NAL REPORT R1 FIN R UEL AVA FU LITY AND OPPO AILABIL ORTUNI ITIES FO OR COS DUCTION ST RED N ent: Clie he World Bank Th B p Group ject: Proj ibya: Supp Li porting Elec ctricity Sec ctor Reform ) Task B – Consultan m (PI54606) es ncy Service bject: Sub UEL AVAIL FU LABILITY & OPPORTU UNITIES FO OR COST REDUCTIO R T ON REPORT e: Date 8/12/2017 18 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written approval TRACTEBE : Avenue Ariane 7 – 1200 EL ENGINEERING S.A. – registered office: 1 GIUM Brussels - BELG 12 639 681 – RMP/RP VAT:BE 041 PR Brussels: 0412 63 39 681 – Bank accounnt - IBAN: BE743751000843707 – BIC/SWIFT: BBRUBEBB A: SUPPORT LIBYA CTOR REFORM (PI54606 TING ELECTRICITY SEC ANCY 6) TASK B – CONSULTA SERVICES AL REPOR FINA RT R1 FUEL ABILITY & OPPOR L AVAILA S FOR CO RTUNITIES DUCTION OST RED BLE OF TAB NTENT O CON TS   UTIVE SUMMARY ............................................... EXECU .................... .................... ...... 3  .................... TRODUCTIO 1.  INT ON ..................................................... .................... .................... ...... 6  .................... OUNTRY OV 2.  CO VERVIEW ........................................... .................... .................... ...... 7  .................... 1.  2.1 ENERG GY INSTITUT TIONAL FRA AMEWORK. ................... .................... .................... ...... 7  2.  2.2 RAL GAS MA NATUR ARKET ........ .................... .................... .................... .................... ...... 8  3.  2.3 TRICITY MAR ELECT RKET .......... .................... .................... .................... .................... .... 14  This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written approval ATURAL GA 3.  NA A AS SUPPLY ALTERNAT IVES FOR P POWER GEN NERATION. .................... . .... 22  1.  3.1 ODOLOGY...................... METHO .................... .................... .................... .................... .... 22  2.  3.2 FOREC CAST UNDER CURRENT T CONDITIO ONS. ............ .................... .................... .... 23  3.  3.3 ALTER RNATIVES TO O IMPROVE E NATURAL GAS AVAIL .................... LABILITY. ... .... 26  OMPARISON 4.  CO N OF SUPPL LY ALTERNA ATIVES. ...... .................... .................... .... 39  .................... 1.  4.1 CAPEX X & OPEX. ...................... .................... .................... .................... .................... .... 39  2.  4.2 P FUEL PRICES. ......................... .................... .................... .................... .................... .... 40  3.  4.3 CTED SAVIN EXPEC NG FROM US SING OPTIM MAL FUEL. .. .................... .................... .... 40  4.  4.4 NTIAL REDU POTEN UCTION OF CO C 2 EMISSIO ONS. ........... .................... .................... .... 43  UIDELINES TO 5.  GU TIZE THE US T PRIORIT RATION. ..... SE OF GAS FOR GENER .... 44  .................... GHLIGHTS. ......................................................... 6.  HIG .................... .................... .... 45  .................... NNEX. ................................................................... 7.  AN .................... .................... .... 46  ....................     1004 P.010556.1 20171215 2 /61 RESTRICTED EXECUTIVE SUMMARY The present document constitutes the “Fuel Availability and Opportunities for Cost Reduction Report” included in Task B, which objective is to study potential options to reduce power generation costs and greenhouse gas emissions while increasing the reliability of the system1. This Report has been developed to provide a guideline into the LNG Options Report by identifying the areas for future investment to best meet the needs for demand growth and fuel distribution as economically as possible subject to technical viability that will be addressed in the LNG Options Report. Libya is located in northern Africa, bordering the Mediterranean Sea, and has a population of around 6.6 million (2017). In 2016, it ranked as the third largest oil producer (i.e. 626mb/d) in North Africa (after Algeria: 1,579mb/d and Egypt: 691mb/d). Its total primary energy consumption is entirely based on fossil fuels. The outlook for the coming years indicates that demand for fuels would probably grow driven by power generation. Since the latter could have a strong impact on the country financial situation it should be properly and timely addressed. In this regard, the World Bank has contracted Tractebel-ECS-TAQA consortium to undertake the Task-B. “Natural Gas Availability, Cost Reduction and LNG Import Options” Study, as part of the Project “Libya: Electricity Sector Reform Technical Assistance”. The objective of this Report is to describe the assessment undertaken on the natural This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written gas and electricity markets in order to determine potential options to reduce both the power generation costs and the greenhouse gas emissions while improving the reliability of the power system by increasing the natural gas availability. It has been developed to provide a guideline into the LNG Options Report. The General Electric Company of Libya (GECOL) and the National Oil Corporation (NOC) are the state-owned companies in charge of running the power system and the oil and gas operations within the country, respectively. This study would provide them valuable insights and data that could be used as a basis for the preparation of their plans for energy cost reduction, increased efficiency, and energy market reform. While Libya is endowed with significant natural gas reserves, current production is below its historical levels. In fact, in 2016 Libya’s natural gas proved reserves attained 53 TCF (see ‘BP Statistic Review of World Energy 2017’). However, according to local assessments this value could go up to over 70 TCF. Natural gas production during the same year averaged ~2100 mmscf/d; almost 40% lower than 2010. Approximately 720 mmscf/d of natural gas was used at the upstream level (oil operations, injections, flaring, etc.); while the remaining was injected into the gas system. The existing Libyan gas transportation infrastructure connects the main cities to the gas production areas along a gas-pipeline system. There are two distinctive gas network areas connected by the Coastal Pipeline. However, due to compression and supply limitations, these areas operate as separate entities. Gas flows from West to East up to Misurata city where the system experiences a pressure constraint; while from East to 1 It is worth noting that this report comprises a preliminary valuation of the alternatives. GEB-OFF/4CT/0502978/100/00  20161020 3 / 61 RESTRICTED West gas flows up to the Raf c R Lanuf complex ue to suppl du e two ly restrictions (see the al, dotted lin vertica m nes on the map.) nd 60% of th Aroun e (after ups he available s) natural ga stream uses ted into the local as is inject gas sy ystem whilee the remaining 40%2 is exported a the Green d to Italy via nstream pipeline, om the Melli which departs fro itah compleex. Power plants rep present the main natural gas con nsumer and d would be the driver for f its demand growth. Although over the la ast years, natural gaas has bee ng its en increasin penetration into the genera going from 37% ation mix (g 3 in 20110 to 74% in 2016); hhence buting to reducing contrib r the generatioon costs, there t r improvem is still room for ments. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Based d on prelimminary estim mations, Lib bya could have h saved approxima M ately 200 MUSD only in s during 20163. n liquid fuels Accor e most rece rding to the ent projections, electricity deman nd is expec ep on cted to kee growinng in comin D ng years. Depending o the various scenar on rios, growth h rates could go from ~5% to ~8 8% (CAGR) until 2030, reaching g circa 60 TWh to 80 TWh. On n the ary, natural gas produ contra uction projeections showw that availability will increase in the t short term art to fall aft but sta verall, CAGR rate would decrease ter 2020 (ov e at -2%). As a r ese project result of the uld be expe tions, it cou ected that under curren nt conditionns the systemm operation n would bee tight and els would be d liquid fue T b largely required. These significant amounts of liquid fuels wo ould probab bly be imp p ported (or prevented t be to export ted, should them be loocally produ s for the co uced), resulting in significant costs ountry (betwe een 3.8 and D/year in ave d 4.7 BUSD erage). Given this situat C tion, the Consultant a assessed f four different alternatives to incrrease al gas availa natura he power ge ability for th eneration sy ystem (by modelling m bo ctricity oth the elec tch and the dispat e natural ga as flow) as part of the e exercise to help det termine thee final um solution optimu n as defined r LNG Optio d in the later ons Report: 2 o the increase in Due to n n the domestic natural gas requ uirements and faall in production, NOC has man ate with naged to negotia eduction of expo ENI a re alf (in 2016). orts to almost ha 3 ming the replacement of liquid fu Assum uels for LNG, bu g into account th ut without taking ucture requirements for he new infrastru g. so doing GEB-OFF/ 0 /4CT/0502978/100/00 20161020 4 / 61 STRICTED RES A- Devoting all the local gas production to the power generation system by expanding4 the Coastal Pipeline gas system and reducing gas exports when necessary. B- Converting the existing on-shore liquefaction terminal located on Marsa El- Brega to a regasification terminal, and expanding the Coastal Pipeline. C- Constructing an off-shore regasification terminal (FSRU) next to Khoms and expanding the natural gas transportation system. D- Constructing an off-shore regasification terminal (FSRU) to connect directly to the most efficient power plants located in the West (rather than connecting to the existing Coastal Pipeline). In order to compare the different alternatives and determine the possible savings of using the optimal fuel, total power generation fuel costs were estimated based on: i) The investment and operational costs - CAPEX and OPEX - of the new infrastructure, that is, regasification terminals and transport capacity expansion; and ii) The fuel prices. The results indicate that, in the short term, reducing the exports to Italy and increasing the Coastal Pipeline capacity is a good immediate solution to reduce liquid fuels5 consumption for power generation. However, in the mid- to long-term this solution proves short to offset the fall in local gas production. Thus, this alternative does not result in being the alternative with the largest saving. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written In the mid-term (from 2020 to 2028), replacing liquid fuels by LNG would deliver the higher savings in generation costs, although the required expansion in existing transportation and import infrastructure would reduce the savings. Given that, on one hand, the greater fall in natural gas production will be observed in the West, where a large part of the most efficient power plants are located; and, on the other hand, the Mellitah – El Khoms pipeline has the largest capacity, the most economical alternative is to place the LNG import terminal(s) in the West somewhere around Khoms. Total savings under this alternative have a net present value (@10% discount rate) of 8 to 10.5 BUSD depending on the electricity scenario In the long term (after 2028), the country could either move forward with an onshore terminal or end LNG imports depending on the evolution in the natural gas exploration and exploitation. The decision would need to be taken around mid-´20s 4 In this report expanding the pipeline could either be additional compression or loops not new pipeline trenches. In the LNG Option Report the most appropriate solution for expanding the pipeline to meet demand will be studied. 5 NOC is already partially implementing this solution. GEB-OFF/4CT/0502978/100/00  20161020 5 / 61 RESTRICTED 1. INTRODUCTION The World Bank Group has provided a Terms of Reference document outlining the key requirements for the provision of consulting services for Selection # 1227307/ Libya: Supporting Electricity Sector Reform (P154606) - Task-B. Fuel (Natural Gas) Availability, Cost Reduction and LNG Import Options Study. The study will provide data to both GECOL and NOC that could be used as a basis for the preparation of their plan for energy cost reduction, increased efficiency and energy market reform in Libya. The present document constitutes the “Fuel Availability and Opportunities for Cost Reduction Report” included in Task B. The objective of this Report is to review the natural gas and electricity markets to determine potential options to reduce power generation costs and greenhouse gas emissions while increasing the reliability of the system through the increase of natural gas availability. It is worth noting that this report comprises a preliminary valuation of the alternatives. This Report has been developed to provide a guideline into the LNG Options Report by identifying the areas for future investment to best meet the needs for demand growth and fuel distribution as economically as possible subject to technical viability that will be addressed in the next report (LNG Options). This Report is based on the discussions that took place during the meeting (held in Tunis in February, May and October) and the subsequent information provided by This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written GECOL and NOC. Additionally, the base line data / assumptions for the electricity sector forecast was established in the Sector Rapid Assessment and further analysis conducted by Task A consultant: PwC6 Further technical detail information regarding the characteristics and possibility to expand transportation system and connection of existing and future power plants as well as the possible LNG terminal locations, is covered in the second report of Task B, “LNG Import Options” Report 6 In addition to Task B: “Fuel (Natural Gas) Availability, Cost Reduction and LNG Import Options Study” the World Bank is undertaking three other assignments / tasks, at the same time, to support the country’s electricity reform. GEB-OFF/4CT/0502978/100/00  20161020 6 / 61 RESTRICTED 2. COUNTRY OVERVIEW Libya is located in northern Africa, bordering the Mediterranean Sea, and has a population of around 6.6 million (CIA World Factbook, 2017). The largest city and capital, Tripoli, is located in western Libya and contains over a sixth of Libya's population. The other large city is Benghazi, located in eastern Libya. Libya is considered an upper middle income country. However, its economy is one of the smallest in Africa and depends mainly on the oil and gas (O&G) sector, which accounts for 60-80% of total GDP and about 95% of total fiscal revenues and exports. During the last years, political instability and the drop of oil prices have affected the country’s economy in general and the energy sectors in particular. However, the economic and social outlook could be auspicious. Libya is the largest oil producer in North Africa. Total primary energy consumption and installed capacity is 100% based on fossil fuels. Recently, natural gas has been increasing its share in the energy matrix. The outlook for the coming years indicates that it could continue to grow mainly driven by power generation. Thus, Libya would require an increase in natural gas production and/or imports, as well as a boost in infrastructure investments. 2.1. ENERGY INSTITUTIONAL FRAMEWORK. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written There is no official regulatory authority in place in Libya today and energy markets are run by the National Oil Corporation – NOC – and the General Electricity Company of Libya - GECOL. In the O&G sector, NOC, established in 1970, is the main company and is in charge of exploration, production, transportation and commercialization of O&G. NOC carries out its activities through its own affiliated companies or in association with international companies, such as ENI, Wintershall and Repsol, among others. NOC owns but does not operate refining and O&G processing companies - such as Zawia (northeast) and Ras Lanuf (north centre) - ammonia, urea and methanol plants; the Ras Lanuf petrochemical complex and the gas processing plant. In 2007 the General Gas Transmission and Distribution Company - GGT&D was created with the objective of separating upstream from downstream activities. It is specialized in the construction and management of the natural gas distribution network. In regards to the electricity sector, GECOL was established based on the law number 17 in the year 1984. It is the only vertically-integrated power utility, hence responsible for not only the generation, transmission and distribution of electricity, but also the planning, development, O&M and dispatch of the power system. In addition to GECOL, there are nine other companies; most of them controlled by GECOL, involved in the market mainly as service providers. In addition, the development and implementation of renewable projects is carried out by the Renewable Energy Authority of Libya – REAOL. GEB-OFF/4CT/0502978/100/00  20161020 7 / 61 RESTRICTED 2. NATURA 2.2 ARKET AL GAS MA pstream: 2.2.1. Up Accorrding to thee BP Statis w of World Energy, in 2016 Liby stic Review ya’s total prroved ves were 53 reserv 3.1 TCF. However, ac ssments this ccording to local asses s value couuld go r up to 70 TCF. Production in 2016 reached ound ~2120 mmscf/d of which ~960 aro mmsc ected for do cf/d was inje omestic consumption (t ng was used in upstrea the remainin am or exportted). Libya’s Na atural Gas Reserves 2000-2016] [2 ] 60 TCF 50 40 30 20 10 0 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written ce: BP Statistic Review of World Sourc W 2 Energy 2017 ural gas pro Most of the natu oduction coomes from three basin W ns: in the West; Ghaddamis e the prolif (where fic Al Wafaaa onshore field is loc cated), and Sabratah (where offs shore Essalam an Bahr E ated) basins nd Bouri fields are loca s; in the Ea e basin con ast, the Sirte ntains al associat severa ted and no on-associateed onshore e fields (e.g. Zahrah- abah, -Hufrah, Sa Raqubba, Nasser, Sarir, Saheel, Hateba, Esteklal, Alrada, etc.). N Natural s Productio Gas n on Location urce: US Ener Sou rgy Information Administration GEB-OFF/ 0 /4CT/0502978/100/00 20161020 8 / 61 STRICTED RES W The Western atural gas production na p accesses t ortation sys the transpo stem througgh an red to as “M Entry Point referr ern product Millitah” while the Easte Brega” tion does it through “B Entry Point. The natural ga as productioon entering each point for the foorecast period of s 2017 – 2030 is shown e following graphs con in the t basis of the inform nstrued on the mation ded by NOC provid C7. ern Natural Weste ecast l Gas Production Fore 2017-2030] [2 ] This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Source: S ased on NOC Own elaboration ba ern Natural Gas Produ Easte ecast uction Fore 2017-2030] [2 ] Source: S ased on NOC Own elaboration ba Thus, the overall Libyan gass production d in the graph below an n is depicted nd entails a CAGR o R of -2.3% over ecast period the fore d: 7 hat this is total gas Note th nd includes gas g produced an stream. s used in the ups GEB-OFF/ 0 /4CT/0502978/100/00 20161020 9 / 61 STRICTED RES an Natural Gas Produ Libya ecast uction Fore 2013-2030] [2 ] S Source: ased on NOC Own elaboration ba dicated by NOC, As ind N orecast is a conservative estimation of gas production this fo p b based on:  The continuation of the on-going ment of on-shore gas fie g developm e Oil; elds of Sirte  The comp s pletion of stage two developmen d hore El-Fare nt of on-sh eg gas field d (by This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 2020); and,  The seco ond stage developm ment of off f-shore of Bahr Ass salam field and ng structures developin y 2023). s A & E (by This p a projection assumes at there is enough sta tha ability and security s L in Libya der to in ord allow the return of international contraactors and service companies an nd that reqquired ble. funds are availab worth noting that over th It is w he last decaade there have been non significan nt investments in explor ration and exploitatio on. Taking into account the ac ctual condi ition of ex xisting es, the num facilitie mber of new b drilled an w wells to be nd the cons struction of new faciliti ies to proces ss the new volume, th he successf ment of the gas fields would requ ful developm uire at least 8 or 9 year rs, even wit th unlimited o investmen d access to nt. Furtherm more, OPEC C has estima M ated in its Monthly Oil Market Report of Aug gust 2017, that t s only one o there is oil-rig availaable in Libya a a. Thus, in addition to the t explorat tion and exploitation th w he country would need to t get hold of significan nt amount ofo equipmen he falling tre nts in order to revert th end in the ga as productio ng term. on in the lon Basedd on rough estimation ns, in order r to meet gas g demandd by the en p nd of the period 8 tments shou invest ast 4.000/5. uld be at lea .000 MUSD ion is succe D if producti essful. 8 This esstimation assum D mes a conservative Finding & Development Co ost of 2 USD/mcf. These costs sources s refer to the res required w O&G reservoir and the expen d to locate a new ng it throughout the lifecycle of the reserve. nses of exploitin GEB-OFF/ 0 /4CT/0502978/100/00 20161020 10 / 61 STRICTED RES 2.2.2. Midstream: e The existing Liby nsportation infrastructu yan gas tran ts the main cities to the ure connect e gas production areas otal gas-pip s along a to em length of peline syste o 5,080 kmm. There are e two ctive gas network distinc n areeas: East & West. These areas are connected by the e 34” Coast tal Pipeline system with ngitude of ~1,120 km. h a total lon atural Gas Pipelines Libya’s Na urce: US Ener Sou rgy Information Administration The eeastern sec e pipeline comprises ction of the c a section th es 246 km from hat stretche This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Marsaa El Brega (the East Entry Poin ghazi and was nt) to Beng w designned to trannsport around 410 mms ds Benghazi. There has scf/d toward s been cons or extending this sideration fo Coast st in order to tal pipeline further eas o reach the e cities of Derna D T and Tobruk. Howwever given the expecte ed demand in these cities it wouldd not be ecconomically viable to exxtend peline9. the pip Eastern and a rn Legs of the Costal Pipeline Wester S Source: NOC 9 Annex: “7.2 Preliminary Analysis See A s on Tobruk”. GEB-OFF/ 0 /4CT/0502978/100/00 20161020 11 / 61 STRICTED RES The western section of the pipeline spans 871 km from Mellitah (the West Entry Point) to Marsa El Brega. Two trenches of the pipeline can be identified:  From Mellitah to Tripoli and then to Khoms (222 km) with a nominal capacity of around 600 mmscf/d. It is worth noting that NOC is undergoing an upgrade to increase injection capacity at Mellitah in around 150 mmscf/d.  From Brega to Khoms (645 km) with a capacity of ~370 mmscf/d. Currently, gas flows to Mellitah treatment plant from southern onshore Al Wafaa field and northern offshore fields (Bahr Assalam, etc.). Hence, the natural gas injected at Mellitah runs to the East supplying power plants and industrial consumers as it is transported to Misurata city where the system experiences pressure constraints. Gas flows could go from Marsa El Brega (the East Entry Point) to the West, however due to supply restrictions, injection in this direction only reachs the Raf Lanuf complex. In the near future, according to NOC supply projections, as gas available in the East Entry Point would be larger than in recent years, higher flows to the West could be expected. The gas transmission pipeline was designed to handle a relatively low pressure: 780 psig (i.e. circa 53 bar). Such a low pressure reduces the operational flexibility across the network, specifically the ability to interconnect the East to West systems and vice versa. As a result, there is not one single gas system, but two; operating as separate entities. The pipeline network is not optimised to help maintain flow pressure (for instance, the connection pipelines to the power plants are considered too large: 34” diameter). This lack of optimisation is also due to the above-mentioned low operating pressure of the system that allows almost no flexibility. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 2.2.3. Downstream: Over the last few years, around 60% of the local available gas supply10 has been consumed domestically, mainly by the power sector (~80%)11 and industries (~20%). The remaining 40% is exported to Italy via the Greenstream pipeline, which departs from Mellitah treatment plant. Through a joint venture with the NOC, ENI has had a 25 year contract since October 2004, to export 60% of the gas produced by Mellitah Oil & Gas. However, due to the increase in the gas requirements for power generation and fall in production, NOC has managed to negotiate with ENI and reduce the amount of gas being exported from its original 800 mmscf/d to around 450 mmscf/d (in 2016). Based on information provided by NOC, the Libyan natural gas available for power generation and demand for other uses (for the period 2017 to 2030) would evolve as shown in the graphs below12. Given the characteristics of the Libyan transportation system referred to above, it is key to understand the gas demand patterns geographically disaggregated by both, the West and East sections, in order to be able to produce meaningful natural gas supply/demand balances and requirements of pipeline expansion. 10 Approximately 720 mmscf/d of natural gas is used at the upstream level (oil operations, injections, flaring, etc.). 11 See the following section for the Power Sector details. 12 Gas available considers that power generation has lower priority than upstream, exports and non-thermoelectric demand. And additional analysis with adjusted priorities has been included in Annex 7.3. GEB-OFF/4CT/0502978/100/00  20161020 12 / 61 RESTRICTED G Availab Gas erent uses Forecast at ble for diffe t a the West 2013-2030] [2 ] S Source: ased on NOC Own elaboration ba This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written G Availab Gas ferent Uses ble for Diff t s Forecast at the East 2013-2030] [2 ] S Source: ased on NOC Own elaboration ba GEB-OFF/ 0 /4CT/0502978/100/00 20161020 13 / 61 STRICTED RES as Available for Diffe Libyan Ga erent Uses Forecast 2013-2030] [2 ] S Source: ased on NOC Own elaboration ba 3. ELECTR 2.3 RKET RICITY MAR ower Generation: 2.3.1. Po alled capac Libya’s total insta city is 10.3 GW, all theermal unitss. Capacity growth ove er the This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 2012 – 2016 pe eriod has been around 3.3% (CAGR). No alled capac ot all insta city is curren G ntly online, though. Given ocial unres the so st, the oper ration and maintenance of e some of the existing poower plant ts have been b ngly compr stron romised; h hence approximately 27 7% of the installed ca c apacity is currently unnavailable. Thus, the “real” y is about 7.5 GW (belo installed capacity ow 2010 lev t vel). Also, there gnificant am are sig mount of proojects plannned or undder construc ntly on standby. The project for ction curren recast accordding to GEC COL Expansion Plan is s shown nex xt. F Installed Capacity Forecast 2016-2030] [2 ] 25.000 MW 20.000 15.000 10.000 5.000 - am Station Stea Gas G Station cle Combined Cyc ource: GECOL So wing map, most As can be seen in the follow m e of the existing and d planned capacity c s and was c would be located along the coast e country. of the GEB-OFF/ 0 /4CT/0502978/100/00 20161020 14 / 61 STRICTED RES n of Existing, Under Constructio Location C nned Powe on and Plan er Plants ation based on Source: Own elabora L/NOC n PwC/GECOL e areas in which the mo Three nts are located can be identified: ore efficient power plan  W To the West, A from Aboukamma ash to Zaw e wia where existing d planned p and power This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written d up approx plants add 000 MW. ximately 4,0  ta, with ~1,5 In Misurat cles. 500 MW of efficient combined cyc  ast, in Zwetina and Ben To the ea or 3,400 MW nghazi which account fo W. eration in 2011, After the sharp fall in gene 2 ricity gener electr s ration has remained stable 2 since 2012. In 2016, poweer generatiion reached G d 36,429 GWh (~4,150 MWavg g). Its growthh has been approxima p over the ately ~3% p.a. e last 6 yea ower than before ars, much lo b w 2011 when al growth was annua w ~ 8% p.a. o Power Generation Evolution of G 2000-2016] [2 ] 40 4 TWh 3 35 3 30 25 2 2 20 1 15 10 1 5 0 ource: GECOL So GEB-OFF/ 0 /4CT/0502978/100/00 20161020 15 / 61 STRICTED RES Libya’s electricity market relies entirely on the O&G sector for electricity production. Most of the energy generation in 2016 was natural gas-fuelled (75%), while the rest was fuelled by light fuel oil – LFO (16%) and heavy fuel oil – HFO (10%) mainly imported by NOC at international prices. Evolution of Fuel Consumption [2001-2016] 400.000 mmscf/d eq. 350.000 300.000 250.000 200.000 150.000 100.000 50.000 - LFO HFO Natural Gas Source: GECOL This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written According to the information provided by GECOL, most of the existing or under construction power plants were designed for dual fuel operation, meaning that they could run either on natural gas or on LFO/HFO. Two power plants are able to run just on HFO (i.e. not dual): Derna (130 MW) and Tobruk (130MW) (both in the far East of the country). In addition to these two plants, Sarir, Ubari, Khaleej (or Gulf) and Tripoli West13 are not currently connected to the Coastal pipeline and are not fuelled with natural gas. The first two are located in the interior of the country; while the other two are located near the Costal pipeline but do not have gas connections yet. Sarir and Khaleej power plant are expected to be connected to the gas network soon. The first one, by the end of the first quarter 2018 and the second one by 2019. West Mountain, although not connected to the Coastal Pipeline, is connected to the pipeline going from the El Wafaa field to the Mellitah treatment plant and mostly uses natural gas. 13 The last two under construction, Ubari and Tripoli West, were not online during 2016; thus, are not included in the “Fuel Consumption by Power Plant” chart. GEB-OFF/4CT/0502978/100/00  20161020 16 / 61 RESTRICTED Fuel Consumption by Power Plant [2016] 100% 9000 GWh 90% 8000 80% 7000 70% 6000 60% 5000 50% 40% 4000 30% 3000 20% 2000 10% 1000 0% 0 Gas Liquid Fuels Generation (right axis) Source: GECOL Although over the last years gas has been increasing its penetration in the generation mix (substituting fuel oil and gas oil) and contributing to reducing generation cost, there This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written is still room for improvements. Taking into consideration liquid fuel consumption at power plants that could have burned natural gas (~240 mmscf/d eq.) approximately 200 MUSD could have been saved by using LNG instead of LFO/HFO during 201614. 2.3.2. Transmission: The transmission network accounts for 2,290 km of 400 kV lines, 13,706 km of 220 kV and 25,453 km of other lines (< 66 kV). The network has suffered from substantial damage in the recent years, which have caused inefficiencies to the grid operation and maintenance. The most important transmission bottlenecks occur near Bengazi, actually splitting the network between eastern and western regions. As a result, surplus generation in the east side does not flow to the west regions. In a similar way as to the gas market, the East and the West essentially operate as independent systems. GECOL is pursuing plans to reinforce the transmission system with 400kV lines, but the status of implementation is uncertain and seems to lag behind. 14 The estimation assumes that the 240 mmscf/d of LFO/HFO consumed are replaced by LNG. LFO/HFO price correspond to the paid by NOC in 2016 (400 USD/ton and 280 USD/ton respectively), while LNG price to the average spot price (5.5 USD/MBTU). Required new infrastructure to meet power plants demand is not considered in the calculation. Also, saving from power plants having higher efficiency and lower O&M costs when fired with gas are not included in the calculation. GEB-OFF/4CT/0502978/100/00  20161020 17 / 61 RESTRICTED L Libya’s ctricity infr elec e rastructure ource: GECOL So emand: 2.3.3. De Since 2012, electricity consu s grown at lower rates umption has g the 2000- s than during -2010 decadde (3% vs. 8% CAGR R). Peak demand has grown at a rate of 4% % (CAGR) since 2012 and reache ed ~7 GW in 201615, although this t as decrease rate ha ed compareed to levels before 2011 (8% CAG GR). However, an add o 2 GW of the demand ditional 1 to t. Moreover d is not met r, the main cities uffering 3 to are su o 4 hours of e also were days during f load shedding every day. There g last w 10-hour power cuts and even some blackouts. year with This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written M Tripoli, the West and the Middle r approxima region together account for o the ately 70% of icity load. Both, peak electri k and averaage deman nd growth are concen these ntrated in t ns. region P Power nsumption by Region Con [2016]  ource: GECOL So 15 s both in summe Peak demand occurs er and winter. GEB-OFF/ 0 /4CT/0502978/100/00 20161020 18 / 61 STRICTED RES Summer and winter are the seasons with the highest average demand, while during autumn and spring, demand is below average. Average Seasonal Hourly Loads [2012] MW 6.000 5.000 4.000 3.000 2.000 1.000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Winter Spring Summer Autumn Source: GECOL According to GECOL, power demand is equally split among Residential, Commercial and Industry (Agriculture, Small and Large Industry). Demand by Customer [2015] This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Agriculture 11% Residential 31% Small Industry 4% Large Industry 21% Commercial 33% Source: GECOL The ability of the consumer to pay is not enough to cover the full prices. On the one hand, energy prices are relatively low. On the other hand, payment collection is one of the main challenges for GECOL together with illegal connections. “Even before the revolution, the share of unpaid bills was high and commonly around 40%. However, post-revolution the situation has worsened significantly. In 2012, the share of unpaid bills reached more than 70%. Additionally, commercial losses accounted for 30% in the domestic sector alone in 2012, mainly due to a large number of illegal connections. Technical losses are also high at around 17%. Electricity bills are issued and delivered quarterly to households who then have to pay them at one of the 188 commercial centers all around the country. A small percentage of around 10% of customers does GEB-OFF/4CT/0502978/100/00  20161020 19 / 61 RESTRICTED pay th s through state bank tr heir invoices ransfers. Ho owever, the ere are no clear c dures proced for the e enforceme payment”16. ent of non-p ricity Prices by Secto Libya Electr or [2015]  USD/MWh 49 9 49 49 30 21 23 22 14 ource: GECOL So ces are hea Since energy pric s avily subsidized for all economic sectors ifficult in Libya, it is di ter renewab to fost s and energ ble energies gy efficiencyy on a cost-effective baasis. Accor rding to PwCC’s17 (documments v03 of 17th Jun e ne 2017), demand is expected to grow CAGR of 4.9 at a C 9% (CAGR 0 under a scenario dub R) until 2030 bbed “Base e”, 6.2% (CA AGR) a in an alternative scenario ca a 7,6% (C alled “Mid” and CAGR) in a third scena ed as ario identifie “Best””, reaching circa 60 TW Wh ,70 TW Wh and 83 TWh (i.e. a 40% diffe 2 erence by 2030), This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written respec e three sce ctively. The enarios asssume simila ar growth rates r 2 until 2022 when they detach e inclusion o h due to the of "mega-prrojects" dem mand. The “Best” “ scenario include es the originaal mega-proojects curvee that rema c ains the only official curve availaable today, while Mid” scenario assumes a revised “mega-proje the “M ects” develoopment curv ve. y Demand Forecast Electricity 2016-2030] [2 ] wC’s Rapid As Source: Pw ssessment 16 -Electricity Sect Libya- tor Reform Tech ce, World Bank, 2014  hnical Assistanc 17 The “Base” scenario o corresponds to the “Continuous Political Instability” scennario in PwC’s documents, the “Mid” scenario P o to the “Slow Political Stability y (Updated)” sce enario and the “Best” scenario uous Political Stability” o to the “Continu S o. scenario GEB-OFF/ 0 /4CT/0502978/100/00 20161020 20 2 / 61 STRICTED RES In regard to power generation plants operational features (to be taken into account in the following section “3. Natural Gas Supply Alternatives for Power Generation), the “Base” scenario considers low installed capacity, low plant availability, high technical losses and low generation efficiency. On the contrary, “Mid” and “Best” scenarios would include high installed capacity, high plant availability, low technical losses and high generation efficiency18. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 18 See Annex 7.4 for the detail of the electricity market assumptions used in the models. GEB-OFF/4CT/0502978/100/00  20161020 21 / 61 RESTRICTED 3. NATURAL GAS SUPPLY ALTERNATIVES FOR POWER GENERATION. The following sections of the report will focus on the analysis of different potential options to reduce power generation costs and greenhouse gas emissions while increasing the reliability of the system through the increase of natural gas availability. 3.1. METHODOLOGY. In order to analyze the different alternatives to improve natural gas supply, the Consultant will run two models: a simplified electricity dispatch model and a natural gas flow. Both models are run for each alternative and the three electricity demand scenarios previously detailed. First, the simplified electricity dispatch model determines the demand for natural gas or liquid fuels by power plant. This linear programing tool, optimize the dispatch of the power plants (minimum cost) to meet the expected demand throughout the study time horizon. In every case, the electricity demand is fully supplied (i.e. the simulations do not consider electricity curtailments). The dispatch model allocates liquid fuels and natural gas by merit order (i.e. the least generation cost expressed in USD/MWh) in order to minimize the total system cost19. As a result, the optimal fuel mix is obtained. The input data for the model are: the electricity demand scenarios, the power plant features (installed capacity, availability, losses, and heat rates or efficiencies of the This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written power plants), the fuel costs20, and the availability of natural gas. It is worth noting that power plants in the interior of the country (i.e. Ubari and Sabha21) and in the East Mountains (i.e. Tobruk and Derna) are assumed as still fuelled with HFO or LFO. The latter stems from the long distances that make pipeline connection not economically viable22. Also, the model does not consider electricity transmission restrictions. Second, natural gas flow simulations are performed. The input data for the model are: natural gas demand resulting from the dispatch model, the transportation capacity and natural gas availability. Through this model, the gas system optimal operation at every section of the pipeline (direction and volume) is understood and the required size of the transportation expansions and additional natural gas is obtained. Both models are run under two electricity demand conditions. First, for summer electricity demand in order to dimension the natural gas supply and transportation infrastructure requirements. Summer is the season with higher demand (approximately 15% higher than the year’s average); thus, the natural gas system configuration resulting would allow meeting demand under tight situations. Second, models are run for the yearly average electricity demand, in order to determine the average fuel 19 This type of dispatch corresponds to a centralized operation in which only one entity decides which plant uses the fuel in order to reduce as much as possible the generation cost. 20 See “4.2 Fuel Costs” 21 Natural gas supply directly from the wells might be possible, but not under review during this study. 22 See Annex “7.2 Preliminary Analysis on Tobruk” GEB-OFF/4CT/0502978/100/00  20161020 22 / 61 RESTRICTED consumption, which along with the investments of new infrastructure, will result on the system’s cost. These model results would then be used to help focus on the areas where technical viability of required changes to the gas distribution system needs to be assessed or preferred location of LNG injection points can be reviewed for the LNG Options report. 3.2. FORECAST UNDER CURRENT CONDITIONS. Before moving forward with the supply alternatives it is important to review what the forecast for Libya could be maintaining the status quo (i.e. not additional gas supply or transportation expansions). As explain in detail below, under these conditions, the country would suffer gas curtailments first due to transportation bottlenecks and then due to insufficient supply. This scenario will serve as the base line case for comparison and to determine the potential savings. Considering the natural gas supply forecast prepared by NOC, a simplified Supply- Demand balance for power generation was prepared. As can be observed, without taking into account the transportation capacity, natural gas supply will not be enough to meet the average power demand as of 2017/2018 under the “Base” scenario, and as of 2022, the “Mid” and “Best” scenarios23. This situation would worsen during summer and winter seasons when electricity demand is higher than the average. It is worth mentioning that “Mid” and “Best” cases show lower gas demand in the short term as, in this scenario, it is assumed that power plant availability, efficiency and capacity is higher This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written than in the “Base” scenario. Simplified Natural Gas Supply-Demand Forecast [2017-2030]  2.500 mmscf/d 2.000 1.500 1.000 500 - Gas Available for Power Generation Base Mid Best Source: Own elaboration based on PwC and NOC 23 Note that since the figures that support the blue-area under the graph above (i.e. “Gas Available for Power Generation”) refer to “availability” instead of “actual supply”, it could be argued that the gas available but not supplied during low demand periods may be effectively supplied when the gas deficit arises in 2022/2023 (according to the Scenario analysed) so deferring such deficits to about 2024 for both Scenarios. Such analysis though is out of the scope of this Study since it would depend on a detailed scrutiny of the features and performance of every Libyan gas field feeding the system. GEB-OFF/4CT/0502978/100/00  20161020 23 / 61 RESTRICTED When taking into consideration the transportation capacity, only part of the available gas volume would be injected to the system due to bottlenecks. As a result, in order to meet electricity demand, liquid fuels would be required. Coastal Pipeline Transportation Utilization24 [2017-2030] Base Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  700  450 mmscf/d  400 mmscf/d mmscf/d  600  350  400 Transportation   350 Transportation   500  300 Bottlenecks Bottlenecks  300  400  250  250  200  300  200  150  150  200  100  100  100  50  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Mid Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  700  400  450 mmscf/d mmscf/d mmscf/d  600  350  400 Transportation   350 Transportation   300 Bottlenecks  500 Bottlenecks  300  250  400  250  200  300  200  150  150  200  100  100  100  50  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Best Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  700  400  450 mmscf/d mmscf/d mmscf/d  600  350  400 Transportation   350 Transportation   300 Bottlenecks  500 Bottlenecks  300  250  400  250  200  300  200  150  150  200  100  100  100  50  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Source: Own elaboration By 2030, taking into consideration the current transportation capacity, natural gas supply and the expected demand growth, the system would be affected by a shortfall of gas for power generation of around 1,250 mmscf/d to over 1,800 mmscf/d that should be covered by liquid fuels, as shown in the following figures. 24 Pipeline utilization includes in addition to power generation gas demand, industrial and residential consumption. GEB-OFF/4CT/0502978/100/00  20161020 24 / 61 RESTRICTED Fuel Utilization for Power Generation Forecast [2017-2030]  Base Scenario  2.000 mmscf/d  1.800  1.600  1.400  1.200  1.000  800  600  400  200  ‐ Local Natural Gas LFO HFO Mid Scenario  2.000 mmscf/d  1.800  1.600  1.400  1.200  1.000 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written  800  600  400  200  ‐ Natural Gas LFO HFO Best Scenario  2.500 mmscf/d  2.000  1.500  1.000  500  ‐ Natural Gas LFO HFO Source: Own elaboration GEB-OFF/4CT/0502978/100/00  20161020 25 / 61 RESTRICTED arge amount of liquid fuels would This la d probably be importe g in a significant ed, resulting cost for f the system25. The following g table sum mmarizes the yearly cost of power p generration underr this “do no othing” scenario (for fu uel prices used u s estimation for this n see Fuel Prices”) “4.2 F ). otal Fuel Ut To or Power Generation tilization fo G st Yearly Cos 2017-2030] [2 ]  ts / Year (MUSD) Fuel Cost Scenario 2017 2018 2019 2020 2021 2 2022 23 202 2024 2025 2026 2027 2 2028 2029 30 203 Base 1.585 1.900 1.871 2.036 1.926 2.274 3.2 236 3.488 3.927 5.163 6.366 7.639 8.566 10.500 Mid 1.352 1.331 1.395 1.455 1.515 1.814 3.0 022 2.555 3.061 4.507 5.787 7.019 8.401 10.137 Best 1.352 1.331 1.395 1.455 1.515 1.849 3.5 561 3.510 4.318 6.210 7.607 8.992 10.613 289 12.2 ration Source: Own elabor 3. ALTERN 3.3 T IMPROV NATIVES TO AL GAS AV VE NATURA TY. VAILABILIT on describe Given the situatio a ed above, alternatives to improvee natural ga ity for as availabili powerr generatioon should include ad atural gas supply and dditional na d transporttation nsion. In this expan s regard, the Consultan tified four different alternatives: nt has ident rm Solution 1. Short Ter n: considers ation of all the s the utiliza t local ga on for as productio 2 neration by expanding26 power gen the Coas stal pipeline cing gas ex e and reduc xports essary. when nece This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written ematic Diag Sche e “Short Te gram of the on” Alterna erm Solutio ative ration Source: Own elabor 25 worth noting, th It is w hat all analysess in this report are made from o view; thus, real m Libya’s point of r cost of fuels were considered in the system cost estimatio on. 26 s report expand In this e could either be ding the pipeline mpression or lo b additional com oops not new pipeline trenchess. In the LNG Op ption Report the most appropria e ate solution for expanding p the pipeline e studied. to meet demand will be GEB-OFF/ 0 /4CT/0502978/100/00 20161020 2 / 61 26 STRICTED RES 2. LNG in El Brega: ass c sumes the conversion action terminal in of the on-shore liquefa on and the expansion of the Coa Marsa El Brega to regasificatio astal pipeline to ral gas dem meet natur mand. S Schematic Diagram D f the “LNG in Brega” Alternative of e ource: Own elaboration So This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 3. LNG in th he West: inncludes the o e construction of an off-shore egasification re n and storage teerminals too next to Khoms to t supply gas and expanding g the tion system transportat m if required. iagram of the Schematic Di n the West” Alternativ t “LNG in ve ource: Own ela So aboration} GEB-OFF/ 0 /4CT/0502978/100/00 20161020 2 / 61 27 STRICTED RES 4. Focused LNG: cons on of an off-shore siders the constructio o n and regasification onnect directly to Mellitha, Zawia and Abouk storage terminal to co kammash p power plants27. S Schematic Diagram D f the “Focu of e used LNG” Alternative ource: Own elaboration So This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Next, the results of the simu derlining fue ulations und el consumpt es, transport tion volume tation expannsion requirrements and additiona al natural ga a present as supply are ted for the three icity demand scenarios electri s under anaalysis. 3.3.1. Sh S hort Term Solution. The “ “Short Term Solution n” alternative, as its name im mplies, redu uces liquid fuel requirrements in the short termt (in comparison withw the current situat tion forecasst) by modify ying the Co oastal pipeline and using local ga as production originall ly planned to be export ng it in the West Entr ted (injectin ry Point). This T ative does not alterna n conside er the ase of gas supply thr increa rough impo orts; but ma aximizes th he utilizatioon of produ uction y. The unde locally erlining assuumption forr this alterna ative is that rable to incr t it is prefer rease e gas supply from reducing exports n expand th than he Coastal pipeline. In n this way, large invest m tments are minimized. As exxplained in “3.1 Metho d odology”, in order to dimension the t ssion expansion transmis and aadditional su upply requirements models are run r under summer s ectricity dem ele mand condittions. Unde nd 2023 in t er the latter, in 2018 an “ the “Base” and in the “Mid” and “Best” scenaarios respec ctively, exports are reduced grad pended to avoid dually until finally susp h noting that using liquid fuels. It is worth f the comme t a study of ct of suspending ercial impac export as not been ts to Italy ha n carried out. 27 alternative was based on the discussion with NOC This a N plify the during the KOM and further discussions, in order to simp on of the transm expansio gher natural gas mission system and allowing hig s availability. GEB-OFF/ 0 /4CT/0502978/100/00 20161020 2 / 61 28 STRICTED RES In order to use as much local production as possible and allow more efficient power plants to be dispatch, additional transportation capacity in the Brega – Zwetina section of the pipeline would be required all three scenarios. Also, additional transportation capacity would be required from Brega to the West. Coastal Pipeline Transportation Utilization [2017-2030] Base Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  800  400  600 mmscf/d mmscf/d mmscf/d  700  350  500  600  300  400  500  250  400  200  300  300  150  200  200  100  100  100  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Mid Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  800  400  600 mmscf/d mmscf/d mmscf/d  700  350  500  600  300  400  500  250  400  200  300  300  150  200  200  100  100  100  50  ‐  ‐  ‐ This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Best Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  800  400  600 mmscf/d mmscf/d mmscf/d  700  350  500  600  300  400  500  250  400  200  300  300  150  200  200  100  100  100  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Source: Own elaboration It is worth noting that, although exports increases supply at the West Entry Point it would only be necessary a minor expansion in the Mellitah - Tripoli - El Khoms pipeline to meet summer demand in the “Base” scenario28. Taking in consideration the yearly average demand, it can be observed in the graphs below that after undergoing the expansion previously mentioned and using all local gas production, liquid fuels required would be delayed until 2025/2026 in all three scenarios 28 This expansion is currently been pursued by NOC and not considered as an extra cost for this solution. GEB-OFF/4CT/0502978/100/00  20161020 29 / 61 RESTRICTED Fuel Utilization for Power Generation Forecast [2017-2030]  Base Scenario 2000 mmscf/d eq. 1800 1600 1400 1200 1000 800 600 400 200 0 Local Gas Exports LFO HFO Mid Scenario 2000 mmscf/d eq. 1800 1600 1400 1200 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 1000 800 600 400 200 0 Natural Gas Exports LFO HFO Best Scenario 2500 mmscf/d 2000 1500 1000 500 0 Local Gas Exports LFO HFO Source: Own elaboration GEB-OFF/4CT/0502978/100/00  20161020 30 / 61 RESTRICTED 3.3.2. LNG in Brega. The “LNG in Brega” alternative consists of increasing gas injection in Brega by converting the on-shore liquefaction terminal in Marsa El Brega and debottlenecking the Coastal pipeline. The table below indicates the maximum send-out capacity requirements for each scenario in order to fully meet summer average demand29. LNG Import Terminals [2017-2030] Brega Conversion 1st Expansion 2nd Expansion 3rd Expansion Scenario Max. Send Out Max. Send Out Max. Send Out Max. Send Out COD COD COD COD (bcm/y) (bcm/y) (bcm/y) (bcm/y) Base 2022 5,5 2026 5,5 2028 5,5 - - Mid 2022 5,5 2026 5,5 2028 5,5 - - Best 2022 5,5 2024 5,5 2026 3,7 2028 5,5 Source: Own elaboration Given that the most efficient power plant (existing and planned) and that the highest fall in natural gas production would be located in the west, large pipeline expansions would be required in order to allow regasified LNG flow from Brega to consumption centers in the West. Also, it would be necessary to expand the Brega- Zwetina pipeline section in order to exploit all local gas production. The maximum This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written transportation utilization for each pipeline including expansions requirements of this alternative are showed in the following table. Coastal Pipeline Transportation Utilization [2017-2030] Base Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  900  1.600  600 mmscf/d mmscf/d mmscf/d  800  1.400  500  700  1.200  600  400  1.000  500  800  300  400  600  300  200  200  400  100  100  200  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity 29 Although LNG terminal plant would be required before 2022, it would be difficult to have the import terminal online before this date. GEB-OFF/4CT/0502978/100/00  20161020 31 / 61 RESTRICTED Mid Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  900  1.600  600 mmscf/d mmscf/d mmscf/d  800  1.400  500  700  1.200  600  400  1.000  500  800  300  400  600  300  200  200  400  100  100  200  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Best Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  1.200  2.500  600 mmscf/d mmscf/d mmscf/d  1.000  2.000  500  800  400  1.500  600  300  1.000  400  200  200  500  100  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Source: Own elaboration Taking in consideration the yearly average demand, it can be observed in the figure below, that this alternative fully meets average natural gas demand during the whole period. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Fuel Utilization for Power Generation Forecast [2017-2030] Base Scenario 1800 mmscf/d eq. 1600 1400 1200 1000 800 600 400 200 0 Local Gas LNG LFO HFO GEB-OFF/4CT/0502978/100/00  20161020 32 / 61 RESTRICTED Mid Scenario 2000 mmscf/d 1800 1600 1400 1200 1000 800 600 400 200 0 Local Gas LNG LFO HFO Best Scenario 2500 mmscf/d 2000 1500 1000 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 500 0 Local Gas LNG LFO HFO Source: Own elaboration 3.3.3. LNG in the West. In this alternative, as well as the previous one, the objective would be to avoid burning liquid fuels for power generation. In order to meet summer average demand across all users, at least three FSRU’s would be required to cover all scenarios30. The table below indicates the maximum send-out capacity requirements for each scenario. 30 The expansion of the regasification capacity would depend on the certainty that all new power plants are in line by the expected dates. GEB-OFF/4CT/0502978/100/00  20161020 33 / 61 RESTRICTED LNG Import Terminals [2017-2030] FSRU 1st Expansion 2nd Expansion 3rd Expansion Scenario Max. Send Out Max. Send Out Max. Send Out Max. Send Out COD COD COD COD (bcm/y) (bcm/y) (bcm/y) (bcm/y) Base 2022 5,5 2026 5,5 2028 5,5 - - Mid 2022 5,5 2026 5,5 2028 5,5 - - Best 2022 5,5 2024 5,5 2026 3,7 2028 5,5 Source: Own elaboration (COD = Commercial Operations Date) FSRU type import terminals would be installed in the west next to Khoms, near the demand and replacing the fall in injections at the West Entry Point. Although the LNG amount required would be the same as in the previous alternative, transportation system expansions should be much smaller. Thus this alternative would have lower costs than the previous one. It’s worth mentioning that, results would be similar if facilities were located along the coast in the West from Khoms to Mellitah. If the terminals were to be located east of Khoms, transportation expansions should be larger as the pipeline only has a capacity of 370 mmscf/d. In all three scenarios, pipeline expansions will be required in the Brega-Zwetina section and from Brega to the West in order to leverage on local gas production. Also some expansion could be necessary by the end of the period under analysis in the Tripoli- Khoms and Tripoli pipeline. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Coastal Pipeline Transportation Utilization [2017-2030] Base Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  900  600  600 mmscf/d mmscf/d mmscf/d  800  500  500  700  600  400  400  500  300  300  400  300  200  200  200  100  100  100  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Mid Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  900  500  600 mmscf/d mmscf/d mmscf/d  800  450  400  500  700  600  350  400  300  500  250  300  400  200  300  150  200  200  100  100  100  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity GEB-OFF/4CT/0502978/100/00  20161020 34 / 61 RESTRICTED Best Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  1.200  1.000  600 mmscf/d mmscf/d mmscf/d  900  1.000  800  500  800  700  400  600  600  500  300  400  400  300  200  200  200  100  100  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Source: Own elaboration Taking in consideration the average yearly demand, it can be observed in the figure below, that this alternative fully meets average natural gas demand during the whole period. Fuel Utilization for Power Generation Forecast [2017-2030] Base Scenario 1800 mmscf/d eq. 1600 1400 1200 1000 800 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 600 400 200 0 Local Gas LNG LFO HFO Mid Scenario 2000 mmscf/d 1800 1600 1400 1200 1000 800 600 400 200 0 Local Gas LNG LFO HFO GEB-OFF/4CT/0502978/100/00  20161020 35 / 61 RESTRICTED Best Scenario 2500 mmscf/d 2000 1500 1000 500 0 Local Gas LNG LFO HFO Source: Own elaboration 3.3.4. Focused LNG. Last, the alternative “Focused LNG” consists in connecting directly, through a new pipeline, a LNG terminal (FRSU) with power plants near Mellitah and Zawia, which according to their efficiency would have high dispatch. The underlining assumption of this scenario is that power plants grouped with a dedicated LNG terminal and pipeline (rather than being connected to the coastal pipeline) would be dispatch with first priority. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written The new pipeline, of around 100 km, would allow supplying directly the power plants leaving idle capacity to meet the rest of the demand. However, by the end of the period under study (2027) due to the fall in local production, liquid fuels would be again required. In order to meet these power plants summer natural gas consumption, the FSRU would need to be ~ 6 bcm/y (within international standards). Given that in this alternative the LNG would be supplied through a dedicated pipeline, transportation expansion would be minor. Coastal Pipeline Transportation Utilization [2017-2030] Base Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  700  400  600 mmscf/d mmscf/d mmscf/d  600  350  500  300  500  400  250  400  200  300  300  150  200  200  100  100  100  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity GEB-OFF/4CT/0502978/100/00  20161020 36 / 61 RESTRICTED Mid Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  700  400  600 mmscf/d mmscf/d mmscf/d  600  350  500  500  300  400  250  400  200  300  300  150  200  200  100  100  100  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Best Scenario Mellitah – El Khoms Pipeline El Khoms ‐ El Brega Pipeline El Brega ‐ Benghazi Pipeline  700  400  600 mmscf/d mmscf/d mmscf/d  600  350  500  500  300  400  250  400  200  300  300  150  200  200  100  100  100  50  ‐  ‐  ‐ Injection Max. Capacity Injection Max. Capacity Injection Max. Capacity Source: Own elaboration Taking into consideration the average yearly demand, it can be observed in the figure below, that this alternative fully meets average natural gas demand during the whole period. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Fuel Utilization for Power Generation Forecast [2017-2030] Base Scenario 2.000 mmscf/d eq. 1.800 1.600 1.400 1.200 1.000 800 600 400 200 - Local Gas LNG LFO HFO GEB-OFF/4CT/0502978/100/00  20161020 37 / 61 RESTRICTED Mid Scenario 2000 mmscf/d eq. 1800 1600 1400 1200 1000 800 600 400 200 0 Local Gas LNG LFO HFO Best Scenario 2.500 mmscf/d 2.000 1.500 1.000 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 500 - Local Gas LNG LFO HFO Source: Own elaboration GEB-OFF/4CT/0502978/100/00  20161020 38 / 61 RESTRICTED 4. COMPARISON OF SUPPLY ALTERNATIVES. In order to compare the different alternatives and determine the possible savings of using the optimal fuel, in this section the total power generation fuel costs are estimated based on the investment and operational costs - CAPEX and OPEX - of the new infrastructure (regas terminals and transport capacity expansion) and fuel prices. 4.1. CAPEX & OPEX. Subsequently, all new infrastructure costs included in the model analysis are detailed. First, the Consultant assumes that the pipeline CAPEX costs would be 105 USD/inch/meter either if it loops or compression stations. Further analysis on which is the best alternative (especially if the pipeline route is difficult) will be undertaken after the site visit in the LNG Option Report. Additionally, transport OPEX is estimated as 4% of CAPEX. These assumptions are considered in all alternatives under study31. Second, for the conversion of the liquefaction terminal in Marsa El Brega involved in Alternative “LNG in Brega”, the CAPEX is assumed as 500 MUSD. Although the terminal already has two LNG storage tanks and a harbor with a breakwater and jetty, initial assessment shows that little plant and equipment could be saved from using this location (the full analysis is being prepared separately for inclusion within the LNG Options Report). OPEX would be 13 MUSD/y. When required, expansions of the regasification terminal required are estimated as 150 MUSD. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Third, regarding the new off-shore regasification and storage terminals (FSRU type), involved in Alternatives “LNG in the West” and “Focused LNG”, the cost (CAPEX and OPEX) is based on a standard FSRU with jetty/trestle facility (90 MUSD) assuming that connection to the grid is not too far away or complicated (such as horizontal drilling being required) and that no breakwater or extensive dredging is required at the FSRU berthing point. FSRU daily fees are estimated at 160 kUSD/day (140 kUSD/day vessel lease and 20 kUSD/day crew costs). Last, the reversion of the Coastal pipeline flow is not included as an additional cost. It is noteworthy that, based on the Consultant’s international experience, the potential flow reverse does not imply significant investments, since an annexation of external new tubing allows the shift. Additionally, the pipeline cost to connect new power plants and regasification terminals to the Coastal pipeline are not included in this analysis. Given that this was a first preliminary valuation of the different alternatives, the costs are assumed based on information available and therefore were subjected to further analysis in the second report of Task B, LNG Options Report. In order to allow new infrastructure COD in the year required, investments are assumed to be executed two years in advance. 31 For scenario comparison only additional OPEX to the existing infrastructure will be considered. GEB-OFF/4CT/0502978/100/00  20161020 39 / 61 RESTRICTED 4.2. FUEL PRICES. Fuel prices used for the estimation of the cost for power generation, were projected based on the EIA January 2017 forecast. The following figure shows the projected prices. Fuel Projections  25,0 USD/MBTU  20,0  15,0  10,0  5,0  ‐ LFO HFO LNG Source: Own elaboration This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written In particular:  LNG was projected based on the prices from Egypt and Pakistan that recently singed short and long term LNG supply contracts at 12% of Brent price.  The liquid fuels forecast was based on the historical spread between international liquids fuel price and WTI.  Exports price, to be considered in the “Short Term Solution” alternative, as an opportunity cost of not selling the gas to Italy is forecasted at 11% of Brent price similar to other prices sold in continental Europe.  Local gas, although it would not have any impact on the study as all alternatives contemplate the utilization of all local gas (with higher priority than more expensive fuels), is estimated at 4 USD/MBtu. 4.3. EXPECTED SAVING FROM USING OPTIMAL FUEL. Based on CAPEXs and OPEXs and considering an estimated discount rate of 10%, the present value of cost of each alternative under the different scenarios is exposed in the following figure. In all cases, Alternative “LNG in the West”, shows the higher level of savings (with a net present value of 8 to 10.5 BUSD depending on the scenario) compared with maintaining the current situation due to two reasons: liquid fuels are replaced by LNG which is cheaper and there is no need for large gas transportation system expansions. GEB-OFF/4CT/0502978/100/00  20161020 40 / 61 RESTRICTED Total saving of this alternative in relation to the different scenarios32 are: Cost Present Value of the Alternatives Base Scenario  45.000 MUSD Savings 10 BUSD  40.000  35.000 ‐27%   30.000  25.000  20.000  15.000  10.000  5.000  ‐ Current Short Term LNG in Brega LNG in the Focused  Dedicated Situation Solution West LNG Mid Scenario  40.000 MUSD Savings 8 BUSD  35.000 ‐24%   30.000  25.000 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written  20.000  15.000  10.000  5.000  ‐ Current Short term LNG in Brega LNG in the Focused  Dedicated Situation solution West LNG Best Scenario  45.000 MUSD  40.000 Savings 9 BUSD  35.000 ‐23%   30.000  25.000  20.000  15.000  10.000  5.000  ‐ Current Short term LNG in Brega LNG in the Focused  Dedicated Situation solution West LNG Source: Own elaboration 32 Note all scenarios consider the same electricity scenarios. All power plants are included in all scenarios. GEB-OFF/4CT/0502978/100/00  20161020 41 / 61 RESTRICTED It is worth noting, that the discount rate has a significant impact on the present value of the total savings of each alternative. The following graphs show the different cost present value at different discount rates. Cost Present Value Sensitivity at Different Discount Rates Base Scenario  80.000 MUSD  70.000  60.000  50.000  40.000  30.000  20.000  10.000  ‐ 5,0% 10,0% 15,0% 20,0% 25,0% 30,0% Current Situation Short Term Solution LNG in Brega LNG in the West Focused  LNG Dedicated  LNG Mid Scenario  70.000 MUSD  60.000 This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written  50.000  40.000  30.000  20.000  10.000  ‐ 5,0% 10,0% 15,0% 20,0% 25,0% 30,0% Current Situation Short Term Solution LNG in Brega LNG in the West Focused  LNG Dedicated  LNG Best Scenario  80.000 MUSD  70.000  60.000  50.000  40.000  30.000  20.000  10.000  ‐ 5,0% 10,0% 15,0% 20,0% 25,0% 30,0% Current Situation Short term solution LNG in Brega LNG in the West Focused LNG Dedicated  LNG Source: Own elaboration GEB-OFF/4CT/0502978/100/00  20161020 42 / 61 RESTRICTED 4.4. POTENTIAL REDUCTION OF CO2 EMISSIONS. The following figures summarize the reduction of CO2 emissions in comparison to the case under current conditions (i.e. neither additional supply nor transportation expansions). As could be expected, Alternatives LNG in Brega” and “LNG in the West” presents the largest reduction as liquid fuels are not used in either of the scenarios. CO2 Emission Reduction Base Scenario -8% -9% 813 745 739 -28% -28% 582 582 Current Situation Short Term LNG in Brega Focused LNG LNG in the West Dedicated LNG Solution M ton. eq CO2 Mid Scenario This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written 804 -11% -10% 713 722 -30% -30% 561 561 Current Situation Short Term LNG in Brega LNG in the West Dedicated LNG Focused LNG Solution M ton. eq CO2 Best Scenario 989 -13% 861 -26% -33% -33% 734 666 666 Current Situation Short Term LNG in Brega LNG in the West Dedicated LNG Focused LNG Solution M ton. eq CO2 Source: Own elaboration GEB-OFF/4CT/0502978/100/00  20161020 43 / 61 RESTRICTED 5. GUIDELINES TO PRIORITIZE THE USE OF GAS FOR GENERATION. Before addressing this point specifically, it is important to highlight that as a matter of a national energy policy level a first assessment should be made in regard to where a “molecule” of natural gas is more valuable for the country or in other words, identify which final consumer or sector has the highest opportunity cost for such a molecule. In the context of this study for the Libyan case this assessment has been implicitly made since the natural gas on which the power sector can count on is the “reminder” one; that is, after having fully supplied the other sectors (i.e. upstream usage, industry, and exports)33. So, the next question is: “with the natural gas available for power generation, how should it be prioritized among the existing and future power plants?” The first consideration is to guarantee a tight coordination among NOC and GECOL plans not just in terms of both the location of the natural gas supply to pipeline and power production (generation), but also in regards to the development of each sector’s infrastructure. As previously mentioned the local gas non-thermoelectric demand is low compared with power generation, thus the latter would probably be the driver for gas transportation expansions and additional supply (either new local production or imports). Thus, the decision of moving forward with an LNG import terminal should be an integrated decision and should contemplate potential resulting local gas production (even though currently there is no exploration, if the political situation improves, an increase in production could be expected leveraging from the countries significant This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written potential). Regarding infrastructure, especially that of transportation, it is necessary to identify the optimal capacities of each one (or even to make comparisons like gas-by- pipeline vs gas-by-wire in case a power plant is to be built near to a gas field, etc.). Another point to take into account is the efficiency of the power plants: if there is the alternative and the necessity to supply them with either liquid fuels or natural gas, the liquids should be allocated to the most efficient plants so as to minimize the generation costs by supplying the most expensive fuel to the plant that requires less of it to generate the same amount of electricity. Generally speaking, it is cheaper to transport liquid fuels than natural gas when it is done by pipelines, so the long distances from a fuel supply to a power plant make liquid fuels the obvious choice provided there are actually pipelines in place; otherwise, if the fuels ought to be transported by other means (by ship or truck, for instance), an analysis of the transportation costs should be made. 33 See GEB-OFF/4CT/0502978/100/00  20161020 44 / 61 RESTRICTED 6. HIGHLIGHTS. In the short term, reducing the exports to Europe and expanding the Coastal Pipeline is a good immediate solution to reduce liquid fuels consumption for power generation. However, it is not enough to offset the fall in local gas production in the mid/long term. In the mid-term (i.e. next 10 years), replacing liquid fuels by LNG seems to be an alternative that would allow significant savings in generation costs. However, the required expansion in existing transportation and import infrastructure would reduce the savings. Given that: the fall in production will be greater in the West Entry Point, a large part of the efficient power generation is located in the West, and, the Mellitah – El Khoms pipeline has the largest capacity the most economical alternative is to place the LNG import terminals in the west somewhere near Khoms. This alternative would also increase flexibility and reduce investment costs. The former by allowing the adaptation of the solution to the evolution of the country’s political situation and/or the development of a new local gas supply. FRSU type import terminals, could be built in the short term in case gas demand is not expected to be met or dismantled when there is higher local gas supply. The latter because FRSU usually do not require high investment, as the vessel is not built or purchased by the user but leased. In the long term, the country could either move forward with an onshore terminal or end This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written LNG imports depending on the evolution in the natural gas E&P. The decision would need to be taken around 2026/2027. GEB-OFF/4CT/0502978/100/00  20161020 45 / 61 RESTRICTED 7. ANNEX. 7.1. POTENTIAL SWITCH OF POWER PLANTS TO NATURAL GAS. As detailed in “2. Country Overview”, Derna and Tobruk power plants are the only ones not designed to run on a dual fuel basis (i.e. only on fuel oil.). These power stations are located at the North-Eastern part of the country. Both are based on the conventional steam units of 65 MWe, i.e. sub-critical steam turbines and HFO-fired steam boilers. Tobruk power station was commissioned in 1983, and Derna in 1985. According to the Expansion Plan, it can be observed that the plants are due to be decommissioned in 2019, and that the available capacity is limited to 30 MW. The reported heat rate evidences the poor performance of these power stations, which are obviously not well suited for long term and base-load operation in terms of energy efficiency. The conversion of steam plants from HFO-firing to NG-firing is technically possible. It would consist of installing a natural gas supply system including associated gas control and safety systems, and to install a gas firing system into the existing boilers with associated mechanical, electrical and process control adaptations. However it is expected that the pay-back period of such works would be incompatible with the remaining operational lifetime of the plants (less than 2 years of operation are planned) and expected dispatch. This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Moreover, the performance indicators mentioned above show that additional works might be required to recover the original plants’ performances. More generally, a lifetime extension assessment might be undertaken to ascertain that the steam turbine generators are still in good condition, as well as to address other ageing issues, boiler corrosion issues, and I&C obsolescence which are generally concerns for similar older plants. 7.2. PRELIMINARY ANALYSIS ON TOBRUK. 7.2.1. Expanding the Pipeline to Tobruk. In order to determine if existing and planned power plants located in Derna and Tobruk the Consultant has undertaken a desktop study to identify a route technically feasible to connect the cities with a new pipeline. Route Survey Source: Own elaboration GEB-OFF/4CT/0502978/100/00  20161020 46 / 61 RESTRICTED Two r routing are possible an nd have bee en checked d and comp ng the pared. The first is alon coast and the se econd is so outh from th he mountain area. Lay ying the pipeline along the v coast would be very t due to the difficult he pipeline would go th e fact that th hrough the cities in the coast and laying in a cliff (altitude ± 250m). Thus, the second opt tion seems to be the mo ost favourable. Based iminary esti d on a preli r imate, the required 34 4 inch / 430 0 km pipelinne would haave a of approximately 1,540 cost o 0 BUSD (un a ncertainty + 40%). In addition to the new pipeline, pply gas fro to sup om Marsa El Brega to o the new pipeline, thhe existing Coastal pippeline d be expand should ply power pl ded to supp ed in these cities. lants locate c istances fro Given the long di om the Cost patch for ex tal pipeline and the expected disp xisting p and planned ower plants po s in Dernaa and Tobr ruk, it wouuld be more econom mically advan o use liquid ntageous to d fuels (during peaks) e ) than to expand the pipeline too this 34 on . locatio 7.2.1. Tobruk Standalone e. If Tob alyzed independent fro bruk power plant is ana tem a dedic om the syst cated LNG could conomically prove to be an ec y feasible alternative. ew CCGT in Considering the full dispatch of the ne n Tobruk, fu c uel saving could be arround 5 35 MUSD/y in th 330 M he 2021-20 dispatch of new power 030 period . If the full d Derna r plants in D ther local units saving would be even bigger. and ot t Present Value Cost V This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written ration Source: Own elabor 34 It is assumed that Lib e regasification terminal. bya only would be installing one 35 If Tob ed below 30% it bruk is dispatche t would be more t use liquid fue e economically to els. GEB-OFF/ 0 /4CT/0502978/100/00 20161020 47 4 / 61 STRICTED RES 3. SENSIT 7.3 H ADJUSTE TIVITY WITH RIORITIES. ED GAS PR . a The alternative or higher ga fo as availabili ity analysis assumes that t ailable for power gas ava p gener e remainde ration is the er after dedducting ups stream usaage and no on-thermoelectric demand. However, it could d be discusssed (as hig n section “5 ghlighted in 5. Guidelines to tize the Use Priorit e of Gas foor Generation”) where e a “molecu ural gas is more ule” of natu valuab c ble for the country. on-thermoelectric dema As no ently small (~150 mms and is curre scf/d), but it is expect ted to grow to ~650 mm ording to NOCs mscf/d acco N C projection, the Consultant run a sens sitivity ming that po assum s have high ower plants n her priority than new non-thermo mand oelectric dem d on 2016 le based evels). Adjust orities of na ting the prio atural gas will w increase ability for po e gas availa ower genera ation; r thus reduces e fuel cost in the n all alternaatives, even se of mainta n in the cas s aining the status quo. However, giveng that non-thermo oelectric deemand is small compared to power p gener h ration, the higher till not enou availability is st ugh to mee et demand in the long g run. Thus, as well as in all the e other sce enarios stu L udied, the LNG nal near Khoms termin alternaative maximmizes saving gs. st Present Value Cos V ves of the Alternativ This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written ration Source: Own elabor 4. ELECTR 7.4 RKET ASS RICITY MAR S USED IN THE PROJ SUMPTIONS . JECTIONS. he projectio For th on the Con nsultant us sed the info ormation re he approac egarding th ch for demand projecti p ion and operational features provided byy PwC thr R rough its Rapid GEB-OFF/ 0 /4CT/0502978/100/00 20161020 4 / 61 48 STRICTED RES Assesssment of th g tables sum he Electricity Sector. The following e availability mmarize the y and y for base and thermal efficiency a best cas se scenarioos: city Deman Electric ons main Drivers nd Projectio D Scenario tion forecast Consumpt Demand (peak) forecast • Regrression analysis off historical consumption1 vs. GDP P and population nuous politica Contin al • Proje ections based on new n G IHS and BMI GDP and bility scenario instab popuulation estimates2 (each ( consumer ca ategory mated separately3) estim • m No mega-projects assuumed to kick-in Fore ecast built separate ely for each scenarrio • Regr f historical consumption1 vs. ression analysis of ording to the followi acco ing methodology: GDPP and population C • Correlation rical peak load and of histor d actual Slow political stability • ections based on IH Proje HS and BMI GDP and a el lectricity consumpt tion1 (estimated ba ased on scena ario popu ulation estimates (e each consumer cat tegory lectricity generation and net import, net el n of arately estimated) sepa wn consumption and technical losses ow s) • Megaa-projects assume ed to kick-in in 2022 2. D • Demand ecast based on (peak) fore onsumption foreca co ast growth rate S Mid Scenario (Updaated • Same projections as th S he “Slow Political Stability Slow political stability Scennario”, with a review m wed projection of mega- scena ario) ects (with a more re proje ) ealistic estimation) This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written wC’s Rapid As Source: Pw ssessment ega Project “Me up Projectio ts” Ramp-u ons wC’s Rapid As Source: Pw ssessment GEB-OFF/ 0 /4CT/0502978/100/00 20161020 49 4 / 61 STRICTED RES Operational Features Assumptions Scenario Simplified assumptions on Simplified assumptions on Variable name Under construction, contracted Existing plants and proposed plants (2017-2030) 1 All units suspended in 2016 Installed capacity/ Best recovered in 2017 No suspended units Suspended units All units suspended in 2016 (MW) Base No suspended units recovered in 2022 2 GECOL data collection ID23 GECOL data collection ID23 Best Availability capacity projections capacity projections (%) Average 2010-2016 GECOL Average 2010-2016 GECOL actual Base actual availability (%) by plant availability (%) by plant technology 3 Max 2010-2016 GECOL Max 2010-2016 GECOL actual Best Thermal efficiency actual efficiency (%) by plant efficiency (%) by plant technology (%) Average 2010-2016 GECOL Average 2010-2016 GECOL actual Base actual efficiency (%) by plant efficiency (%) by plant technology 4 Min 2010-2016 GECOL actual Best Technical losses T&D network technical losses (%) (%) Average 2010-2016 GECOL actual Base T&D network technical losses (%) This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Source: PwC’s Rapid Assessment Base Case Installed Capacity Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 135 Khoms Steam 480 4ST 480 480 480 480 480 Derna 130 2ST 0 0 0 Steam Tobruk 130 2ST 65 65 65 Misurata Steel 507 6ST 169 169 169 169 169 169 85 Tripoli South 500 5GT 500 500 500 500 500 500 500 500 500 500 Zwetina Gas 200 4GT 50 50 50 50 50 50 200 200 200 200 Gas Khoms Gas 600 4GT 600 600 600 600 600 600 600 600 600 600 West Mountain 936 6GT 936 936 936 936 936 936 936 936 936 936 936 936 936 936 936 Existing Sarir 820 3GT 570 570 570 570 570 570 820 820 820 820 820 820 820 820 820 6GT 780 990 990 990 990 990 990 990 990 990 990 990 990 990 990 Zawia 1.485 3ST 495 495 495 495 495 495 495 495 495 495 495 495 495 495 495 4GT 155 465 465 465 465 465 635 635 635 635 635 635 635 635 635 Benghazi North 945 2ST 310 0 0 0 0 0 310 310 310 310 310 310 310 310 310 2GT 570 570 570 570 570 570 570 570 570 570 570 570 570 570 570 CC Misurata CC 820 1ST 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 2GT 570 570 570 570 570 570 570 570 570 570 570 570 570 570 570 Benghazi North II 820 1ST 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 2GT 285 285 285 285 285 285 570 570 570 570 570 570 570 570 570 Zwetina 820 1ST 0 0 0 0 0 0 250 250 250 250 250 250 250 250 250 Khaleej (Gulf) 1.400 4ST 350 350 700 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 Under contr. / contracted Steam Tripoli West 1.400 4ST 1.050 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 Ubari 624 4GT 156 624 624 624 624 624 624 624 624 624 624 624 624 624 Gas Khoms II 524 2GT 524 524 524 524 524 524 524 524 524 524 524 524 524 524 Units of (PIAG) 235 5GT 235 235 235 235 235 235 235 235 235 235 235 235 235 235 Tripoli East 1.400 4ST 350 700 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 Tubrok 700 2ST 350 700 700 700 700 700 700 700 700 700 700 Steam Darna 700 2ST 700 700 700 700 700 700 700 700 700 Benghazi West 1.400 4ST 350 700 1.400 1.400 1.400 1.400 1.400 Sabha 855 3GT 285 855 855 855 855 855 855 855 855 855 855 Gas Tripoli South II 855 3GT 285 855 855 855 855 855 855 855 855 2GT 250 500 500 500 500 500 500 500 500 500 500 500 Proposed Misurata 750 1ST 250 250 250 250 250 250 250 250 250 250 250 4GT 550 550 1.090 1.090 1.090 1.090 1.090 1.090 1.090 1.090 1.090 1.090 Mellitah 1.640 2ST 270 550 550 550 550 550 550 550 550 550 550 2 GT 270 550 550 550 550 550 550 550 550 550 550 CC Zwetina II 820 1 ST 270 270 270 270 270 270 270 270 270 270 2 GT 270 550 550 550 550 550 550 550 550 550 Tubrok 820 1 ST 270 270 270 270 270 270 270 270 270 2 GT 270 550 550 550 550 550 550 Aboukammash 820 1 ST 270 270 270 270 270 270 Source: PwC’s Rapid Assessment GEB-OFF/4CT/0502978/100/00  20161020 50 / 61 RESTRICTED Best Case Installed Capacity Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 135 Khoms Steam 480 4ST 480 480 480 480 480 Derna 130 2ST 0 0 0 Steam Tobruk 130 2ST 65 65 65 Misurata Steel 507 6ST 169 169 169 169 169 169 85 Tripoli South 500 5GT 500 500 500 500 500 500 500 500 500 500 Zwetina Gas 200 4GT 50 50 200 200 200 200 200 200 200 200 Gas Khoms Gas 600 4GT 600 600 600 600 600 600 600 600 600 600 West Mountain 936 6GT 936 936 936 936 936 936 936 936 936 936 936 936 936 936 936 Existing Sarir 820 3GT 570 570 820 820 820 820 820 820 820 820 820 820 820 820 820 6GT 780 990 990 990 990 990 990 990 990 990 990 990 990 990 990 Zawia 1.485 3ST 495 495 495 495 495 495 495 495 495 495 495 495 495 495 495 4GT 155 465 635 635 635 635 635 635 635 635 635 635 635 635 635 Benghazi North 945 2ST 310 0 310 310 310 310 310 310 310 310 310 310 310 310 310 2GT 570 570 570 570 570 570 570 570 570 570 570 570 570 570 570 CC Misurata CC 820 1ST 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 2GT 570 570 570 570 570 570 570 570 570 570 570 570 570 570 570 Benghazi North II 820 1ST 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 2GT 285 285 570 570 570 570 570 570 570 570 570 570 570 570 570 Zwetina 820 1ST 0 0 250 250 250 250 250 250 250 250 250 250 250 250 250 Khaleej (Gulf) 1.400 4ST 350 350 700 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 Under contr. / contracted Steam Tripoli West 1.400 4ST 1.050 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 Ubari 624 4GT 156 624 624 624 624 624 624 624 624 624 624 624 624 624 Gas Khoms II 524 2GT 524 524 524 524 524 524 524 524 524 524 524 524 524 524 Units of (PIAG) 235 5GT 235 235 235 235 235 235 235 235 235 235 235 235 235 235 Tripoli East 1.400 4ST 350 700 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 1.400 Tubrok 700 2ST 350 700 700 700 700 700 700 700 700 700 700 Steam Darna 700 2ST 700 700 700 700 700 700 700 700 700 Benghazi West 1.400 4ST 350 700 1.400 1.400 1.400 1.400 1.400 Sabha 855 3GT 285 855 855 855 855 855 855 855 855 855 855 Gas Tripoli South II 855 3GT 285 855 855 855 855 855 855 855 855 2GT 250 500 500 500 500 500 500 500 500 500 500 500 Proposed Misurata 750 1ST 250 250 250 250 250 250 250 250 250 250 250 4GT 550 550 1.090 1.090 1.090 1.090 1.090 1.090 1.090 1.090 1.090 1.090 Mellitah 1.640 2ST 270 550 550 550 550 550 550 550 550 550 550 2 GT 270 550 550 550 550 550 550 550 550 550 550 CC Zwetina II 820 1 ST 270 270 270 270 270 270 270 270 270 270 2 GT 270 550 550 550 550 550 550 550 550 550 Tubrok 820 1 ST 270 270 270 270 270 270 270 270 270 2 GT 270 550 550 550 550 550 550 Aboukammash 820 1 ST 270 270 270 270 270 270 Source: PwC’s Rapid Assessment This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Base Case Availability Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 100% Khoms Steam 480 4ST 70% 78% 78% 78% 78% Derna 130 2ST 67% 67% Steam Tobruk 130 2ST 62% 39% 39% Misurata Steel 507 6ST 71% 71% 71% 71% 71% 71% 71% Tripoli South 500 5GT 85% 83% 83% 83% 83% 83% 83% 83% 83% 83% Zwetina Gas 200 4GT 50% 71% 71% 71% 71% 71% 71% 71% 71% 71% Gas Khoms Gas 600 4GT 82% 79% 79% 79% 79% 79% 79% 79% 79% 79% West Mountain 936 6GT 80% 79% 79% 79% 79% 79% 79% 79% 79% 79% 79% 79% 79% 79% 79% Existing Sarir 820 3GT 58% 55% 55% 55% 55% 55% 55% 55% 55% 55% 55% 55% 55% 55% 55% 6GT Zawia 1.485 71% 81% 81% 81% 81% 81% 81% 81% 81% 81% 81% 81% 81% 81% 81% 3ST 4GT Benghazi North 945 84% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 2ST 2GT CC Misurata CC 820 78% 76% 76% 76% 76% 76% 76% 76% 76% 76% 76% 76% 76% 76% 76% 1ST 2GT Benghazi North II 820 65% 68% 68% 68% 68% 68% 68% 68% 68% 68% 68% 68% 68% 68% 68% 1ST 2GT Zwetina 820 88% 71% 71% 71% 71% 71% 71% 71% 71% 71% 71% 71% 71% 71% 71% 1ST Khaleej (Gulf) 1.400 4ST 43% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% Under contr. / contracted Steam Tripoli West 1.400 4ST 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% Ubari 624 4GT 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% Gas Khoms II 524 2GT 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% Units of (PIAG) 235 5GT 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% Tripoli East 1.400 4ST 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% Tubrok 700 2ST 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% Steam Darna 700 2ST 65% 65% 65% 65% 65% 65% 65% 65% 65% Benghazi West 1.400 4ST 65% 65% 65% 65% 65% 65% 65% Sabha 855 3GT 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% Gas Tripoli South II 855 3GT 74% 74% 74% 74% 74% 74% 74% 74% 74% 2GT Proposed Misurata 750 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 1ST 4GT Mellitah 1.640 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 2ST 2 GT CC Zwetina II 820 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 1 ST 2 GT Tubrok 820 74% 74% 74% 74% 74% 74% 74% 74% 74% 74% 1 ST 2 GT Aboukammash 820 74% 74% 74% 74% 74% 74% 74% 1 ST Average 73% 74% 73% 71% 70% 70% 70% 70% 70% 70% 70% 70% 70% 70% 70% Source: PwC’s Rapid Assessment GEB-OFF/4CT/0502978/100/00  20161020 51 / 61 RESTRICTED Best Case Availability Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 100% Khoms Steam 480 4ST 70% 83% 83% 83% 83% Derna 130 2ST 46% 46% Steam Tobruk 130 2ST 62% 46% 46% Misurata Steel 507 6ST 71% 71% 71% 71% 71% 71% 71% Tripoli South 500 5GT 85% 80% 80% 80% 80% 80% 80% 80% 80% 80% Zwetina Gas 200 4GT 50% 80% 80% 80% 80% 80% 80% 80% 80% 80% Gas Khoms Gas 600 4GT 82% 80% 80% 80% 80% 80% 80% 80% 80% 80% West Mountain 936 6GT 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% Existing Sarir 820 3GT 58% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 6GT Zawia 1.485 71% 82% 82% 82% 82% 82% 82% 82% 82% 82% 82% 82% 82% 82% 82% 3ST 4GT Benghazi North 945 84% 78% 78% 78% 78% 78% 78% 78% 78% 78% 78% 78% 78% 78% 78% 2ST 2GT CC Misurata CC 820 78% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 1ST 2GT Benghazi North II 820 65% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 1ST 2GT Zwetina 820 88% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 1ST Khaleej (Gulf) 1.400 4ST 43% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Under contr. / contracted Steam Tripoli West 1.400 4ST 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Ubari 624 4GT 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65% Gas Khoms II 524 2GT 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% Units of (PIAG) 235 5GT 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% Tripoli East 1.400 4ST 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Tubrok 700 2ST 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Steam Darna 700 2ST 100% 100% 100% 100% 100% 100% 100% 100% 100% Benghazi West 1.400 4ST 100% 100% 100% 100% 100% 100% 100% Sabha 855 3GT 81% 81% 81% 81% 81% 81% 81% 81% 81% 81% 81% Gas Tripoli South II 855 3GT 81% 81% 81% 81% 81% 81% 81% 81% 81% 2GT Proposed Misurata 750 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 1ST 4GT Mellitah 1.640 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 2ST 2 GT CC Zwetina II 820 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 1 ST 2 GT Tubrok 820 84% 84% 84% 84% 84% 84% 84% 84% 84% 84% 1 ST 2 GT Aboukammash 820 84% 84% 84% 84% 84% 84% 84% 1 ST Average 73% 82% 82% 85% 86% 86% 86% 86% 87% 87% 88% 88% 88% 88% 88% This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Source: PwC’s Rapid Assessment Base Case Thermal Efficiency with Natural Gas Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 10% Khoms Steam 480 4ST 20% 21% 21% 21% 21% Derna 130 2ST / / / Steam Tobruk 130 2ST / / / Misurata Steel 507 6ST 31% 31% 31% 31% 31% 31% 31% Tripoli South 500 5GT 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% Zwetina Gas 200 4GT 31% 32% 32% 32% 32% 32% 32% 32% 32% 32% Gas Khoms Gas 600 4GT 29% 29% 29% 29% 29% 29% 29% 29% 29% 29% West Mountain 936 6GT 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% Existing Sarir 820 3GT / 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 6GT Zawia 1.485 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 3ST 4GT Benghazi North 945 46% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 2ST 2GT CC Misurata CC 820 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 1ST 2GT Benghazi North II 820 46% 30% 30% 30% 30% 30% 41% 41% 41% 41% 41% 41% 41% 41% 41% 1ST 2GT Zwetina 820 31% 30% 30% 30% 30% 30% 45% 45% 45% 45% 45% 45% 45% 45% 45% 1ST Khaleej (Gulf) 1.400 4ST / 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% Under contr. / contracted Steam Tripoli West 1.400 4ST 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% Ubari 624 4GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Gas Khoms II 524 2GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Units of (PIAG) 235 5GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Tripoli East 1.400 4ST 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% Tubrok 700 2ST 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% Steam Darna 700 2ST 21% 21% 21% 21% 21% 21% 21% 21% 21% Benghazi West 1.400 4ST 21% 21% 21% 21% 21% 21% 21% Sabha 855 3GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Gas Tripoli South II 855 3GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 2GT Proposed Misurata 750 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 1ST 4GT Mellitah 1.640 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 2ST 2 GT CC Zwetina II 820 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 1 ST 2 GT Tubrok 820 45% 45% 45% 45% 45% 45% 45% 45% 45% 45% 1 ST 2 GT Aboukammash 820 45% 45% 45% 45% 45% 45% 45% 1 ST Average 36% 34% 33% 32% 32% 33% 34% 34% 34% 34% 34% 34% 34% 34% 34% Source: PwC’s Rapid Assessment GEB-OFF/4CT/0502978/100/00  20161020 52 / 61 RESTRICTED Best Case Thermal Efficiency with Natural Gas Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 10% Khoms Steam 480 4ST 20% 23% 23% 23% 23% Derna 130 2ST / / / Steam Tobruk 130 2ST / / / Misurata Steel 507 6ST 31% 31% 31% 31% 31% 31% 31% Tripoli South 500 5GT 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% Zwetina Gas 200 4GT 31% 35% 35% 35% 35% 35% 35% 35% 35% 35% Gas Khoms Gas 600 4GT 29% 30% 30% 30% 30% 30% 30% 30% 30% 30% West Mountain 936 6GT 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% Existing Sarir 820 3GT / 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 6GT Zawia 1.485 45% 47% 47% 47% 47% 47% 47% 47% 47% 47% 47% 47% 47% 47% 47% 3ST 4GT Benghazi North 945 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 2ST 2GT CC Misurata CC 820 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 1ST 2GT Benghazi North II 820 46% 37% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 1ST 2GT Zwetina 820 31% 37% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 1ST Khaleej (Gulf) 1.400 4ST / 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% Under contr. / contracted Steam Tripoli West 1.400 4ST 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% Ubari 624 4GT 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% Gas Khoms II 524 2GT 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% Units of (PIAG) 235 5GT 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% Tripoli East 1.400 4ST 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% Tubrok 700 2ST 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% 31% Steam Darna 700 2ST 31% 31% 31% 31% 31% 31% 31% 31% 31% Benghazi West 1.400 4ST 31% 31% 31% 31% 31% 31% 31% Sabha 855 3GT 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% Gas Tripoli South II 855 3GT 37% 37% 37% 37% 37% 37% 37% 37% 37% 2GT Proposed Misurata 750 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 1ST 4GT Mellitah 1.640 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 2ST 2 GT CC Zwetina II 820 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 1 ST 2 GT Tubrok 820 49% 49% 49% 49% 49% 49% 49% 49% 49% 49% 1 ST 2 GT Aboukammash 820 49% 49% 49% 49% 49% 49% 49% 1 ST Average 36% 37% 38% 38% 38% 39% 39% 39% 39% 40% 40% 40% 40% 40% 40% This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Source: PwC’s Rapid Assessment Base Case Thermal Efficiency with Liquid Fuels Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 23% Khoms Steam 480 4ST 29% 29% 29% 29% 29% Derna 130 2ST 19% 23% 23% Steam Tobruk 130 2ST 24% 17% 17% Misurata Steel 507 6ST 20% 22% 22% 22% 22% 22% 22% Tripoli South 500 5GT 28% 26% 26% 26% 26% 26% 26% 26% 26% 26% Zwetina Gas 200 4GT 24% 25% 25% 25% 25% 25% 25% 25% 25% 25% Gas Khoms Gas 600 4GT 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% West Mountain 936 6GT / 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% Existing Sarir 820 3GT 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 6GT Zawia 1.485 40% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 3ST 4GT Benghazi North 945 31% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% 2ST 2GT CC Misurata CC 820 32% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% 1ST 2GT Benghazi North II 820 31% 27% 27% 27% 27% 27% 28% 28% 28% 28% 28% 28% 28% 28% 28% 1ST 2GT Zwetina 820 24% 27% 27% 27% 27% 27% 36% 36% 36% 36% 36% 36% 36% 36% 36% 1ST Khaleej (Gulf) 1.400 4ST 30% 32% 32% 32% 32% 32% 32% 32% 32% 32% 32% 32% 32% 32% 32% Under contr. / contracted Steam Tripoli West 1.400 4ST 24% 24% 24% 24% 24% 24% 24% 24% 24% 24% 24% 24% Ubari 624 4GT 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% Gas Khoms II 524 2GT 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% Units of (PIAG) 235 5GT 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% Tripoli East 1.400 4ST 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% Tubrok 700 2ST 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% 21% Steam Darna 700 2ST 21% 21% 21% 21% 21% 21% 21% 21% 21% Benghazi West 1.400 4ST 21% 21% 21% 21% 21% 21% 21% Sabha 855 3GT 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% 27% Gas Tripoli South II 855 3GT 27% 27% 27% 27% 27% 27% 27% 27% 27% 2GT Proposed Misurata 750 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 1ST 4GT Mellitah 1.640 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 2ST 2 GT CC Zwetina II 820 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 1 ST 2 GT Tubrok 820 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 1 ST 2 GT Aboukammash 820 36% 36% 36% 36% 36% 36% 36% 1 ST Average 30% 31% 31% 31% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Source: PwC’s Rapid Assessment GEB-OFF/4CT/0502978/100/00  20161020 53 / 61 RESTRICTED Best Case Thermal Efficiency with Liquid Fuels Type of plant Power station Inst. cap Unit 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Various Small / rented N/A N/A 23% Khoms Steam 480 4ST 29% 30% 30% 30% 30% Derna 130 2ST 19% 29% 29% Steam Tobruk 130 2ST 24% 24% 24% Misurata Steel 507 6ST 20% 26% 26% 26% 26% 26% 26% Tripoli South 500 5GT 28% 28% 28% 28% 28% 28% 28% 28% 28% 28% Zwetina Gas 200 4GT 24% 26% 26% 26% 26% 26% 26% 26% 26% 26% Gas Khoms Gas 600 4GT 28% 30% 30% 30% 30% 30% 30% 30% 30% 30% West Mountain 936 6GT / 29% 29% 29% 29% 29% 29% 29% 29% 29% 29% 29% 29% 29% 29% Existing Sarir 820 3GT 27% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 6GT Zawia 1.485 40% 43% 43% 43% 43% 43% 43% 43% 43% 43% 43% 43% 43% 43% 43% 3ST 4GT Benghazi North 945 31% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 2ST 2GT CC Misurata CC 820 32% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 1ST 2GT Benghazi North II 820 31% 30% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 34% 1ST 2GT Zwetina 820 24% 30% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 1ST Khaleej (Gulf) 1.400 4ST 30% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% 36% Under contr. / contracted Steam Tripoli West 1.400 4ST 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% Ubari 624 4GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Gas Khoms II 524 2GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Units of (PIAG) 235 5GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Tripoli East 1.400 4ST 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% Tubrok 700 2ST 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% Steam Darna 700 2ST 33% 33% 33% 33% 33% 33% 33% 33% 33% Benghazi West 1.400 4ST 33% 33% 33% 33% 33% 33% 33% Sabha 855 3GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Gas Tripoli South II 855 3GT 30% 30% 30% 30% 30% 30% 30% 30% 30% 2GT Proposed Misurata 750 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 1ST 4GT Mellitah 1.640 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 2ST 2 GT CC Zwetina II 820 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 1 ST 2 GT Tubrok 820 46% 46% 46% 46% 46% 46% 46% 46% 46% 46% 1 ST 2 GT Aboukammash 820 46% 46% 46% 46% 46% 46% 46% 1 ST Average 30% 34% 35% 35% 36% 37% 37% 37% 37% 37% 37% 37% 37% 37% 37% Source: PwC’s Rapid Assessment This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Technical Losses Scenario 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 17.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 14.6% 17.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% 18.6% Source: PwC’s Rapid Assessment 7.5. MODELING RESULTS. 7.5.1. Pipeline Expansions. The following tables summarizes the transportation system expansions requirements (based on an initial configuration36) for each alternative and scenario. 36 To be updated after the site visit and further the technical study of aspects of the gas transportation system and High Level Conceptual Design of the LNG import option. GEB-OFF/4CT/0502978/100/00  20161020 54 / 61 RESTRICTED Short Term Solution Mellitah - Zawia Zawia - Tripoli Tripoli - Khoms Khoms - Misurata Misurata - Gulf (PP) Gulf - Brega Brega-Zwetina Zwetina-Benghazi Scenario COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d Base - - - - - - - - - - - - 2021 +141 - - GEB-OFF/4CT/0502978/100/00  Mid - - - - - - - - - - - - 2020 +118 - - Best - - - - - - - - - - - - 2020 +113 - - LNG in Brega 20161020 Mellitah - Zawia Zawia - Tripoli Tripoli - Khoms Khoms - Misurata Misurata - Gulf (PP) Gulf - Brega Brega-Zwetina Zwetina-Benghazi Scenario COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d 2020 +353 2020 +424 2023 +353 Base - - - - 2029 +177 2026 +353 2026 +353 2021 +141 - - 2028 +353 2028 +353 2028 +353 2021 +353 2021 +353 2026 +194 Mid - - - - 2029 +177 2026 +353 2026 +353 2020 +118 - - 2028 +431 2028 +353 2028 +424 2021 +353 2021 +353 2024 +353 2024 +353 2024 +353 Best - - - - 2028 +441 2020 +158 - - 2028 +530 2026 +353 2026 +353 2028 +247 2028 +600 LNG in the West Mellitah - Zawia Zawia - Tripoli Tripoli - Khoms Khoms - Misurata Misurata - Gulf (PP) Gulf - Brega Brega-Zwetina Zwetina-Benghazi Scenario COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d Base - - - - 2028 +180 2028 +127 2020 +71 2020 +71 2021 +141 - - 55 / 61 Mid - - - - 2029 +177 2028 +353 - - - - 2020 +118 - - Best - - - - 2028 +442 2027 +565 - - - - 2020 +159 - - Dedicated LNG Mellitah - Zawia Zawia - Tripoli Tripoli - Khoms Khoms - Misurata Misurata - Gulf (PP) Gulf - Brega Brega-Zwetina Zwetina-Benghazi Scenario COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d COD ∆mmscf/d Base - - - - - - - - - - - - 2022 +131 - - Mid - - - - - - - - - - - - 2020 +118 - - Best - - - - - - - - - - - - 2020 +159 - - RESTRICTED This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Short Term Solution Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 10 10 10 10 - 39 39 39 - - - - - Liquid Fuels - - - - - - - - - - - - - - Khoms Gas Natural Gas - 15 - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 207 207 207 207 207 - 24 49 11 - 19 87 155 207 Liquid Fuels - - - - - - - - - 99 166 254 254 254 Zawia Natural Gas 232 232 232 232 232 232 232 232 232 141 82 - - - Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 74 74 74 74 74 150 150 150 150 150 150 150 150 150 Liquid Fuels - - - - - - - - - - - 131 131 131 Misurata CC Natural Gas 110 110 110 110 110 110 110 110 110 110 110 - - - Liquid Fuels - - - - - - - - - - - - - - “Base” scenario: Benghazi North II Natural Gas 161 161 161 161 - 109 118 118 118 76 118 118 118 118 Liquid Fuels - - - - - - - - - - - 64 141 141 GEB-OFF/4CT/0502978/100/00  Zwetina Natural Gas 59 59 59 40 - 112 112 112 112 112 112 61 - - Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 112 112 108 - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 38 50 - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - 134 134 Misurata Natural Gas - - 36 107 107 107 107 107 107 107 107 107 - - 20161020 Liquid Fuels - - - - - - - - - - - - 28 254 Mellitah Natural Gas - - 78 117 234 234 234 234 234 234 234 234 213 30 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 39 117 117 117 117 117 117 117 117 117 117 Liquid Fuels - - - - - - - - - 173 173 173 173 173 Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 91 91 91 83 - - - - - - - - 18 Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 34 34 34 34 - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 39 117 117 117 117 117 117 Total Liquids Fuels - - - - - - - - - 272 339 621 862 1.088 Total Natural Gas 1.037 1.154 1.199 1.221 1.207 1.171 1.243 1.306 1.347 1.165 1.166 991 870 757 Total 1.037 1.154 1.199 1.221 1.207 1.171 1.243 1.306 1.347 1.437 1.505 1.612 1.732 1.844 LNG in Brega Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 10 10 10 10 - 39 39 39 - - - - - 7.5.2. Fuel consumption by Power Plant. Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 34 34 34 34 - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - West Mountain 56 / 61 Natural Gas 207 207 207 207 207 - 24 49 11 125 199 207 207 207 Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 199 199 199 199 199 232 232 232 232 232 232 232 232 232 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 74 74 74 74 74 150 150 150 150 150 150 150 150 150 Liquid Fuels - - - - - - - - - - - - - - Misurata CC Natural Gas 110 110 110 110 110 110 110 110 110 110 110 110 110 110 Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 161 161 161 161 41 109 118 118 118 118 118 118 118 118 Liquid Fuels - - - - - - - - - - - - - - Zwetina power plant in order to fully supply the average electricity demand. Natural Gas 117 117 117 89 - 112 112 112 112 112 112 112 112 112 Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 112 112 99 - - - - - - - - - 3 74 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas                29,1                50,3                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐ Liquid Fuels - - - - - - - - - - - - - - Misurata Natural Gas - - 36 107 107 107 107 107 107 107 107 107 107 107 Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 78 117 234 234 234 234 234 234 234 234 234 234 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 39 117 117 117 117 117 117 117 117 117 117 Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 91 91 91 91 - - - - - - 63 130 130 Liquid Fuels - 65 15 - - - - - - - - - - - Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 39 117 117 117 117 117 117 Total Liquids Fuels - 65 15 - - - - - - - - - - - Total Natural Gas 1.053 1.165 1.215 1.237 1.223 1.171 1.243 1.306 1.347 1.422 1.496 1.567 1.637 1.709 Total 1.053 1.230 1.230 1.237 1.223 1.171 1.243 1.306 1.347 1.422 1.496 1.567 1.637 1.709 The following tables summarize the fuel consumption (natural gas, LFO and HFO) by RESTRICTED This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written LNG in the West Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 10 10 10 10 - 39 39 39 - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 34 34 34 34 - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 207 207 207 207 207 - 24 49 11 125 199 207 207 207 Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 199 199 199 199 199 232 232 232 232 232 232 232 232 232 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 74 74 74 74 74 150 150 150 150 150 150 150 150 150 Liquid Fuels - - - - - - - - - - - - - - Misurata CC Natural Gas 110 110 110 110 110 110 110 110 110 110 110 110 110 110 GEB-OFF/4CT/0502978/100/00  Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 161 161 161 161 41 109 118 118 118 118 118 118 118 118 Liquid Fuels - - - - - - - - - - - - - - Zwetina Natural Gas 117 117 117 89 - 112 112 112 112 112 112 112 112 112 Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 112 112 99 - - - - - - - - - 3 74 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) 20161020 Natural Gas                29,1                50,3                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐                  ‐ Liquid Fuels - - - - - - - - - - - - - - Misurata Natural Gas - - 36 107 107 107 107 107 107 107 107 107 107 107 Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 78 117 234 234 234 234 234 234 234 234 234 234 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 39 117 117 117 117 117 117 117 117 117 117 Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 91 91 91 91 - - - - - - 63 130 130 Liquid Fuels - 65 15 - - - - - - - - - - - Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 39 117 117 117 117 117 117 Total Liquids Fuels - 65 15 - - - - - - - - - - - Total Natural Gas 1.053 1.165 1.215 1.237 1.223 1.171 1.243 1.306 1.347 1.422 1.496 1.567 1.637 1.709 Total 1.053 1.230 1.230 1.237 1.223 1.171 1.243 1.306 1.347 1.422 1.496 1.567 1.637 1.709 Dedicated LNG Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 10 10 10 10 - 39 39 39 - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 34 34 - - - - - - - - - - - 57 / 61 Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 207 207 207 207 207 - 24 49 11 125 117 87 155 199 Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 199 199 199 199 199 232 232 232 232 232 232 232 232 232 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 74 74 74 74 74 141 150 150 150 150 150 150 150 150 Liquid Fuels - - - - - - - - - - - 120 132 132 Misurata CC Natural Gas 110 110 110 110 110 110 110 110 110 110 110 10 - - Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 161 161 161 161 117 108 108 108 108 108 108 108 108 108 Liquid Fuels - - - - - - - - - - - - 140 140 Zwetina Natural Gas 117 117 117 59 - 112 112 112 112 112 112 112 - - Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 112 112 99 107 - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 29                50,3                  ‐ - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - 84 134 Misurata Natural Gas - - 36 107 107 107 107 107 107 107 107 107 40 - Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 78 117 234 234 234 234 234 234 234 234 234 234 Liquid Fuels - - - - - - - - - - - - - 146 Zwetina II Natural Gas - - - 39 117 117 117 117 117 117 117 117 117 - Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 91 91 - - - - - - - - - - - Liquid Fuels - 65 15 - - - - - - - 79 175 175 175 Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 39 117 117 117 117 117 117 Total Liquids Fuels - 65 15 - - - - - - - 79 294 531 727 Total Natural Gas 1.053 1.165 1.215 1.189 1.175 1.161 1.233 1.296 1.337 1.412 1.404 1.274 1.153 1.040 Total 1.053 1.230 1.230 1.189 1.175 1.161 1.233 1.296 1.337 1.412 1.483 1.568 1.683 1.767 RESTRICTED This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Short Term Solution Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 67 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 135 60 - - - - 11 - - - - 13 92 Liquid Fuels - - - - - - - - - - - - - - “Mid” scenario: Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 106 139 139 139 139 139 139 139 139 GEB-OFF/4CT/0502978/100/00  Liquid Fuels - - - - - - - - - - 88 131 131 131 Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 122 38 - - - Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 162 130 130 77 - - 76 130 127 43 3 65 130 130 Liquid Fuels - - - - - - - - - - - 131 131 131 Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 122 - - - Liquid Fuels - - - - - - - - - - - - - - 20161020 Khoms II Natural Gas 98 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas                44,1 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - 35 113 113 Misurata Natural Gas - - 35 106 106 106 106 106 106 106 106 74 - - Liquid Fuels - - - - - - - - - - - - 134 261 Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 244 119 - Liquid Fuels - - - - - - - - - - - - - 78 Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 122 49 Liquid Fuels - - - - - - - - - 198 339 339 339 339 Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 122 Total Liquids Fuels - - - - - - - - - 198 427 636 847 1.052 Total Natural Gas 886 873 915 954 993 1.047 1.156 1.261 1.329 1.245 1.121 991 870 757 Total 886 873 915 954 993 1.047 1.156 1.261 1.329 1.443 1.548 1.626 1.717 1.809 LNG in Brega Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 - - - - - - - - - - - - - 58 / 61 Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 162 60 - - - - 11 - 84 162 162 162 162 Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 67 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 106 139 139 139 139 139 139 139 139 Liquid Fuels - - - - - - - - - - - - - - Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 162 102 130 77 - - 76 130 127 130 130 130 130 130 Liquid Fuels - - - - - - - - - - - - - - Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 98 8 - - - - - - - - 9 86 98 98 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 44 - - - - - - - - - - - 44 44 Liquid Fuels - - - - - - - - - - - - - - Misurata Natural Gas - - 35 106 106 106 106 106 106 106 106 106 106 106 Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 244 244 244 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Tripoli South Natural Gas - - - - - - - - - - - - 38 117 Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 122 Total Liquids Fuels - - - - - - - - - - - - - - Total Natural Gas 886 879 915 954 993 1.047 1.156 1.261 1.329 1.416 1.502 1.580 1.673 1.752 Total 886 879 915 954 993 1.047 1.156 1.261 1.329 1.416 1.502 1.580 1.673 1.752 RESTRICTED This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written LNG in the West Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 162 60 - - - - 11 - 84 162 162 162 162 Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 67 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 106 139 139 139 139 139 139 139 139 GEB-OFF/4CT/0502978/100/00  Liquid Fuels - - - - - - - - - - - - - - Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 162 102 130 77 - - 76 130 127 130 130 130 130 130 Liquid Fuels - - - - - - - - - - - - - - Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Khoms II 20161020 Natural Gas 98 8 - - - - - - - - 9 86 98 98 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 44 - - - - - - - - - - - 44 44 Liquid Fuels - - - - - - - - - - - - - - Misurata Natural Gas - - 35 106 106 106 106 106 106 106 106 106 106 106 Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 244 244 244 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Tripoli South Natural Gas - - - - - - - - - - - - 38 117 Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 122 Total Liquids Fuels - - - - - - - - - - - - - - Total Natural Gas 886 879 915 954 993 1.047 1.156 1.261 1.329 1.416 1.502 1.580 1.673 1.752 Total 886 879 915 954 993 1.047 1.156 1.261 1.329 1.416 1.502 1.580 1.673 1.752 Dedicated LNG Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas 112 135 60 - - - - 11 - 84 80 - 13 92 Liquid Fuels - - - - - - - - - - - - - - Khoms Gas Natural Gas - - - - - - - - - - - - - - 59 / 61 Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 106 139 139 139 139 139 139 139 139 Liquid Fuels - - - - - - - - - - - - 131 131 Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 122 122 122 - - Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 162 130 130 77 - - 76 130 127 130 130 80 130 131 Liquid Fuels - - - - - - - - - - - - 67 131 Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 122 122 60 - Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 98 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 44 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - 113 Misurata Natural Gas - - 35 106 106 106 106 106 106 106 106 106 106 0 Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 244 244 244 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Tobruk CC Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - 92 318 339 339 Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 122 Total Liquids Fuels - - - - - - - - - - 92 318 537 713 Total Natural Gas 887 873 915 954 993 1.047 1.156 1.261 1.329 1.416 1.412 1.282 1.161 1.074 Total 887 873 915 954 993 1.047 1.156 1.261 1.329 1.416 1.503 1.599 1.698 1.787 RESTRICTED This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written Short Term Solution Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 67 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 110 139 139 139 139 139 139 139 139 Liquid Fuels - - - - - - - - - 109 131 131 131 131 “Best” scenario: Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 19 - - - - Liquid Fuels - - - - - - - - - - - - - - GEB-OFF/4CT/0502978/100/00  Benghazi North II Natural Gas 162 130 130 77 - - 130 130 130 130 130 130 130 130 Liquid Fuels - - - - - - - - - - 131 131 131 131 Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 - - - - Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 98 - - - - - - 34 - - - 79 93 98 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 44 - - - - - - - - - - - - 4 Liquid Fuels - - - - - - - - - - 109 113 113 113 20161020 Misurata Natural Gas - - 35 106 106 106 106 106 106 106 3 - - - Liquid Fuels - - - - - - - - - - - 247 261 261 Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 13 - - Liquid Fuels - - - - - - - - - - - - 131 131 Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 - - Liquid Fuels - - - - - - - - - - - - - 74 Tripoli West Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - 102 131 Tobruk CC Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - 152 339 339 339 339 339 Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 135 60 - - - 33 162 74 16 136 162 162 162 Liquid Fuels - - - - - - - - - - - - - 131 Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 - Total Liquids Fuels - - - - - - - - 152 448 710 960 1.208 1.441 Total Natural Gas 886 873 915 954 993 1.051 1.243 1.445 1.406 1.245 1.121 991 870 757 Total 886 873 915 954 993 1.051 1.243 1.445 1.558 1.693 1.831 1.952 2.078 2.198 LNG in Brega Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel 60 / 61 Natural Gas 34 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 67 - - - - - - - - - - 123 210 210 Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 110 139 139 139 139 139 139 139 139 Liquid Fuels - - - - - - - - - - - - - - Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 162 102 130 77 - - 130 130 130 130 130 130 130 130 Liquid Fuels - - - - - - - - - - - - - - Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 98 8 - - - - - 34 60 98 98 98 98 98 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 44 - - - - - - - - 44 44 44 44 44 Liquid Fuels - - - - - - - - - - - - - - Misurata Natural Gas - - 35 106 106 106 106 106 106 106 106 106 106 106 Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 244 244 244 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Khaleej (Gulf) Natural Gas - - - - - - - - - - - - 83 213 Liquid Fuels - - - - - - - - - - - - - - Tripoli South II Natural Gas - - - - - - - - - 41 160 162 162 162 Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 162 60 - - - 33 162 162 162 162 162 162 162 Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 122 Total Liquids Fuels - - - - - - - - - - - - - - Total Natural Gas 886 879 915 954 993 1.051 1.243 1.445 1.553 1.676 1.796 1.921 2.091 2.220 Total 886 879 915 954 993 1.051 1.243 1.445 1.553 1.676 1.796 1.921 2.091 2.220 RESTRICTED This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written LNG in the West Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Misurata Steel Natural Gas 34 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 67 - - - - - - - - - - 123 210 210 Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 110 139 139 139 139 139 139 139 139 Liquid Fuels - - - - - - - - - - - - - - Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Benghazi North II GEB-OFF/4CT/0502978/100/00  Natural Gas 162 102 130 77 - - 130 130 130 130 130 130 130 130 Liquid Fuels - - - - - - - - - - - - - - Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 98 8 - - - - - 34 60 98 98 98 98 98 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 44 - - - - - - - - 44 44 44 44 44 20161020 Liquid Fuels - - - - - - - - - - - - - - Misurata Natural Gas - - 35 106 106 106 106 106 106 106 106 106 106 106 Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 244 244 244 Liquid Fuels - - - - - - - - - - - - - - Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 122 122 Liquid Fuels - - - - - - - - - - - - - - Khaleej (Gulf) Natural Gas - - - - - - - - - - - - 83 213 Liquid Fuels - - - - - - - - - - - - - - Tripoli South II Natural Gas - - - - - - - - - 41 160 162 162 162 Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 162 60 - - - 33 162 162 162 162 162 162 162 Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 122 Total Liquids Fuels - - - - - - - - - - - - - - Total Natural Gas 886 879 915 954 993 1.051 1.243 1.445 1.553 1.676 1.796 1.921 2.091 2.220 Total 886 879 915 954 993 1.051 1.243 1.445 1.553 1.676 1.796 1.921 2.091 2.220 Dedicated LNG Consumption (mmscf/d eq.) Power Plant Fuel 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Liquid Fuels - - - - - - - - - - - - - - Zwetina Gas Natural Gas 10 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Sarir Natural Gas - 135 60 - - - 33 162 162 162 136 162 162 162 61 / 61 Liquid Fuels - - - - - - - - - - - - - - West Mountain Natural Gas 67 - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Zawia Natural Gas 225 225 225 225 225 225 225 225 225 225 225 225 225 225 Liquid Fuels - - - - - - - - - - - - - - Benghazi North Natural Gas 68 139 139 139 52 110 139 139 139 139 139 139 139 139 Liquid Fuels - - - - - - - - - - 60 131 131 131 Misurata CC Natural Gas 122 122 122 122 122 122 122 122 122 122 66 - - - Liquid Fuels - - - - - - - - - - - - - - Benghazi North II Natural Gas 162 130 130 77 - - 130 130 130 130 130 130 130 130 Liquid Fuels - - - - - - - - - - - 131 131 131 Zwetina Natural Gas 56 122 122 122 122 122 122 122 122 122 122 - - - Liquid Fuels - - - - - - - - - - - - - - Khoms II Natural Gas 98 - - - - - - 34 60 42 - 79 98 27 Liquid Fuels - - - - - - - - - - - - - - Units of (PIAG) Natural Gas 44 - - - - - - - - - - - 41 - Liquid Fuels - - - - - - - - - - - 49 113 113 Misurata Natural Gas - - 35 106 106 106 106 106 106 106 106 59 - - Liquid Fuels - - - - - - - - - - - - - - Mellitah Natural Gas - - 82 122 244 244 244 244 244 244 244 244 244 244 Liquid Fuels - - - - - - - - - - - - 131 131 Zwetina II Natural Gas - - - 40 122 122 122 122 122 122 122 122 - - Liquid Fuels - - - - - - - - - - - - 67 131 Tobruk CC Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - 145 339 339 339 339 Khaleej (Gulf) Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - 159 Tripoli West Natural Gas - - - - - - - - - - - - - - Liquid Fuels - - - - - - - - - - - - - - Aboukammash Natural Gas - - - - - - - 40 122 122 122 122 122 122 Total Liquids Fuels - - - - - - - - - 145 399 650 911 1.133 Total Natural Gas 852 873 915 954 993 1.051 1.243 1.445 1.553 1.536 1.412 1.282 1.161 1.048 Total 852 873 915 954 993 1.051 1.243 1.445 1.553 1.680 1.811 1.932 2.072 2.181 RESTRICTED This document is the property of Tractebel Engineering S.A. Any duplication or transmission to third parties is forbidden without prior written