natural gas from Trans-Med. Pipeline. D. Sales Engineering Activities 6.04 STEG has one gas sales engineer who regularly visits industries and large commercial consumers to promote gas sales. STEG has developed special tables which provide the potential gas consumers with detailed calculations showing the cost savings resulting from conversion to natural gas. While this activity is a step in the right direction, it has not been sufficiently - 33 - effective, because the sales engineer is not responsible for providing the potential consumers with conversion cost and relative payout time calculations. Cost calculation is done by another section under the Gas Directorate of STEG and usually reaches the consumer about two months after the sales engineer's visit. It appears that a sales engineering group should be established in order to carry out activities such as consumer load survey, interfuel calculations, conversion cost estimate, as well as gas sales contract negotiations. This group should be capable of handling all the sales activities for industrial and large commercial consumers, including hotels. E. Project Appraisal and Supervision by the Bank 6.05 The total Bank's staff time spent in Tunisia on the project from identification to appraisal amounted to about 19 staff weeks. Recognizing that a lot of time had been spent on Miskar, yet it appears that for a complex project which involved imported gas, more time was required to focus on various issues such as market development. Six supervisions were carried out between April 1982 and June 1986. Most of the supervision reports and aide memoires were comprehensive and issues-oriented. F. Performance of Consultants, Suppliers and Contractors 6.06 According to STEG, except for the following cases, all consultants, suppliers and contractors performed their tasks in a satisfactory manner: (a) there were two tragic accidents during the pipelines construction: one as a result of the crane's arm short circuiting the high voltage overhead line and the other caused by overlifting and rolling over of the crane. Both incidents were caused by human negligence and lack of observance of the industry standards; and (b) STEG is not satisfied with the performance of the three measurement centers. Review of the situation indicated: i) numerous measurement errors; (ii) frequent power failures lasting beyond the standby battery capacity which provides for only two hours supply; and (iii) lack of availability of spare parts because of discontinuation of the instruments manufacturer's production line. 6.07 STEG is in the process of replacing all the mechanical and electronic devices and computers with up-to-date equipment. Measurement centers which are usually referred to in the industry for measurement of large international gas deliveries such as those in Tunisia involve sensitive operation and high technology devices. It appears that this component should have been packaged separately from the pipeline construction and handled directly by specialized contractors. G. Training 6.08 STEG's employees were trained both outside. and inside the country which included training of two engineers in France and twelve in Algeria. STEG is particularly satisfied with the training in Algeria. - 34 - VII. OPERATIONAL PERFORMANCE A. Gas System Operation 7.01 With the exception of the measurement centers, the gas systems installed under this project are working satisfactorily. These systems include the high pressure spurlines, distribution mains, service connections and customer meters and regulators, and piping installations and appliance/burners. The three measurement centers are operational, but performance is unsatisfactory (para 6.06, item (b)). STEG is in the process of modifying these measurement centers. 7.02 Table 5 shows the design and utilization capacities for each of the four spurlines. About 30% of the capacity is currently being used and there is ample excess capacity for future market development. Table 5. System Capacity Utilization Maximum Design Utilization Spurlines Capacity April 1988 m'/hr m' /hr Tunis 250,000 80,000 Sousse 200,000 60,000 Cap Bon 80,000 40,000 Tadjerouine 60,000 30,000 Total 590,000 210,000 B. Environmental Aspect and Safety 7.03 The project did not cause any major environmental problems. Any damages during construction along the spurlines' right-of-way were of a temporary nature and were corrected after completion. Adequate compensation was provided for damaged crop and property which were relatively minor. A major part of the natural gas being utilized through this project is substituting fuel oil with 1-2% sulphur content. This would alleviate the air pollution. 7.04 In the course of conversion of the town gas consumers' facilities to natural gas (about 20,000 customer facilities were converted as of end-1987), one tragic accident involving human life happened on November 25, 1987. The mission expressed its deep concern and stressed the importance of safety and its impact on the future of the gas industry in Tunisia. Accordingly, the mission discussed the following steps with STEG: (a) National standards - STEG has already adopted standards for transmission systems and is in the process of preparing standards for distribution and gas utilization. - 35 - (b) Consumer piping installation and appliance/burner conversion - The mission recommended that STEG prepare booklets for standards and safety measures for consumer piping installation and appliance conversion. The mission also recommended that these standards be made obligatory by law. (c) Qualified contractors - STEG has prepared a list of qualified contractors for consumers' piping installation and appliance/burners conversion. The mission recommended that these contractors and their technical staff, i.e., mechanics and welders be tested periodically to make sure that they are familiar with the standards and that they carry out their activities accordingly. (d) Consumers' installation inspection - As a matter of standard operating procedure, STEG approves the contractoi's plan for piping installation and inspects the final work (including pressure test) before opening the gas to the consumer premises. VIII. INSTITUTIONAL ASPECTS 8.01 STEG is primarily the national power utility of Tunisia in tharge of public supplies of electricity. It is also in charge of the public distribution of gas in Tunisia. In this respect, in the South it acquires domestic gas at El Bormah (at no charge), and small quantities of associated gas from Algeria at a relatively low price which it uses essentially to feed its power plant at Gabes and a small industrial market in the vicinity; in the North, it acquires Algerian gas to feed 5 power plants at Kasserine, Rades (near Tunis) and Sousse, 6 large industries and to serve a small but with large market potential comprising residential, commercial and small industrial consumers (para 6.03). Gas sales in 1987, including southern gas, estimated at TD 21 million, represent less than 10% of total annual revenues of TD 223 million. 8.02 STEG employs a staff of about 6,700 of which 600, or 9%, are employed by the Gas Directorate. The Gas Directorate, headed by a Director reporting to the Company's President, is in charge of the technical aspects of gas transport and distribution, as well as of the LPG extraction plant in the South. Supporting functions, including personnel, accounting and budgeting, meter reading, billing and collections are undertaken by the appropriate divisions of STEG entrusted with the same functions for electric power. 8.03 Until the Project came about, STEG's gas activities in the north were confined to the distribution of town gas in Tunis (produced from the reforming of naphtha) and the distribution of minor quantities of indigenous natural gas in the Tunis and Cap Bon areas. As a result, it was recognized at appraisal that it would be necessary to strengthen the Gas Directorate, inter alia, by che training of staff in Tunisia and abroad. It was anticipated that Gaz de France would provide preliminary training in respect of construction work, maintenance, operations and commercial aspects of gas activities, and that suppliers of equipment will arrange for specialized training programs. - 36 - 8.05 The Gas Directorate is equipped adequately to handle its operating responsibilities, but needs to expand its market development skills and technical resources to a higher level to implement a more ambitious development program. The management is aware of this and is planning to expand the Gas Directorate's capabilities to cope with the country's gas distribution network development plan particularly in the Tunis area. 8.06 The mission believes that the time is ripe for the Government to explore the possibility of giving more autonomy to the country's gas operations. Some justifications for this proposal are: (i) Gas will continue to take an increasing role in the energy balance of Tunisia as petroleum reserves are expected to last only through the early 1990's; (ii) Gas and electricity technology and operation are different and their combined operation under STEG, particularly when gas is a minor activity within STEG's domain, constrains the gas industry's development in Tunisia; (iii) Future gas activities such as city gas distribution in Tunis and other cities would be expedited. This is beneficial to the country's economy as more gas would shift from the fuel oil market to the premium fuels market; (iv) An established gas institutional framework would already be in place once a decision is made to develop the country's large offshore gas reserve in Miskar; and (v) A separate gas entity would eliminate the problem of the separate accounts and implicit subsidies between the gas and electricity sectors. 8.07 It appears that the potential benefits of a gas operation with more autonomy for Tunisia far outweigh the costs. This move would ensure that issues concerning the future of the gas industry in Tunisia would be appropriately addressed and that its future development would be given the attention that it rightfully deserves. IX. FINANCIAL ASPECTS A. Separation of Accounts 9.01 It was recognized at appraisal that STEG's accounting and management systems were efficient, that accounts are produced promptly, and that the main issue relates to the separation of gas and electricity accounts.1' As a result, agreement was reached during negotiations that separate non-statutory itemized accounts (including separate annual cash accounts) would be maintained for imported gas operations, El Borman gas operations, and other operations. Furthermore, it was also agreed that the audited accounts (on a 1/ Under Loan IBRD 724-TUN of February 1971, STEG agreed to maintain separate (non-statutory) accounts for El Bormah, and had done so, although accounts were not always produced promptly (SAR, para. 3.07). - 37 - consolidated basis) would be submitted to the Bank within six months from the end of the fiscal year, and that the audited accounts related to purchased gas would be submitted to the Bank within 9 months. These arrangements wereanticipated to come into effect in FY82, but were deferred by a year under the first amendment of the loan to take into account the delay in project execution. 9.02 As gas started to flow only at end-1983, STEG initiated the preparation of separate accounts for imported gas for that year (consisting only of an opening Balance Sheet), and for the subsequent years prepared full accounts (therefore incorporating Income Statements and Sources and Application of Funds statements). The audited accounts were unqualified and ready on a timely basis, except for the FY83 accounts which vere submitted one year late. 9.03 Still, an examination of STEG's compliance with the financial covenants becomes somehow theoretical, particularly since STEG did not: (a) prepare separate accounts for its activities other than purchased gas as provided for under the loan agreement; (b) maintain separate cash accounts (on an annual basis) for its imported gas activities; and (c) revalue assets on an annual ba is in accordance with the methodology agreed upon at negotiations.l' As a result, supervision missions, and the completion report mission had to perform their own calculations to assess STEG's performance under the financial covenants, but could not assess the impact of gas prices on the power sector (see also para. 3.06 above in this respect) or establish whether cross subsidies within STEG's different operations take place, and, if so, their extent.-' 9.04 Bank supervision missions since 1984 emphasized to STEG the urgency to prepare separate statements for purchased gas, and this was repeatedly mentioned in the correspondence with the borrower. Furthermore, three supervision missions 1' had to use preliminary data to reach tentative conclusions regarding the financial position of the gas activity (the 1/ In accordance with a recent regulation, assets in operation in 1982 were revalued, and a provision introduced in the fiyed assets and consumer contributions accounts of the FY87 balance sheet. In view of the small value of gas investments made until 1982, the financial impact is minimal. 2/ Under section 5.06 of the Loan Agreement, the financial covenants related to STEG under the Second Power Project (Loan *1355-TUN of December 23, 1976) were redefined to specifically exclude STEG's purchased gas operations from July 1982 onwards. 3/ June 1984, December 1984 and July 1985. - 38 - complexity of the financial mechanisms, particularly pricing and taxes also proved to be a considerable handicap in this work). 9.05 With respect to STEG's power generation activities, while the financial covenants under the three most recent power loans apply exclusively to the power sector due to the non-availability of separate accounts, the financial appraisal and supervision of these projects have been predicated on a review of STEG's finances in their entirety, as a result of which subsidies from purchased gas to power generation cannot be readily identified. 9.06 In conclusion, it would appear that the objectives of the Bank in terms of ensuring separately the financial viability of STEG's purchased gas, and STEG's power activities has not been attained because important accounting data needed for that exercise is not being generated. STEG is, however, aware of the problem, as consideration if now being given to transferring the accounting for gas to the Gas Directorate. This would represent an important step, and reelect recommendations made by supervision missions in the past, (including the appointment of a qualified accountant to coordinate all gas related accounts, to prepare separate budgets, to monitor compliance with financial covenants, etc.). B. Financial Performance 9.07 A comparison of expectations at appraisal and actual results has limited financial significance particularly because of: (a) the considerable reduction in project scope, and cost estimates together with the delay in project implementation (para 6.01); (b) the large reduction in sales resulting from the switch from fuel oil to premium fuels replacement (para 3.02); and (c) the large drop in oil prices (as an indication, the price of fuel was expected to reach US$235/TOE in 1987, against an average price of US$105/TOE during that year). As a result, the comparison of the appraisal forecast over 1982-87, with actual results over 1983-87, which appears at Annex 7 should be read with the above caveats in mind. I' 9.08 The main financial covenant provides for an 8% rate of return on average net revalued assets from FY82 onwards; under the first amendment of the Loan, this covenant was modified to become effective in FY83. Since gas became available only at end-1983, compliance with the covenant could only be monitored from FY84. STEG was never able to attain the 8% rate of return target-from a negative 22% return on assets in FY84, the rate increased to slightly below 4% in 1987. This is essentially because the purchase price of gas in the early years was too high in relation to the valuation of gas used for power generation. As a matter of fact, as indicated in Annex 2, the 1/ Actual results differ from STEG's audited accounts for purchased gas to reflect the revaluation of assets, and to correct some errors in STEG's gas account. - 39 - average purchase price of gas was higher than the value of gas assigned to power generation in FY84 and FY85. In FY86, that margin was positive, but the volume of STEG's consumption in power declined dramatically, so that the gross income was insufficient to attain the target. FY87 was the first year in which the purchased gas operations showed a profit, on account of higher sales, and a positive margin for power generation. Of course, taking into account the issue of transfer pricing of purchased gas used for power generation (para 3.14),.L and the limitations of the separated accounts for purchased gas under the present procedures (paras 9.01-9.06 above), the interpretation of the covenant is limited. 9.09 Another covenant provided that STEG could not borrow long term for its purchased gar operations without the prior agreement of the Bank unless the debt service coverage ratio exceeded 1.2 from 1983 onwards. Bank supervision missions became aware that the debt service coverage ratio was considerably below 1.2 and the Bank notified STEG on February 13, 1985, that the prior agreement of the Bank should be sought prior to securing new long-term debt. The covenant was complied with to the extent that STEG did not incur new long-term loans for purchased gas activities after that date. 9.10 Another covenant provided that transfers from the purchased gas operations to other activities could only take place once the financial targets have been reached. The covenant is not enforceable as long as accounts are not prepared separately for the other activities of STEG, and separate cash accounts are established (para. 9.03 above). 9.11 Regarding STEG's failure to meet the the financial targets of the loan, the following recommendations appear appropriate under the circumstances: (a) The reporting requirements under the Project (spelled out in the agreed minutes of negotiations dated May 2, 1980) make no reference to financial reporting. By including at least semi-annual financial reports to be submitted in a timely manner, STEG would have been required to carry out more financial analyses of the purchased gas operations than it has, and establish on its own (instead of through Bank supervision missions) its performance under the financial covenants; (b) The Bank's analysis did not reflect in full the implications of the transfer price in the formulation of the covenants; with hindsight, it would have been more appropriate to spell out the basis for transfer pricing so that the rules are known well in advance, and that such prices cannot be established arbitrarily; (c) The audit covenant should have been broadened to encompass not only STEG's consolidated accounts and, separately, the accounts for purchased gas, but also the el.ztricity/El Bormah activities;1' 1/ Had the gas 3ed by STEG's gas turbines been valued at the cost of diesel oil, the conclusion would have been different. 2/ Understandably, this approach was not adopted under the Fourth Power Project (Loan 2455 of June 27, 1984) so that the Bank is not in a position to assess the financial performance of STEG's power activities per se. - 40 - C. Financing Plan 9.12 It was anticipated at appraisal that the Project would be financed by way of export credits (US$12 million), commercial banks (TD 7 million equivalent to about US$18 million at the then exchange rate), Government equity (TD 10 million-US$25 million) and the Bank (US$37 million).L' STEG was not expected to participate in the financing of the Project. The financing plan was supported by several legal undertakings, and in particular, the signature of US$5 million of export credits was made a condition of effectiveness of the Bank loan. 9.13 Following the reduction in the scope of the Project, and the amendment of the Loan, the financing plan was revised, with the deletion of export credits, and an increase in the amount of commercial borrowings (TD 8.2 million). The amount of the Government's equity contribution and of the Bank Loan remained unchanged. 9.14 The evolution of the financing plan can thus be summarized as follows: Financing Plans (US$ million) a/ Initial b/ Amendment c/ Actual d/ IBRD 37 37 27 Suppliers Credit 12 - 4 Commercial Borrowings 18 19 12 Government 25 24 9 Total 92 80 52 a/ Including interest during construction 11/ Exchange rate of US$2.5/TD (SAR) c/ Exchange rate of US$2.35/TD (Memorandum Amending the Loan) d/ Actual exchange rate at time of disbursements (STEG's accounts) 9.15 The reduction in the Bank loan, the commercial borrowings, and the equity contribution are all explained by the reduction in the Project's cost and are therefore reasonable under the circumstances. 9.16 The government participation in the financing plan amounted to US$9 million (equivalent to 17%). But, STEG, the implementing agency, did not participate in the financing of the Project (except for a nominal amount of interest during construction). This is possibly because STEG's power operations were not sufficiently profitable at the time and the gas activities too small to yield financing for a new activity. The Bank records are not clear on this point. Yet one could have argued equally well that STEG's gas activities in the South which were not insignificant in terms of gas utilization (in excess of 200,000 TOE per annum), and the Tunis town gas network ought to have contributed to the purchased gas activity as well. 1/ SAR, para 2.19; PR, para 49. - 41 - D. Conclusion 9.17 It seems that, at least from a legal standpoint, the Bank has obtained under this Project all the undertakings required for a financial separation of the electricity and purchased gas activities. Some progress has been made in preparing separate accounts for purchased gas, but considerable progress remains to be made to establish separate accounts for STEG's other activities, and introduce the measures required to ensure separately the financial soundness of STEG's gas and electricity activities. X. ECONOMIC REEVALUATION 10.01 It was anticipated at appraisal that natural gas would essentially replace fuel oil used for power generation and industrial purposes, that sales of gas will increase rapidly (2.4 million TOE in 198t, 0.9 million TOE in reality), and that the economic price of gas would be approximately 70% of the price of fuel oil. With these assumptions, the SAR's economic rates of return was 28%. 10.02 The economic rate of return of the Project was recalculated on the basis of actual costs and performance to date. The benefits of the project reflect the CIF and distribution costs of petroleum products natural gas replaces (essentially LPG, diesel oil and fuel oil). The cost of the Project includes the investment and operating expenses, as well as gas purchases which were all valued at the selling price of Algerian gas (since royalty gas sold to Italy is priced at that level, too). Beyond 1987, the following assumptions were made: (a) purchased gas would only be used in gas turbines, for peaking in the coming 5 years, by which time STEG would switch its peaking needs to more efficient plants; (b) for uses other than power generation, STEG's forecast was used; and (c) the price of imported gas was assumed to remain constant at the level anticipated for e second quarter of 1988, while fuel oil, diesel oil and LPG were priced respectively 6%, 52% and 68% higher on a calorific equivalent basis, in line with experience acquired over 1982-87."' 10.03 Under these asaumptions, the economic rate of return of the Project turned out to be 14% against SAR's 28%. This significant reduction was primarily caused by a lower gas utilization than that of SAR's forecast (para 2.07, Table 1). However, the system provides ample capacity for future requirements (para 7.02). The calculation appears at Annex 8.3' STEG would 1/ This is considered appropriate under the circumstances since the benefits of gas use are essentially dependent on relative and not absolute prices. 2/ Since there is more than one sign change in the net cash flow, there might be more than one discount rate which equalizes benefits and costs. However, between 0% and 14%, the net present value of the cash flow remains positive, so that 14% is the first positive discount rate which equalizes costs and benefits, so that it can be taken to be the economic rate of return of the project. - 42 - have saved the national economy about US$4 million and the rate of return of the Project would have increased by 1% had STEG abstained from using gas in the steam units during 1986, when oil was cheaper than imported gas during the whole year. 10.04 Despite the relatively low rate of return, the northern part of Tunisia has now the requisite basic infrastructure for gas to supply the most important industrial and commertial centers where most of Tunisia's population live. The addition of new customers to the grid, can be done in most cases at a relatively low cost, and the economic return can be extremely high for those using fuels other than fuel oil. Proper institutional arrangements would be required to accelerate systematic effort to convert such consumers to natural gas. XI. CONCLUSIONS 11.01 The project was related to one of the largest international gas projects (the Trans-Mediterranean Pipeline) with all the complexities which are inherent to these projects such as long lead planning time, heavy front end investment, long term and complex contractual arrangements, as well as pricing issues. 11.02 Overall, the objectives of this complex project which underwent several changes were substantially met. The project as completed consisted of four new gas systems serving Tunis, Sousse, Cap Bon and Kasserine- Tadjerouine. It also included three measurement centers at the off-take points of the TMP, four high-pressure spurlines, distribution mains and service lines for supply of gas to five power plants, six industrial and about 35,000 commercial and residential consumers. 11.03 There was a critical variable, the renegotiation of the pricing of Algerian gas during the early stages of the project that delayed project implementation by about two years (para 2.02). The project was, however, completed with a 44% cost underrun, mainly due to favorable ICB procurement and changes in project scope (para 5.03) and a substantial appreciation of the US$ vis-a-vis the Tunisian dinar during project implementation. Lessons Learned 11.04 There are lessons to be learned from this project as follows: (a) When the project was appraised, there was a firm and long-term gas sales and purchase agreement in place between Algeria and Italy. However, as a result of the early 1980's oil price upheaval, the pricing of the agreement became a crucial issue between the parties concerned. When the Loan Agreement was amended in 1981, pricing was still under renegotiation. It appears that the project implementation should have been retarded until agreement on pricing was reached. This would have prevented an idle gas grid investment for one year and would have provided a clear basis for project evaluation and planning; - 43 - (b) It would be useful for similar projects based on natural gas imports, whose price is subject to complex formulas, to: (M) retard the implementation of domestic gas networks until a satisfactory agreement on pricing has been reached between the parties concerned. This would have given Tunisia more leverage during negotiations (it would not have had an idle gas grid during one year), with minimal adverse repercussions, since the royalty gas could be sold to Italy; and (ii) carry out computerized simulations of gas pricing formulas over long enough periods to test the bahavior of gas prices in relation to alternative fuels. (c) Originally, the main objective of the project was to substitute gas for fuel oil. However, because of the steep rise in the price of Algerian gas during the initial stages, the project was amended to substitute gas for the premium market, primarily LPG, naphtha and gas oil. During this switch, however, the project failed to provide for an elaborate distribution network development plan and conversion program, two aspects critical to the success of any gas project. As a result, actual sales averaged only 30% of SAR estimates for the period 1984-87, or the share of premium market was only about 16% of the total gas sales in 1987 which adversely affected the project's e.onomic performance. This brings to light the critical importance of responding to the changing scope/objectives of a project. As the target markei was rightfully shifted to the premium fuels market in response to a change in a critical aspect of the project (pricing), a detailed market survey for the domestic market should have been developed and from there, a distribution network development plan tailored to the target market should have been prepared. These twin actions would have provided the appropriate response to the shift in priority objectives of the project. (d) In tandem with the market survey and distribution network development plan, the project should have also provided for a conversion program. The conversion program should have explicitly indicated the type and number of consumers to be converted in each year. Experience shows that lack of detailed planning for conversion has always caused significant delays in market development, despite timely completion of main project components such as transmission and distribution network. In other words, a conversion program if not properly planned and executed becomes a bottleneck to the market development of a gas project. (e) Another critical project component concerns the institutional aspects, particularly the maintenance of separate accounts for STEG's gas activities. 11f timely implemented, this measure would have afforded both STEG and the Bank the means to effectively monitor the efficiency of STEG's electricity and gas operations. As it turned out, the absence of a separate account meant that the missions had to -44 - rely on preliminary data to reach conclusions regarding the financial position of the gas activity. Furthermore, possible cross-subsidies between purchased gas and power activities of STEG could not be ascertained as review of STEG's finances could only be done in their entirety. With the benefits of hindsight, there should have been closer coordination within the Bank regarding the supervision of STEG's gas and power accounts, and the Bank should have exercised more pressure on the authorities on this matter, possibly in connection with adjustment lending. STEG, however, is now much aware of the problem and consideration is being given to transferring the accounting for gas to the Gas Directorate. (f) Virtually all the financial targets of the loan could not be attained for a variety of reasons, including reduced sales volume, STEG's reluctance to consider gas as a separate profit center, the adoption of pricing policies which do not reflect the true value of gas, and the use of gas as a fuel oil substitute even when not justified economically. As a result, the following recommendations (spelled out in more detail at para 9.11) seem pertinent under the circumstances: (i) the reporting requirements for the project should require at the minimum semi-annual financial reports incorporating inter alia a statement of compliance with financial covenants; (ii) in cases such as STEG's when the implementing agency is also the main user of a product, appropriate guarantees should be sought on transfer pricing policies; (iii) when a separation of accounts is sought, the audit covenant should, in addition to the audited accounts, provide for the separate audit of each activity (and not one of the activities as was the case in this instance), as well as a statement on keys used to separate accounts. (g) There is a need to strengthen the institutional framework for Tunisia's gas resources. The mission believes that the time is ripe for the government to assess the possibility of giving more autonomy to the country's gas operation. The precise form of this autonomy should be investigated. - 45 - TUNISIA Cansuaption of Ndrocarbos (thouad of tet) Grawth Rate 1980-07 1990 1981 1982 1983 1984 1905 1986 1997 Natural Gas North 0 0 0 3 379 650 322 994 South 4119 464 500 501 489 447 433 393 -11 Total Natural as 419 464 500 504 968 1,098 774 1,277 172 LP6 106 118 132 143 165 186 199 211 10% Iasline 159 168 177 196 210 229 229 227 5 Jet Fuel 186 165 32 143 165 186 199 211 22 Kerosne 112 116 126 131 137 140 143 145 41 Disel Oil 795 917 834 919 940 987 949 975 31 Light Fuel Oil 143 135 109 86 76 64 47 33 -191 Fuel Oil 969 989 896 1,179 98 847 1,100 72 -41 Total Liquids 2,471 2,508 2,405 2,797 2,682 2,638 2,866 2,526 0 Total Coasuption 2,99 2,972 2,906 3,301 3,550 3,736 3,640 3,9803 41 Fuel Oil/Total (1) 33.541 33.27 30.852 35.70 27.831 22.67 30.231 19.041 Fuel Oil + Natural Gas/Total (1) 48.032 48. 48.07 50.97 52.282 52.052 S1.502 52.621 Northern Oas/Total 02 0 02 02 112 172 92 242 22-ay-88 a - 46 - TUNISIA Annex 2 Societe Tunisienne de L'Electricite et du Saz (STES) Northern Sas Activity Oas Purchases and Sales ACTUAL Prov. Budget 1983 1984 1985 1986 1987 1988 I. Supplies A. Guantities Jebel Abdelrrahman 5 2 1 1 1 1 Royalty Gas 6 254 408 133 311 520 Purchased Gas 126 237 182 600 387 Total 11 382 646 316 912 907 8. Cost (Dinars Thousands) Royalty gas 438 18,241 28,871 9,219 23,077 39,416 Purchased Gas 15,580 26,375 13,002 45,594 29,335 Total 438 33,821 55,246 22,220 69,471 68,751 C. Average Price (Dinarltoe) Royalty as 77.2 71.7 70.8 69.3 76.7 75.8 Purchased Sao 123.3 111.2 71.4 76.0 75.8 Overall Average 77.2 88.8 85.6 70.5 76.2 75.8 II. Gas Utilization A. eantities STES - TV (steam turbine) 157 404 186 688 STEG TAS (Gas Turbine) 2 169 145 19 89 STES Consumption 2 327 548 204 776 750 Domestic Consumption 1 18 23 26 28 31 Heavy Industries 33 66 69 61 95 Hotels 0 6 14 18 19 Niscellaneous 0 1 6 9 11 12 Subtotal 1 52 102 117 118 157 Total Use 3 379 650 322 094 907 8. Revenues (Dinars thousands) STEG Consumption 203 23,913 43,219 17,473 68,447 66,199 Demestic Consuption 1,995 2,026 2,374 2,328 2,774 4,123 eavy Industries 0 5,615 6,051 5,018 7,600 Hotels 12 68 1 676 2 246 2 527 Other 2,808 881 243 1,964 1,596 Subtotal 1,995 4,846 9,559 11,298 12,003 15,846 Total North 2,199 20,759 52,778 28,771 80,450 82,035 C. Average Revenue (Dinars/toe) STE C insuption 73.1 78.8 85.5 88.2 88.3 Domestic Consumption 110.0 101.9 91.0 100.7 133.0 Heavy Industries 0.0 84.7 87.6 81.7 80.0 Hotels 112.7 121.3 126.3 133.0 Other 3421.3 139.1 142.5 174.4 133 Average (other than power gen.) 93.7 93.7 96.4 101.7 100.9 Average 75.9 81.1 89.5 90.0 90.4 08-Sep-88 ANNER 3 - 47 - Page 1 of 10 TUNISIA Second Natural Gas Pipeline Project (Lan 1864 - TUN) The Pricing of Natural Gas I. Introduction 1. The pricing of natural gas is a complex issue since, unlike oil products, natural gas is not a freely traded commodity. As a matter of fact, natural gas prices vary considerably from one country to the next, and in most instances, are largely influenced by those of competing fuels, and to a lesser degree by costs considerations. 2. In Tunisia's case, further complications arise from the following: (a) the price of Algerian gas to Tunisia, in the final analysis, is largely dictated by the contract between Algeria and Italy, which inter alia reflects a basket of 8 international crudes adjusted on a quarterly basis. As a result, particularly at times of large fluctuations in international oil prices, the price of Algerian gas may become unattractive to the economy when compared to that of imported oil products gas can replace1'; and (b) like some other net exporters of petroleum products, Tunisia has historically maintained domestic prices for liquid fuels (other than gasoline) well below international levels. Under such circumstances, Algerian gas would only be marketable in Tunisia if priced below its border price, i.e., subsidized. The price of imported gas had a considerable impact on the project's design, implementation and economic rate of return, as well as the formulation of most covenants. In view of its importance, this Annex therefore reviews the evolution of gas pricing during the implementation of the project in detail. II. The Price of Algerian Gas A. Contractual Aspects 3. Tunisia is entitled to natural gas through: (i) a "take or pay" contract with Algeria under which Tunisia imports gas at a price determined 1/ Tunisia is an exporter of crude oil but an importer of all oil products, so that the cost of Algerian gas to the economy -has to be compared to CIF oil products prices. ANNEX 3 -48 - Page 2 of 10 through a contractual formula (this gas is referred to as purchased gas)L"; and (ii) an agreement with Italy, which provides Tunisia with royalties for transmitting gas (in cash or in kind) equivalent to 5.250' of the throughput of the intercontinental pipeline. In the event that Tunisia decides to take the royalty gas in cash, Italy would compensate Tunisia on the basis of the price paid to Algeria for purchased gas. These arrangements are prima facie advantageous to Tunisia, to the extent that they allow for considerable flexibility in the national consumption of imported gas. On the other hand, one should note that Tunisia has relatively little control over two important elements, i.e., the price of gas, and the quantity of royalty gas available. 4. The tripartite negotiations involving Algeria, Italy and Tunisia for the contract had already started in 1973, and the terms of the transit agreement between Italy and Tunisia had been agreed upon already in 1977.' By appraisal time (October 1979), the most important contract binding Algeria and Italy was effective although this contract was under renegotiation in July 1981 when the Loan Amendment was signed (para. 2.02). At the time, construction of the transcontinental pipeline was well underway, at a cost in excess of US$3 billioni' with an anticipated completion for October 1981. 5. In view of the total dependence of the project on the gas supply contract, the Bank anticipated receiving a copy of the document during Project processing. The Appraisal mission reported that despite the assurances given, it did not receive copies of the contracts; following appraisal, receipt of the contracts was made a condition of negotiations. However, the 1/ "Take or pay" contracts are frequent for gas projects and commit the buyer to acquire a minimum quantity (i.e. 60-90%) of gas on a continuous basis. They usually also allow the buyer to take daily quantities in excess, provided that adquate notice is given. 2/ For quantities exceeding 12 billion m3 per annum, the royalty increases to 6%. 3/ Source: SAR, para. 2.01. 4/ Memorandum of the President to the Board of June 22, 1981 (para. 11). - 49 - ANNEX 3 Page 3 of 10 Government informed the Bank in March 1980-' that its contractual partners in Algeria and Italy had objected to the disclosure of the contracts to the Bank, and that in any event, Bank staff were already aware of their salient features. The Bank eventually agreed to negotiate the loan without having had formal access to the contracts, a position which was not shared by all.-V At negotiations (April 1980), it was agreed instead that a confirmation that the Staff Appraisal Report reflect the substance of the supply contracts, and the subsequent submission of a legal opinion certifying that the royalty and gas purchase contracts are effective would be satisfactory. The Project was submitted to the Board (June 1980) on this basis. B. The Contractual Prices 6. Throughout project preparation and appraisal, it was anticipated that the price of imported gas would be highly attractive to the Tunisian economy, i.e., considerably below the economic cost of liqaid fuels to be substituted. An internal memorandum refers to 66% to 80% of international oil prices, and the SAR makes a reference to a border price equivalent to 60-70% of the "present international price for fuel oil" (para. 2.07) which is even more appealing.3' 7. The Bank was informed shortly after Board presentation of a substantial increase in the price of Algerian gas so that the utilization of natural gas to substitute fuel oil as intended initially was no longer economically attractive. - The Government, following a careful examination of all its options, decided to redesign the Project in July 1980, and aim it at the replacement of diesel oil (gas turbines, industries) and naphtha (Tunis town-gas network); Tunisia would then forego the option to purchase gas from 1/ Covering Memorandum of Loan Committee Package dated April 2, 1980, para. 9. 2/ Memorandum of March 28, 1980. 3/ As the 1979-80 period coincided with the second oil shock, it was in all likelihood anticipated at the time that there would be a continuous lag in the adjustment of the price of Algerian gas (on a quarterly basis) to international prices, which explains partly the low levels of gas prices quoted. 4/ The SAR provides little information about the specific market for the imported gas but it is implicit that the bulk of the supplies would be used to replace fuel oil (paras. 1.17 and 5.05). Furthermore, the economic analysis of the Project was predicated on fuel oil replacement exclusively, at a price equivalent to US$180/ton. ANNEX 3 -50- Page 4 of 10 Algeria and only use its royalty gas for the premium market when economically justified. The Project was then redesigned into Stage I (essentially replacement of premium fuels) and Stage II (replacement of fuel oil). The Government gave high priority to proceeding with Stage I at the earliest. Obviously, this necessitated an amendment to the loan agreement, which was approved by the Board on a non-objection basis in July 1981. Furthermore, submission of a legal opinion, as condition of effectiveness of the loan (para. 5 above) was confined to the royalty gas contract. 8. One should note that at the time the loan was amended, the value of royalty gas was still uncertain' so that the justification of the Project was in doubt for certain components. Analyses made at the time indicated that the Tunis, Cap Bon and Kasserine lines were justified-'; the lines to Tadjerouine and Sousse (altogether about 30% of the anticipated uses of the Loan proceeds) on the other hand were subjected to the submission of satisfactory evidence on their economic viability, as a condition of disbursement. This approach was probably appropriate under the circumstances, given the lack of data on the value of royalty gas when compared to liquid fuels. 9. Supervision missions in 1982 and 1983 reported on difficulties in the reaching of an agreement on gas prices between Algeria and Italy, while the domestic transmission and distribution network was under construction, and for certain portions, ready for commissioning. Algeria, Italy and Tunisia finalized the agreements in July 1983, and gas started to flow in December 1983, i.e., with a two years delay when compared to appraisal expectations. C. Actual Prices Bid 10. It is understood that the contract between Algeria and Italy (which determines also the price of gas purchased by Tunisia, and the price paid to Tunisia when it declines to receive the gas in kind) is based on a basket of 8 crudes updated on quarterly basis. Prices can be estimated well in advance (for instance by applying the formula on a 3-months moving average basis) which gives Tunisia some flexibility to establish a strategy for gas utilization, on a quarterly basis, in accordance with economic criteria. 11. STEG carefully monitors the prices of imported natural gas and the prices of oil products it substitutes such as LPG, diesel oil and fuel 1/ The value of royalty gas being the price Italy would pay should Tunisia decline to use it (para. 3.09). 2/ Subject to the installation of a gas turbine at Kasserine. -51 - ANNE 3 Page 5 of 10 oil." The graph at Appendix 1 of this Annex depicts the price of gas in relation to liquid fuels over 1982-88 on a quarterly basis. Those data can be summarized as follows: Comparison of Imported Gas Prices and Alternative Fuels (US$/TOE) 1982 1983 1984 1985 1986 1987 1988 '' Diesel Oil 275 234 228 225 130 148 134 Fuel Oil 173 173 185 157 79 105 76 LPG 283 299 235 234 139 167 162 Algerian Gas 185 161 147 144 101 83 89 a/ Prices for the first quarter of 1988 Source: STEG, Gas Directorate, Quarterly Price Data Tables, May 1988 During the period under review, Algerian gas was, with the exception of the first quarter of 1986 (when prices declined rapidly) more attractive, on a calorific equivalent basis, than LPG and diesel oil. But, this was not the case for fuel oil substitution particularly in 1982, 1986 and the first quarter of 1988, when the landed cost of fuel oil was lower on average than the price of gas at the border. Based on the same data, a quarterly comparison indicates that out of 25 quarters (January 1982 - March 1988), fuel oil was a more attractive source of heat than natural gas during 9, or 36% of the time. The authorities are very aware of the issue, and STEG's two swing power stations (at Rades, near Tunis - 480 MW, and Sousse - 320 MW) aim to operate accordingly. D. Conclusion 12. On the basis of the events to date, the Bank's cautious attitude in relation to pricing in general and the gas contracts in particular was undoubtedly justified. The authorities also acted promptly to redesign the scope of the project once they became aware, around mid-1980, of the higher price of Algerian gas. With the benefit of hindsight, it would be useful for similar projects based on natural gas imports to: 1/ The economic prices of these products are based on f.o.b. Genova, plus transport and distribution. In the case of fuel oil used by STEG, no provision is made for distribution, the fuel oil based power plants being located at the coast. - 52- ANNEX 3 page 6 of 10 (M) carry out computerized simulations of gas pricing formulas over long enough periods to test the behavior of gas prices in relation to those of alternative fuels; and (ii) retard the implementation of domestic gas networks until a satisfactory agreement on pricing has been reached with the parties concerned (in this instance both Algeria and Tunisia). This would have given Tunisia more leverage during negotiations (it would not have had an idle grid during one year), with minimal adverse repercussions, since the royalty gas could be sold to Italy. III. Domestic Prices A. Domestic Pricing Covenants 13. At appraisal time, domestic prices of petroleum products to be replaced by natural gas were considerably below border prices-/ so that imported gas could only be sold domestically if subsidized correspondingly; otherwise a conversion to natural gas would have been unattractive from the standpoint of consumers. As a result, agreements were reached during negotiations (April 1980) whereby: (i) the priced charged by the Government to STEG for royalty gas would be gradually raised to reach full import parity by the end of 1986 (Section 3.03 of initial Guarantee Agreement); and (ii) the domestic price of fuel oil will be at least equivalent to that of natural gas (Section 3.04 of initial Guarantee Agreement). These two covenants together ensured, from the Bank's standpoint, that the price of fuel oil would reach import parity by early 1987. When the loan was first amended (July 1981), these agreements were replaced by new covenants providing for gradual increases in the prices paid by STEG for royalty gas to reach international levels (defined as the price paid by Italy to Tunisia for royalty gas, Section 3.03 of Guarantee Agreement) by early 1987, and increases in the prices of oil products gas is intended to replace to international levels, to be reached by the same target date (Section 3.04 of Guarantee Agreement). 14. It was thought at appraisal time that STEG would purchase imported gas from the Algerian party, Sonatrach, and for a limited period receive the royalty gas free or at a subsidized price (this approach was used in the financial analysis). In reality, two institutional arrangements have been in effect since gas supplies started: (i) until September 1985, STEG bought purchased gas from Sonatrach; in addition, it had to pay customs duties and transportation fees in the international pipeline. Obviously, as the cost of purchased gas to 1/ The January 1980 domestic price of fuel oil was US$60/ton against an Italian spot price of US$182/ton. The domestic price of heating oil (98% diesel oiL and 21 fuel oil) was US$158/ton which compares to an Italian spot price of US$365/ton. (Source: SAR, Annex 1.06) - 53 -AN 3 Page 7 of 10 STEG exceeded by far the domestic price of fuel oil until 1985, STEG was compensated for the difference. For royalty gas, STEG had to pay the State a fee broadly similar to the domestic price of fuel oil, and a "fiscal fee".l (it) Since October 1985, the contract of Sonstrach has been with ETAPV and STEG has been charged the same price for purchased gas and royalty gas. These arrangements are far simpler, and allow ETAP to adjust gas prices through the fund that stabilises oil product prices. Calculations made by the mission indicate that the target has been reached in 1987-'; for that year, STEC paid on average a higher price for royalty gas than the price paid by ETAP for purchased gas. 15. Domestic prices of oil products can be compared to international levels as follows: Evolutlon of Domestic Prices of Products in Relation to CIF Prices Domestic Prices CIF Prices Dinars/TOE US$/TOE US$/TOE 1982 1987 % 1982 1987 2 1982 1987 % LPG 151 192 5% 243 228 -1% 289 175 -101 Diesel Oil 136 283 16% 220 336 9% 272 142 -121 Fuel Oil 63 92 8% 102 109 1% 171 102 -10% a/ Early 1982 and early 1987 Source: STEG, Gas Directorate, May 1988 In dinar terms, the policy followed over 1982-87 has been to increase moderately the price of LPG (on social grounds), and increase at a faster rate that of diesel oil. The price of fuel oil was increased at an intermediate 1/ The "fiscal fee" (forfait fiscal) compensates the Italian party for the 5.25% being taken at the Algerian border, and not the Italian border. It is therefore equivalent to 5.25% of the royalty gas taken at the Algerian border. 2/ ETAP is the national company in charge inter alia of oil imports. 3/ From the total payment paid by STEG for gas (net of subsidies received from the government), the theoretical cost of imported gas at the official price was deducted. The balance was divided by the volume of royalty gas, in order to establish its theoretical price to STEG of royalty gas. ANNEX 3 Page 8 of 10 rate. The increase in US$ terms, except for diesel oil, are less apparent in view of the appreciation of the US$. Of course, with the collapse of oil prices in 1986, CIF prices declined on average by 10% over 1982-87, so that domestic prices are now above import parity for all products; for instance, the price of fuel oil was 18% above import parity in early 1987 and 552 in early 1988. All in all, considering the pricing policies in effect when the loan was approved (the price of fuel oil was about 33% of its opportunity cost), considerable progress was achieved in the restructuring of petroleum products prices with a view to stopping their subsidization. B. Gas Tariffs 16. The behavior of domestic gas prices when compared to liquid fuels to be substituted can be summarized as follows: Comparison of Domestic Gas Prices and Alternative Fuels (US$/TOE) 1983 1984 1985 1986 1987 1988 ' LPG 257 218 236 240 237 246 Diesel Oil 234 218 264 323 35& 375 Fuel Oil$' 125 108 117 121 123 128 Gas - Domestic 197 166 163 166 168 179 Gas - Commercial 197 166 163 166 150 145 Gas - Industrial - 98 107 111 114 120 Gas Import Price 156 142 139 96 78 84 a/ Domestic prices expressed at mid-year exchange rates. b/ Prices in effect since April 29. 1988, reflecting the end-1987 exchange rate. c/ On the basis of posted domestic prices plus US$10/TOE to reflect the cost of transport (to be paid separately by the user). Source: STEG, Gas Directorate, May 1988. As the above table indicates, the prices of LPG and diesel oil (i.e. the domestic and commercial gas markets) were always considerably higher than the price of gas, on a calorific equivalent basis, so that (excluding other charges, including connection cost, monthly charge, etc.), users had an incentive to switch to gas. With respect to fuel oil replacement (i.e. the industrial market), the policy in place was to price natural gas at the posted price of fuel oil, so that in effect, the end-user would save on the transportation cost (equivalent to US$10/TOE). Furthermore, since 1986, the domestic price of gas has been considerably higher than its opportunity cost. 55 - ANNEX 3 page 9 of 10 17. Until June 1987, pricing policies for imported gas had not been formalized. Regarding the industrial market, STEG had applied the calorific equivalent price of fuel oil, as explained above, while in relation to the domestic market (i.e. largely LPG replacement), STEG had maintained the tariff in effect for town gas. In June 1987, a new structure of gas prices was introduced by decree, providing for 3 tariffs (high, medium and low pressure), and including a fixed charge, a capacity charge (not applicable to low pressure customers) and energy charge. They appear at Appendix 2 of this Annex. This structure is appropriate since it segregates the fixed and variable costs of supplying gas to different consumer categories (the appropriateness of the tariff structure to the long range marginal cost of supply remains to be ascertained). 18. An important outstanding issue, however, both from economic and financial standpoints is the tariffs to be charged for gas used for power generation which, in turn, has major implications not only for the financial position of the gas activity but also for the power sector (particularly power tariffs, optimization of investments in generation -'). STEG is not only a buyer and distributor of natural gas, but also the major user of gas in Tunisia. Gas used for power generation results therefore in an internal transfer within STEG, for which the price can be set arbitrarily, with restricted financial or economic implications. As agreed with the Bank, STEG now prepares separate accounts for the imported gas activity, for which the transfer price it applies is the financial price of fuel oil (official price less 10% production tax from which it is exempted). This practice would not be unreasonable if gas were used fully as a fuel substitute; as a matter of fact, about 10% of the gas was used in gas turbines in 1986 and 1987, but in 1984, in excess of 50% of the gas was used for this purpose. Under such circumstances, the proper transfer price would have been that of diesel oil, and not of fuel oil. C. Conclusion 19. Considerable progress was achieved in the domestic pricing of natural gas, as well as oil products, as they are all sold above their opportunity costs. It would also appear, prima facie, that the relative price of gas 1/ Power plants (gas turbines, steam plants) which can operate on natural gas represent some 90% of the installed capacity in Tuaisia. In the South, STEG acquires considerable albeit declining quantities of gas from the El Bormah field (about 260,000 TOE in 1987) at virtually no cost; the appraisal mission was aware of the issue but did not raise it since El Bormah's gas production was anticipated to cease in 1986 (SAR, para. 4.10) with the depletion of the reserves - El Bormah gas production is now expected to remain above 100,000 TOE until 1994. There are therefore valid grounds for concern that Northern gas will be used also to subsidize the power sector, particularly since the royalty gas is acquired "free" (but at the very real cost of foregone compensation from Italy). - 56 - ANNEX 3 paso 10 of 10 (excluding the one-time cost of connection, and fixed monthly charges) is adequate to give appropriate incentives to present users of liquid fuels to the vicinity of the pipeline network to carry out the conversion. As a result, the pricing targets agreed upon with the Bank have been attained. 20. On the other hand, the issue of gas pricing for power generation remains to be addressed fully. In particular, it would not be appropriate to price gas at its fuel oil equivalent, when in reality it is used in gas turbines. STEG officials are concerned about the financial implications of such a pricing policy since the Government might decide to price gas to STEG according to end use. On the other hand, it would have possibly modified STEG's load managemement practicies, which would have been beneficial to the economy. ~57 .. AlMl! 3 Appendix 3 Intarnational Prices c-f Irnported Gos und Uquid tle (Us$4sluf sug - lou - 150 100 - 48 .F- Jan-o 2 Jon-fi 3 Jon--64 Jun--65 jon--i 5 Jen-87 an-c 8 A l iml n rp 4. LP 3 ' N 8 i -58 - ANNEX 4 Page 1 of 2 DETAILED PROJECT DESCRIPTION The project consists of four systems as follows: A. Tunis System 1. Tunis System which is the largest of the four consists of: (a) a measurement system with 300,000 m3 per hour capacity at the off-take point in Zibra, including four measurement rumps equipped with electronic and mechanical measurement instruments; (b) 55.3 km 20" high pressure (75 bar) pipeline downstream of the measurement center for supply of gas to Tunis area; (c) a city gate station for primarily reducing the gas pressure to 20 bar; and (d) a 30 km 20", 20 bar distribution main downstream of the city gate station with seven regulating stations for supply of gas to: two power plants (TAG and Rades), a medium pressure n-w network, an old cast iron network (converted from town gas), and an old gas works. The gas works which was previously manufacturing naphtha-based town gas is now using natural gas instead of naphtha. This plant is supplying town gas to the remaining 5,000 consumers which are being gradually converted to natural gas. B. Sousse System 2. This system which has a common measurement center with Tunis consists of: (a) a 70 km 20" high pressure spurline downstream of Zibra measurement center to M'Saken; (b) a 10 km 16" high pressure pipeline between M'Saken and Sousse; and (c) service line to the Sousse power plant, two distribution mains, one in North Sousse and another in the South for supply of gas to hotels and domestic consumers. - 59- ANNEX 4 Page 2 of 2 C. Cap Bon System 3. The Cap Bon system includes: (a) a measurement center with 4 rumps and 100,000 m 3 per hour capacity; (b) a 10 km 10" high pressure pipeline downstream of the measurement center to Korba; (c) a 44 km 10" 20-bar pipeline between Korba and Hammamet; (d) service line for supply of gas to Korba gas turbine power plant; and (e) medium pressure distribution pipelines in Nabeul and Hammamet areas for supply to small industries and hotels. D. Kasserine-Tadierouine System 4. This system consists of: (a) a measurement center at the off-take point in Kasserine with 2 rumps and 100,000 m2c meters per hour capacity; (b) 90 km 8" high pressure pipeline downstream of the measurement center to Kasserine and Tadjerouine; and (c) service lines for supply to a gas turbine power plant and four industries in Kasserine and Tadjerouine. Second Natural Gas Pineline Proect tLoan 1864-TuM) Disburseent!PerormanceAnal Ysis (US$ Mi Ion) SAR_ Actual Ata Period Endine Estate Amnded Artual As % of e,Sed 1980/81 September 30. 1980 4.0 December 31, 1980 10.0 March 31. 1981 15.0 June 30, 1981 20.0 1981/82 September 30, 1981 23.0 December 31. 1981 28.0 March 31. 1982 32.0 5.0 6.6 21 132 June 30. 1982 34.0 9.0 8.2 24 91 1982/83 September 30, 1982 35.0 12.0 10.2 29 85 December 31, 1982 36.0 16.0 12.5 35 78 March 31, 1983 36.5 20.0 13.1 36 66 June 30, 1983 37.0 25.0 16.1 44 64 1983/84 September 30, 1983 28.0 16.8 45 60 C December 31, 1983 28.5 18.0 49 63 March 31, 1984 29.0 18.1 49 62 June 30, 1984 30.0 18.1 49 60 1984/85 September 30. 1984 32.0 18.7 S1 58 December 31. 1984 33.0 19.4 52 59 March 31. 1985 34.0 20.9 56 61 June 30. 1985 35.0 21.3 58 61 1985/86 September 30, 1985 * 27.0 27.0 21.8 81 81 December 31. 1985 22.3 83 83 March 31. 1986 22.8 84 84 June 30. 1986 22.8 84 84 1986/87 September 30, 1986 23.2 86 86 December 31, 1986 24.4 90 90 March 31, 1987 25.4 94 94 June 30. 1987 26.2 97 97 1987/88 September 30. 1987 26.7 99 99 December 31. 1987 26.9 100 100 March 31. 1988 27.0 100 100 $10 million of loan proceeds was cancelled in September 1985. TUNiSIA SECOND NATURAL GAS PIPEUNE PROJECT Implemntation Chart 1980 1981 1982 i1m3 1984 195 16 987 01 03 Os 04 01 02 0301 021 02 03 04 01 02 03 001 1 02 03 040 O0» 01 0 03 04 01 02 03 04 MATERIALSAND i ir ry ,..EMGem Tt (1) TUNISOUSSE l =m (2) TADJEAOUUNE .. 1 •a•a=,s (2 m~maew (3) G~FS (4) CAP ODM Riummmmumm (5)1*4 DI" "TR" B• T *O* (1) NEWOCGNSUMERS -- Si=mm m=r=raaa=a (2) TOWNAS CONSUMERS = u m- - ecaaa a a- sm -=a==u u ae=m EKMf4301W, Adig - - - - . (0B) .Oenn 0' - 62- Ton1s14 Ann,, 7 Second Iatural as Pipeline Project Pag of 3 S7ES - leported as Gperations Incom Statesents (Dinar§ Thouands 1982 1983 194 1985 1986 1987 Appresal Actual AIppraIsal Actuel Appratsul Actual Appreisal Actual Appr1ta 8tute A iprsjal ktuel salts of Sm ('000 t0) STE 346.0 320.0 557.0 326.9 822.0 548.5 1,065.0 204.4 1,030.0 776.3 other 489.0 510.0 588.0 51.7 973.0 102.0 1,095.0 117.2 1,370.0 118.0 835.0 860.0 1,145.0 378.7 1,795.0 650.5 2,160.0 321.6 2,400.0 894.4 Averae elling Price (I/ta.) '7Er 36 44 53 73 64 79 77 85 92 88 Other 36 44 53 94 64 94 77 % 92 JUA melghted Averag 36 44 53 76 64 81 77 89 92 90 Avera Purchase Price 58 63 68 99 73 96 79 70 85 76 Rvenes fras fales StEO 12,532 14,078 29,496 23,913 52,407 43,219 81 776 17,473 95,110 68,447 other 17,712 23,757 31,138 4,846 62,034 9,559 84,080 11,298 126,506 12,003 Revenues fror Sales 30,244 0 37,835 60,634 28,759 114,441 52,778 165,856 28,771 221,616 80,450 Subsidies 25,098 23,199 24,584 6,454 30,280 7,878 7, 774 uther Operating Revenus 239 204 710 1,029 Total Revenuus 55,342 61,034 85,218 35,452 144,721 60,860 186,630 29,481 221,616 81,479 E= rchaus Cst ,4 53,922 77,545 34 603 131 286 56,476 170,618 22,220 204,744 69,471 1~888tålleft eftt k,om 1,074 I,f44 I,N34 2,'29 1,538 3,102 0 3,6m6 0 Total Operating Expe 52,312 58,002 82,209 39,656 139,260 61,611 180,760 28,475 215,896 79,006 Operating Incom. 3,030 3,032 3,009 (4,204) 5,461 (750) 5,870 1,0^ 5,720 2,472 Interst 2,079 2,588 3,242 2,054 3,858 2,442 3,918 2,298 3,544 2,502 Eschange Losss 2,793 (2,297) 1,793 (1,927) Met lnces 951 444 (233) (9,051) 1,603 (895) 1,952 (3,084) 2,176 1,898 RDR en Rev. Assats 8.01 8.01 8.02 -25.91 8.02 -2.32 8.02 2.61 8.01 5.92 - 63 - Second Natural Oas Pipeline Project Page 2 of 3 STEO - loported Oss Operations Sources and Applications of Funds Statesets (iners Thousands) 1992 1983 1984 1985 1936 1987 Appraisal Actual Appraisal Actual Appraisal Actual Appraisal Actual appraisal Actual Appressal Actual Sources of Funds Net Inceme Before late 3,030 3,033 3,008 (4,204) 5460 (1SO) 5,170 1,006 5,720 2,472 Depreciation 2,533 2,723 2,913 1,636 5,137 1,019 5,792 2,391 6,139 2,587 Internal Cash Seners 5,563 5,736 5,921 (2,368) 10,597 1,069 11,662 3,397 11,859 5,059 Long Tere Debt raing 6,200 6,700 14,650 5,045 6,650 2,321 6,500 1,700 2,038 Consonr Cotributions 1,639 819 19 1,011 STE8 Contributions (3,024) 7,294 6,455 (1,060) Increase in Accounts P (2,482) 1,122 3,903 13,617 327 (4,903) 4,216 (7,985) 4,710 6,054 Increase in Capital 0 0 0 0 Total Sources 11,281 13,578 24,474 15,509 17,574 6,600 22,378 3,726 16,569 15,110 *ass amm ass*= s... " Sa Uses of Funds Capital Expenditures 5,104 7,359 15,301 6,093 S,000 3,076 6,400 4,219 3,336 Increase in ventorle 9 237 27 669 29 653 31 420 33 104 Increase in Accounts 8 2 590 612 1,936 4,730 4,561 (2,545) 4,363 46,626) 4,734 (168) Increase in Cash (t0) 1387) 230 38 551 657 Increase in Current As 2,493 462 2,193 5,599 4,978 (1,692) 4,945 (6,406) 5,624 (64) Interest Lan2 T or eb 2,079 2,568 3,242 2,054 3,838 2,442 3,918 2,296 3,544 2,302 eleburseten1 Log Ter 1,600 3,169 3,738 1,762 3,738 2,974 7,115 3,615 7,401 9,337 Debt Service 3,679 5,757 6,980 3,816 7,596 3,416 11,033 1,913 10,945 11,838 Total Uses -- -- -- -- - - -- - -- - 11,281 13,578 24,474 15,509 17,574 6,600 22,318 3,726 16,569 15,110 *ass" smm mm a... se=n. mm ino.a Debt Service Coverage 1.5 1.0 0.6 -0.7 1.4 0.2 1.1 0.6 1.1 0.4 Wp-88 - 64 - Tunisia Second Natural Uas Pipeline Project Page 3 of 3 STES - laparted Gas Operations Balance Sheets (Diners Thousands) 1982 1993 1984 1985 1986 1987 ASSETS Appraisal Actual Appraisal Actual Appraisal Actual Appraisal Actual Appraisal Actual Appraisal Actual Gross Fixed Assets 39,072 42,002 14,354 44,942 36,976 60,062 13,135 91,697 57,390 97,188 65,95 Less: Acc: Dep. 2,533 5,446 6,327 8,740 6,400 14,409 10,896 21,223 13,819 28,63 14,65 Net Fixed Assets 36,539 36,556 8,027 36,202 29,577 65,593 42,239 10,464 43,571 66,552 49,319 dark in Progress 1,785 9,279 29,394 25,226 14,408 - 3,264 - 6,301 - 3,341 Current Assets Inventory 94 31 1,496 334 9 ,9 1 ~ 44 47 Accounts Receivable 2,5 S,o 2 765402 9,6% 1 14, 02 t. 7 ** S-T. Deposits 655 469 34 698 40 1,086 49 1,637 46 2 ,494 19 Subtotal 3,539 4,001 3,406 6,194 6,987 11,172 7,079 16,117 5,185 21,741 5,227 Other Assets 4,699 4,717 4,734 222 116 Total Assets 41,863 49,835 44,526 67,624 56,689 76,765 57,336 86,561 5$,279 90,293 58,003 ""am3 63833s WSM=3 33333 33=33 3333z 33383 33 nu33 Mon"3 333 Mo333m Liabilities and Equity Equity Capital 10,000 10,000 7,500 10,000 7,500 10,000 7,500 10,000 7,500 10,000 7,500 Revaluation Reserve 3 935 6,809 4,604 10 017 5,094 14,317 4,937 18,580 9,134 22,807 10,206 Retained Earnings 490) (45) 0 1279) (9,051) 1,323 19,946) 3,275 (13,030) 5,451 (11,132) STES 1,567 (1,458) 3,836 12,291 11,230 Total Equity 13,445 16,764 13,670 19,738 2,077 25,640 10,327 31,855 15,894 38,258 17,604 Long Tere Debt 21,931 24,793 17,576 35,705 24,275 35,240 19,524 34,339 20,303 29,138 12,955 Current Liabilities Accounts Payable 3,416 4,540 5,593 9,443 17,649 8,770 14,604 12,96 11,560 17,696 19,559 Current Portion of L 3,169 3,736 31 3,738 1,832 7,115 3,063 7,401 2,487 6,201 1,576 Subtotal 6,587 6,276 5,624 12,16 1 19491 15,665 17,947 20,397 14,046 23,897 21,135 Other 7,656 10,856 9,617 5,035 6,109 Total Liabilities and Eq 41,863 49,935 44,526 67,624 56,689 76,765 57,336 66,581 5,219 90,293 56,003 3.8.88 33*=. 88.. 333 33383 3 33838 3a3 ..... sm3 Current Ratio 0.5 0.5 0.6 0.5 0.5 0.7 0.4 0.6 0.4 0.9 0.2 ebulebt 4 Equity (1) 65? 631 561 671 931 62? 69? 57? 56? 47? 451 08-Sep-99 擺許騙吃 綢闢呂矓譽攤遝彎，”•號，“露 劉闢露鰓蠱養首曇―”•黑，札， 邊―露名離蠱糁舀藝―。•號零“蠶 織―認名矓黑養口藝l。•魚零枓認 夠峰名矓藝養養藝i”蠶發零料認 劉―露呂矓蠱糁養藝！”•翁響鰓釁 目―。名矓里糁貧藝―”•號零“登 劉爐呂離雙蔆亂藝―”•號零料離 目―發名矓里藕邊騙―&8焜“囀纔 自降名鰓蠱養劉藝―”•名”&& 觀陽寫矓豐響劉讓―&”視”料法 男隱•矓望養糅藝“，號”私翅 U禺造l華寫巒纔鳥發綺藝禹號響號網視翁擊 認屆馴―總•藝發編藝審著禺黑斗賽為啊規認 互劍霎暑織―藝寫遞震視藝驕藝“胎富竇跚門發韋 Hd遲訪賽I賽名邊露嘗蔆規絕騙零認，雲啊魚養 。倡馴蓄編奮•酒呈季舀鬍盡翅親縱•召，規畏法 觀視購話賽購芻遞攙彎蘊雙”養”胞萬，發群 劉擊鰓居蓬養響牘姿劉擊革翅奮”蠶’，發婦 目涌頸寫露響響選趁劉遲狗禹馳，&&,”各 劉”藝話藝。荊藝 男織藝藝”〕翁 目蘊巷―讓 賽露奮―豐 ,l;_ 萬＿纏審二藝露規煙言奮渥壇！ ,!;!!!!!;!!;!!‘。！;;&,，。，,; •66一A潤股胞XS 讓，號言，鳥雙””擊藝織綢垂奪Pase之”f& 劉，,&,&,&”寧碧織潤舞響 胡，,,,&，。。參藝藝綢舞藝 潤，,,,&，。。華邊藝織賽藝 織，,,,,,”。華邊藝賽藝擊 寫，,,,&,&”寧藝藝綱蘿擊 劉，,,&&&&”讓藝醫編靈導 觀，,,,&，。”讓藝蔥織藝審 賽，,&,&,&”症參蘊網萋毒 弱，,,&&,”。待壅蒙網藝攤 劉，。，,&,&”囊蠶專開藝獲 劉，,,,&,”擊邊當響潤萋藝 。。。”,&&,’藝韋醒藝網奪萋 三」劉，寫言，號寫’彗蘿參響荊藝提 。纏蒙碧獨’規，，鳥雙”藝巷藝鬍網藝響 萬蠶蔆目劉，賽震，馳豐”釁擊羅話馴響藝 透攤劉織寫鳥規餐鳥遷藝響雜審啊曇賽 。。。，,,&，。變．審響賽禹藝藝 賽，。。，&”萋這邊鑒蚤啊藝藝 賽，。。”&”讓織藝摻。界雜藝 鰓視‘朧’&&&&”。’1‘藝 劉―。薑 編―”藝 劉―。奮雙g 畸I。萬＿婦 呂必 號三 奮？古。騷 醒萬言．言萬言：＿日日日叢蘊 不革I權：甚萬審權：&I廈蔆豐。邊甲 星萬瘁選響！屆j壇讓．盞―仕言江g森論 ．亡三1廈11看：三】蠶暹蓬遼i-i濫邊11權 自牌牌”雲蠶寫屆騰轎。雲’‘、惡婪―露•湯邊韭遝， :&:”遲J藝―；一盒 ”蓬邊―蓬甚 MAP SECTION IBRD 14849R1 M r F A V é N (OTabarkia ICAP i9i - - Nohegi ( E!Kef Tderovine 0Kafrouan \Deua \ 0Dn A LGERI A El DSomo- K.ss.rin. } WO 64 ~ ~ - -%:Gaso Chott el Jerid TUNISIA FRNENATURAL GAS TRANSPORTATION NETWORK - -Fture PIpenes, L.org Term PossthIfes . ExtIng Trans-Medierranean Plpelines Other Existng Pipelines c.omss.rSt... Solt Lakes * National Copital --. -- Internatonal londarYes ALGERIA 1. 9.wL OCTOBE 1988