Report No. 40099-YE Republic of Yemen A Natural Gas Incentive Framework June 2007 Sustainable Development Department Middle East and North Africa Region Document of the World Bank IRR InternalRate ofReturn JCC Japan Crude Cocktail kW Kilowatt kwh KilowattHour(s) LFO LightFuel Oil LPG Liquefied PetroleumGas LRMC Long Run Marginal Cost LRMCC Long Run Marginal Capacity Cost LRAIC Long Run Average Incremental Cost LRIC Long Run IncrementalCost LSFO Light SulfurFuel Oil LNG LiquefiedNatural Gas Mbbl Million barrels Mcm Million Cubic Meter MENA MiddleEast andNorth Afiica MFN MostFavorite Nation MOE Ministry of Electricity MOM Ministry of Oil and Minerals MOU Memorandum of Understanding mmcf Million Cubic Feet -'Pa Million Tons per Annum Mmbtu BillionBritish ThermalUnits mmbtu Million BritishThermalUnits MRC Marib Refmery Company MW Megawatt NAG Non-Associated Gas NGP National Gas Pipeline NTPA Negotiated Third Party Access NPV Net Present Value OCGT Open Cycle Gas Turbine O&M Operationand Maintenance PEPA PetroleumExploration and Production Authority PEC Public Electricity Cooperation PSA Production SharingAgreement PSC Production SharingContract RTPA RegulatedThird Party Access Tcf Trillion CubicFeet TPES Total Primary Energy Supply UX United Kingdom us United States WACOG Weighted Average Cost of Gas YC Yemen Company YGC Yemen Gas Company YLNG Yemen LiquefiedNaturalGas YOC Yemen Oil Company YOGC Yemen Oil and Gas Company YPC Yemen Petroleum Company YtF Yet-to-fmd Fields Vice President: Daniela Gressani CountryDirector: Emmanuel Mbi SectorDirector: Inger Andersen Sector Manager: Jonathan D. Walters Task Team Leader: Franz Gerner Contents Acknowledgments ............................................................................................................ix Conversion Table ...............................................................................................................x Units of Measure ..............................................................................................................xi ............................................................................................XIII... Acronyms and Abbreviations ExecutiveSummary .........................................................................................................xvii 1. MacroeconomicOutlook for Yemen ...............................................................................1 Macroeconomic Environment ....................................................................................1 Potential Sources of Economic Growth .......................................................................2 Nonoil Sector ......................................................................................................2 RevenueGenerated by Switchingto Natural Gas in the Power Sector ......................3 RevenueGenerated from LNG Export ...................................................................4 Government and State Revenues Flows from Natural Gas ......................................5 Conclusions ............................................................................................................8 2. Determiningthe Economic Costs of Natural Gas ..........................................................11 Introduction ..........................................................................................................11 Economicversus Financial Costs of Gas ..................................................................12 Approaches and Methods for Determining Economic Costs ......................................12 Gas Production Costs ............................................................................................13 Gas Transmission and Distribution Costs ............................................................15 Economic Costing Options for Yemen ......................................................................15 Indicative Cost Calculations ....................................................................................18 Opportunity Costs ............................................................................................. 18 Marginal Costs .................................................................................................20 Netback-to-MarketValue ...................................................................................21 Conclusions ..........................................................................................................24 REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK 3 A Framework for Developing the Domestic Gas Market . ................................................27 Introduction ..........................................................................................................27 The Power Sector as Anchor Customer .................................................................... 28 Future Gas Demand and the Importance of Anchor Load ....................................28 The Characteristicsof the Power Sector ...............................................................29 The Marib Plant and Gas Pipeline ...........................................................................33 The National Gas Pipeline(NGP) ............................................................................35 The Two-phase Approach ..................................................................................35 Potential Gas Demand of Power Generation ........................................................36 The Economicsof the National Gas Pipeline ........................................................38 Establishment of an Attractive Gas Industry Structure ........................................39 The Current Natural Gas Industry Structure ........................................................39 The Gas Market Players .....................................................................................40 A Future Gas Market Structure ...........................................................................43 Private Participation in the Development of the National Gas Pipeline ....................44 Key Contract/Market Design Issues ....................................................................46 Developmentof an Efficient Regulatory Regime ........................................................52 Why Regulation of the Gas Sector is Necessary ....................................................52 What Regulation Intends to Achieve .....................................................................52 What in the Gas Sector should be Regulated .......................................................53 How should the Gas Sector be Regulated ............................................................53 Who should Regulate ........................................................................................56 Conclusions ..........................................................................................................58 4 Analysis of the Key Features of Proposed Legal and Fiscal Terms for the Exploration. . Developmentand Production of Hydrocarbons ........................................................ 61 Introduction ..........................................................................................................61 Alternative Petroleum Legal and Fiscal Systems:'Advantages and Disadvantages ........61 Legal Frameworksfor the Petroleum Sector .........................................................62 Elements of Successful Legal Frameworks ...........................................................65 Fiscal Regimesfor the Petroleum Sector: Tax and Nontax Instruments ....................65 Elementsof Good Petroleum Fiscal Regimes ........................................................67 Key Features of Yemen's 2006 Model PSA ................................................................67 Legal Framework and Institutional Set-up ...........................................................67 CONTENTS Procedures for the Award of Petroleum Rights .....................................................70 Elements of the 2006 Model PSA ........................................................................72 Other Countries' Terms ..........................................................................................79 Conclusions ..........................................................................................................82 5. Encouragingthe Developmentof Gas Reserves ............................................................83 Introduction ..........................................................................................................83 Barriers to the Development of Gas Explorationand ProductionActivities ...................83 Options to Encourage Gas ExplorationActivities ......................................................88 International Experience ....................................................................................88 Assessment of Options to Encourage Gas Explorationin Yemen ........................... 90 Gas PriceVolatility and Risk Mitigation ...................................................................103 Gas PriceVolatility and Government Revenue ....................................................104 Conclusions ........................................................................................................110 Annex 1: Governmentand State Revenue from Gas Sales ............................................113 Annex 2: Gas-In-Place ..............................................................................................119 Annex 3: Tax and Nontax Instruments ........................................................................121 Annex 4: UndiscoveredFields ....................................................................................131 Annex 5: Fiscal ModelsSimulation .............................................................................135 Annex 6: Hedging with Derivatives: Examplesand Strategies .......................................153 REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Tables Table 1.1. Government and State Take . 2008-28 (in US$ billion) .................................7 Table 2.1 : Economic Costing Options for Domestic Gas ........................................16 Table2.2: Economic Costing Principles at the Well Head for Domestic Usage............... 17 Table 2.3: Opportunity Cost for Domestic Gas in Yemen ........................................ 18 Table 2.4: Natural Gas Price Forecasts (in US$/MMBTU) ........................................ 19 Table2.5: Opportunity Cost of Natural Gas in Yemen until 2030 ................................ 20 Table 2.6: FinancialNetback of ExistingOil-fired Plant ........................................ 22 Table 2.7: Economic Netback from Existing Oil-fired Plant ........................................23 Table 3.1 : Existing Generation Plants Suitable for Conversion to Natural Gas ..............30 Table 3.2: Commissionedand Planned Gas-fired Power Plants ...................................31 Table 3.3: Economic Netback for Natural Gas for New OCGT and CCGT Plant........... 32 Table 3.4: Hizyaz 1& 2 and Economic Netback for Natural Gas .................................. 34 Table 3.5: Power Generation Costs of New Marib OCGT Plants..................................35 Table 3.6: Potential Annual Gas Demand of Power Plants Using OCGT Technology ......37 Table 3.7: The Economic Feasibility of the National Gas Pipeline ................................. 38 Table 3.8: Maximum Gas Transportation Tariff on National Gas Pipeline .....................39 Table 3.9: Natural Gas Transmission Pipeline Investment by Region 1990-2005 ...........44 Table 3.10: Natural Gas Transmission Pipeline by Investment-type1990-2005 ..............45 Table 3.1 1 : Coverage of Potential Gas Law.................................................................. 54 Table 3.12: Coverage of Subordinate Instruments .......................................................55 Table4.1 : Main Difference between ConcessionarySystems and.................................64 Petroleum Sharing Agreements Table4.2: Key Elements of Successful Petroleum Legal Frameworks............................. 66 Table4.3: Model MoU: Biddable terms .....................................................................71 Table4.4: Fiscal Parameters of the 2006 Model PSA and 2005 Model MoU ................. 77 CONTENTS Table4.5: 2006 Model PSA: Suggested Improvements ........................................79 Table4.6: Features of Petroleum Fiscal Regimes in Selected Countries .........................81 Table 5.1: Potential Barriers to Investment in Gas E&P in Yemen ..................................84 Table 5.2: Key Parameters. EconomicModel of a Hypothetical PetroleumProject .........97 Table 5.3: Fiscal System Indices ..............................................................................99 Table 5.4: Break-evenPrice .....................................................................................101 TableAl.l: Revenue Generatedfrom Gas Sales to the Power Sector ............................114 TableAl.2: HFO Fuel Cost for Power Generation .......................................................115 TableAl.3: Government and State Revenuefrom LNG Export . Price Scenario Low ...... 116 TableAl.4: Government and State Revenuefrom LNG Export. Price Scenario Base ..... 117 TableAl.5: Government and State Revenuefrom LNG Export. Price Scenario High ..... 118 TableA5.1: Oil Project ..............................................................................................136 TableA5.2: Associated Gas Project ...........................................................................141 TableA5.3: Nonassociated Gas Project .....................................................................146 TableA5.4: NOC Participation . NonassociatedGas Project .......................................151 Figure 1: ExpectedState Revenuefrom Gas and Oil Sales (2008-28) .........................xviii Figure 1.1. Projected Government Revenuefrom Gas Sales (2008-28). and Export ...........................................................2 Domestic Figure 1.2: ExpectedState Revenuefrom Gas and Oil (2008-28) ....................................9 Figure 1.3: ExpectedState Revenuefrom Gas and Oil (2008-28) ....................................9 Figure 1.4: ExpectedState Revenuefrom Gas and Oil (2008-28) ..................................10 Figure3.1: Estimateof Gas Consumption (in Tcf) 2007-25 ........................................28 Figure 3.2: Proposed Pipeline Routing and Gas-fired Power Plants ................................36 Figure3.3: The Current Gas Industry Structure ...........................................................40 Figure3.4: A Future Gas Market Structure for Yemen ..................................................44 Figure3.5: Options for Accessing the National Gas Pipeline ........................................48 FigureA5.1: Government Take and Project's IRR at Different C/R Levels. Oil .................137 FigureA5.2: Government Take and Project's IRR at Different Price Levels. Oil ...............139 REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK FigureA5.3: Government Take and Project's IRR at Different C/R Levels. Gas ...............................................................142 Associated FigureA5.4: Government Take and Project's IRR at Different Price Levels. Associated Gas ..................................................................... 144 FigureA5.5: Government Take and Project's IRR at Different C/R Levels . NonassociatedGas.........................................................147 FigureA5.6: Government Take and Project's IRR at Different Price Levels. Nonassociated Gas ...............................................................149 FigureA6.1 : Payoff for Selling a Futures Contract............................................................153 Figure A6.2. Selling Futures Four Month Ahead .............................................................. 154 FigureA6.3. Payoff for Buying a Put Option ....................................................................155 FigureA6.4. Payoff for Buying a Zero-cost Collar ............................................................ 155 Figure A6.5. Buying Out-of-the-money Options Two MonthsAhead ................................. 156 FigureA6.6. Payofffor Selling a Swap ............................................................................157 FigureA6.7. Setting the Pricewith a Fixed-for-floating ..................................................... 157 Boxes Box 2.1 : Methods for Calculating Marginal Costs at the Well Head ...............................14 Box 2.2: Methodsfor Calculating Marginal Costs for Pipeline Network ..........................16 Box 4.1 : Key Features of Concessionary and Contractual Systems.................................63 Box4.2: Key Featuresof Effective Fiscal Regimes ..........................................................68 Box 5.1 : Price Structure in the Main LNG Markets ......................................................104 Box 5.2: Key Elements of the Main Derivatives Contracts.............................................106 BoxA3.1: Royalties..................................................................................................... 121 BoxA3.2: Taxes on Income: Ring.fencing. Corporate IncomeTax. Resource RentTax...................................................................................123 BoxA3.3: Import and Export Duties. Value Added Tax. Surface Fees. Bonuses................125 BoxA3.4. Government Participation ............................................................................126 BoxA3.5. Cost Recovery Limit .....................................................................................127 Box A3.6. ProfitOil Split .............................................................................................128 BoxA3.7: Foreign Exchange Controls, EnvironmentalTaxes and Bonds. Other Performance Bonds and Local Content Obligations ......................... 129 Acknowledgments This reportwas written byMr. FranzGerner, Task thank Mr. Hossein Razavi and Mr. John E. Team Leader (Natural Gas Pricing and Besant-Jones,peer reviewers, for their guidance. Framework for Developing the Domestic Gas Mr. Jonathan Walters, Mr. Eric Groom, Market) and Ms. Silvana Tordo (Legal and Fiscal Mr. Somin Mukherji, Ms. Silvia Pariente-David, Terms for Exploration and Production of Mr. PierreAudinet, Ms. Masami Kojima, Mr. Raul Hydrocarbons,andEncouragingthe Development Garcia, Mr. Nirmaljit Singh Paul and Mr. Ivan of Gas Reserves). Zelenko have provided valuable input. The macroeconomic outlook was prepared by The report was jointly financed by the Energy the team based on information provided by Sector Management Assistance Program Mr. SrinivasanThirumalaiand Mr. Thilakarantna (ESMAP) and through allocations from the Ranaweera. The authors would like to World Bank budget. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVEFRAMEWORK ConversionTable 1 Cubic Meter (m3)of natural gas 35.31 Cubic Feet (6) 0.036 Million British Thermal Units (MMBTU) 10.54 Kilo Watt (s) Per Hour (kwh) 0.0066 Barrels (bbls)of crude oil 1 cf of natural gas 0.00019 Barrels of Oil Equivalent(BOE) 1 Barrel (bbl)of Heavy Fuel Oil (HFO) 5.7 MMBTU of natural gas (based on 40 Mega Joule [MillKilogram [kg] of HFO) 117 Liters (I)of HFO 1 MMBTU of natural gas 1,000,000 British Thermal Units (BTUs) 293 (kwh)of electricity 0.183 bbl(s)of crude oil 1 Mega Watt (s) (MW) 0.001 Giga Watt (s) (GW) 1.6 Million Cubic Meter (Mm3) 57,600 MMBTU 1ton of HFO 7.4 bbls of HFO 1,059 1 of HFO CurrencyConversion (Effective April 2007) Currency Unit -Yemeni Rial US$l =YER 195.85 FiscalYear March 21-March 20 Units of Measure bbl(s) Barrel(s) Bcf BillionCubic Feet Bcm Billion Cubic Meter BOE Barrelof Oil Equivalent BTUs British Thermal Units d Cubic Meter GW Giga Watt (s) GWh Giga Watt (s) Per Hour kg Kilogram km2 Square Kilometer kW Kilo Watt (s) kwh KiloWatt (s) Per Hour I Liters m3 Cubic Meter Mbbl Million Barrels Mm3 Million Cubic Meter MJ Mega Joule MMBTU Million British Thermal Units MMCF Million Cubic Feet Mt MillionTons MTPA Million Tons PerAnnum MW Mega Watt (s) Td Trillion Cubic Feet Acronyms and Abbreviations ACCC Australian Consumer and Competition Commission AG Associated Gas AlPN American Institute of Petroleum Negotiators ARC Aden Refinery Company AYCC Arabia-Yemeni Cement Company BLO Build, Lease and Own BLT Build-Lease-Transfer BOT Build-Operate-Transfer BOO Build-Operate-Own BOOT Build, Own, Operate, Transfer BT Build-Transfer BTO Build-Transfer-Operate CCGT Combined Cycle Gas Turbine CNG Compressed Natural Gas CPI Commodity Price Index CPlA Country Policy and Institutional Assessment CSF Contingent Stabilization Fund EIA Energy Information Administration ElTl Extractive Industry Transparency Initiative E&P Explorationand Production ESMAP Energy Sector Management Assistance Program EU European Union FERC Federal EnergyRegulatoryAgency FID Final Investment Decision fob Free on Board FPlA Filipino Participation IncentiveAllowance REPUBLIC OF YEMEN: ANATURALGAS INCENTIVE FRAMEWORK FSA Feedgas Supply Agreement FTP Floor Transfer Price GDA Gas DevelopmentAgreement GDP Gross Domestic Product G&G Geophysical and Geological GIP Gas-In-Place GllGNL Groupe lnternational des lmportateurs de Gaz Liquefik GOY Government of Yemen GPA Gas ProjectAgreement GSA Gas Sales Agreement GST General SalesTax GTC Gas Transport Contract HFO Heavy FuelOil HH Henry Hub HSFO HeavySulfur Fuel Oil IEA lnternational Energy Agency IMF lnternational Monetary Fund IPP Independent Power Producer IRR Internal Rate of Return JCC Japan Crude Cocktail JV Joint Venture Kogas Korean Gas Corporation LFO Light FuelOil LPG Liquefied PetroleumGas LRAlC Long-Run Average lncremental Cost LRlC Long-Run lncremental Cost LRMC Long-Run Marginal Cost LRMCC Long-Run Marginal Capacity Cost LNG Liquefied Natural Gas LSFO LightSulfur Fuel Oil MENA Middle East and North Africa MFN Most Favoured Nation MIC Marginal Incremental Cost MOE Ministry of Electricity ACRONYMSAND ABBREVIATIONS MOM Ministryof Oil and Minerals MoU Memorandum of Understanding MRC Marib Refinery Company NAG NonAssociated Gas NCC National Cement Company NELP-V New Exploration Licensing Policy RoundV NGP National Gas Pipeline NTPA Negotiated Third Party Access NPV Net Present Value OCGT Open Cycle Gas Turbine O&M Operation and Maintenance OPEC Organization of the Petroleum Exporting Countries OTC Over The Counter PEC Public ElectricityCooperation PEPA Petroleum Explorationand ProductionAuthority PPI Private Participation in Infrastructure PPlAF Public-Private InfrastructureAdvisory Facility PR ProfitabilityRatio PSA Production Sharing Agreement or Petroleum Sharing Agreement WE ratio Ratio Between Revenue and Expenses RTPA RegulatedThird PartyAccess SI Saving Index SOEs State-Owned Enterprises T&D Transmission and Distribution TPA Third Party Access TPES Total Primary Energy Supply U.K. United Kingdom U.S. United States VAT Value Added Tax WACOG Weighted Average Cost of Gas WTP Willingness-To-Pay YC Yemen Company YGASSP Yemen General Authority for Social Security and Pensions YGC Yemen Gas Company REPUBLICOF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK YLNG Yemen Liquefied Natural Gas YOC Yemen Oil Company YOGC Yemen Oil and Gas Company YPC Yemen Petroleum Company YtF Yet-to-findFields xvi ExecutiveSummary A Macroeconomic Perspective and economy, including introducing the General the Role of Natural Gas SalesTax (GST),abolishing petroleumsubsidies and promoting the agriculture, industrial and Fiscal accounts and balance of payments of services sectors. Evenif successfulfiscal reforms the Republic of Yemen (referred to as Yemen are implemented, additional sources of hereafter)depend upon oil revenues. Currently, government revenue would need to be sought nearly 75 percent of central government fiscal to avoid having to implement sharp fiscal revenuesand 90 percentof export receiptscome adjustments at a later stage. from the oil sector. Production levels have been falling as the majority of currently producing Yemen is planningto export gas through Yemen fields move toward the end of their economic Liquefied Natural Gas (YLNG) starting from life cycle. Recent discoveries and technological 2009. Yemen is also aiming to develop the advances have only partially offset this decline. domestic gas market, in particular gas-to-power. Liquefied Natural Gas (LNG) export revenue For purely macroeconomic planning and fiscal and domesticgas sales are expectedto partially purposes, a prudent approach ignores revenue offset the decline in crude oil revenue from from "possible" future hydrocarbon reserves currentlyproducingfields. Thefiscal revenueflow until such time as such reserves are proven. that is currently expectedto be generated bythe Thisisbecausethe aim of fiscal policyisto ensure hydrocarbon sector over the next 20 years is in fiscal sustainability, which requires that the Figure 1. (A more detailed explanation of the government's expenditure plans are tailored to different lines in the Figure is provided in matchthe levelof revenuethat can beanticipated Chapter 1.) with a reasonable degree of certainty. Realizingthese potentialfiscal revenueswill require Based on the current level of expenditure and developing domestic gas pipeline infrastructure knownrevenueflows, Yemen is likelyto become to provide access to the power sector (and moderately stressed with regard to the potentialother customer groups)to this relatively sustainability of its external debt, unless the cheap and clean source of energy. GOY has Government of Yemen (GOY) designs and earmarked 5.2 Trillion Cubic Feet (Tcf)of proven implements policies aimed at fostering growth gas reservesfor the developmentof the domestic and controlling public expenditure levels. market and there may be more gas yet-to-find. Although the fiscal impact of domestic gas sales Severalareas of the Yemeni economyhave been is relativelysmall, the major benefitof developing identified as potential sources of government the domestic gas market is to provide access to revenue and growth for the nonhydrocarbon the powersector (andpotentiallythe industrialand REPUBLICOF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Figure 1: Expected State Revenue from Gas and Oil Sales (2008-28) Years -Crude Oil Revenue (based on 2004 PEPA data) - - - -Gas Gas Revenue (Government Take - Feedgas to Whole Power Sector) -Gas Revenue (Government Take - LNG) Revenue (State Take - LNG) ,TotalCrudeOilandGasRevenue(StateTake-LNGandFeedgasSales) , Source: Authors' calculations. other sectors) to a relatively cheap and clean power generation demand. If the company sourceofenergythatwillcreatelowerenergyprices switches to natural gas, it will pay between and efficiencygains to the economy as a whole. US$4.2 billion and US$10.5 billion to meet future generation demand andthiswould create Figure 1 shows that current exports of gas substantial savings on generation costs that through YLNG and domestic gas sales to the shouldhave rnaior positive impactson lowerend power sectorwill not offsetthe expecteddecline user tariffs and the effectiveness and in oil production and associatedfiscal revenue. competitivenessof the Yemeni economy. The nonhydrocarbon growth potential is limited and the most likely potential for additional It is imperative that GOYimplements measures sources of revenue in the medium term is the to further encourage oil and gas Exploration& hydrocarbon sector. Production (E&P)activities, and to develop the utilization of natural gas. Incentivesto explore However, there are direct efficiency gains from and produce oil have been reasonably switching the power sector to natural gas arising appropriate for some years now, but few from lower fuel costs for power generation that major discoveries are still be made. By lead to lower generation costs per Kilo Watt (s) contrast, incentives to explore and produce Per Hour (kwh) and eventually could result in gas have been inadequate and enhancement cheaper electricity for final customers. Public of the incentive framework could perhaps Electricity Cooperation (PEC), the power utility, lead to major discoveries of natural gas. This will spend between US$8.6 billion and US$27.8 requires the development of policies and billion (depending on future oil prices) for institutions tailored to gas, beyond those purchasing Heavy FuelOil (HFO)to meetfuture appropriate for oil. EXECUTIVE SUMMARY Itis alsoworth notingthat LNGenjoyssignificant additional limited gas reserves to export is only economies of scale for technological reasons, advisable once domestic use is fully assured. so, if new associated or nonassociated gas The Investors' Perception of Risk in discoveriesare made, their productionfor export Developing the Domestic could be quite competitive, even if the domestic Gas Market market could not fully absorb additional production at that time. Inprinciple, a governmentwould preferthat gas The Economic Cost of Domestic Gas be used domesticallywhen the economic return on investment is higher for domestic use than On the basis of currently available data, the for export. The private sector would prefer to economic and financial rate of return of using develop and supply the domestic market when the gas domestically for power generation are the financial return on investment is higher for higher than the rate of return generated by domestic use than for export. To date, the only exporting it. It follows that increasing the level sizable privatesector investmentinthe gas sector of gas exportsfrom existing gas reserveswould in Yemen has been the YLNG export project. In be advisable only if enough gas was available other words, the private sector appears to be to satisfydomestic demand. This istrue intheory. unwilling to invest in the development of gas In practice, several elements would need to be infrastructurefor the domestic market.This may taken into consideration bypolicymakersbefore be due to the fact that the private sector's a decisionis madeon alternative usesfor existing perceptionof politicalandregulatoryrisksinYemen gas reserves. ishigh. Hence, the "risk-adiustedMfinancialreturn on investment may turn out to be much lower Yemen has limited provennatural gas resources than the financial return unadiustedfor risk. and the economic value of the existing gas reserves is the opportunity cost of selling it in The Yemeni government has two options: (a)to international markets (through YLNG) or the finance the development of the domestic gas netback-to-market value of selling the gas to sectorthrough publicfunding; or (b)to introduce domestic customers-whichever is higher. measuresto mitigatethe regulatoryand political risk to attract private capital. The first option The opportunitycost iscalculatedbynetting back would clearly be undesirablefrom an economic the international gas price to the well head at standpoint since it could lead to the inefficient Marib and was estimated at an average of use of scarce public resources that would US$2.6/Million British Thermal Units (MMBTU) otherwise be destined to priority sectors over a 25-year period. The power sector is the (for example, education, health, sanitation). most likely customer of natural gas in the domestic market, and netback calculations The second option should clearly be preferred. demonstratedthat an existing oil-fired plantthat Addressing the factors that contribute to converts to gas would be willing to pay for decreasethe investors' perception of regulatory natural gas up to US$7.1IMMBTU. This would and political risk would be important to attract suggest that the economic rate of return for foreign investment and management skills, using the remaining proven gas reserves which, in turn, would be indispensable for domestically are higher than the rate of return swiftly developing the domestic gas industry. generated by exporting these gas reserves. This In addition, this policy option would increase would further suggest that allocating any economicefficiency, promoteafastergrowthand, xix REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK at the same time, would not preclude a certain A Suitable Regulatory Regime for level of GoYs' directparticipation. One important the Small Yemeni Gas Market way to addressthe perception of risk is to create an efficient gas market structure and a clear GOY has substantial leeway in designing a legal and regulatoryframework governing it. market and regulatory regime for the NGPthat is capable of attracting private investors. To this The Participation of the end, it is proposedthat separatecommodityand Private Sector in Gas transportationcontracts, Third PartyAccess (TPA) Infrastructure Development rules, firm capacityrightsand an attractivetariff regime be adopted. The development of a domestic gas market would require the construction of a greenfield Given Yemen's limited history and expertise in gas transmission pipeline, the National Gas regulating network businesses, developing a Pipeline (NGP). Although the economic and comprehensivelegal and regulatoryframework financial viability of this pipeline can be clearly (gas law, subregulationsand guidelines)would demonstrated, large investments are required likely be a lengthy process and would risk a for its construction. For this reason, it would be further delay in the construction of the NGF! advisable to invite private sector investment or As time is of the essence, it would be advisable to form a public-private partnership. to adopt a "regulation by contract" approach. Timing is a keyfactor and the earlier the NGPis An InstitutionalSet-up for Regulating built, the higher the net economic benefits to the Downstream Gas Sector theYemenieconomy. Consequently, a regulatory regime and gas market structure would need In line with the size of its domestic gas market, to be put in placewhich are practical, attractive Yemen haslimitedinstitutionalcapacity.Therefore, to privateinvestors, consistentwith international although the independent regulator model is a best practice and suitable to the small size of widely accepted best practicemodelof economic the Yemeni gas market. regulation in more advanced economies and larger and mature gas markets, it may not be To expedite the development of the gas sector, suitable to apply it in Yemen. A more practical GOYshould allow for private participation in all approach may be to entrust an existing parts of the gas chain. It is recommended that governmentagency(ies)to ensurethe supervision no cross-ownership restrictions apply and and monitoring of the sector, and the control of market participantsbe allowed to participate in compliancewiththe relevantcontracts. Credibility all parts of the gas chain, including gas of the regulatory regime could be enhanced if production, transmission, distribution, shipping, some or all of the monitoring functions would be supply and consumption. In practice, this would carried out by, for example, internationalauditors mean that the owner and operator of the NGP on an annual or biannual basis. However, some could well be a gas producer, buyer, seller, consideration should be given to a joint gas transporter and/or customer. To ensure and electricity regulatory agency, and it is transparency, to enableregulatoryoversightand recommendedthat the most suitable agency will monitoring, to protect end users and to prevent be identified as part of developing the detailed anti-competitive behavior, companies which regulatoryregime. engage in several areas of the gas chain would be required to unbundle and prepare separate Theseflexibleownership, market and regulatory accounts for each business activity. arrangements would likely reduce the political EXECUTIVE SUMMARY and regulatory risks and increasethe incentives relativelylow chanceof finding largeoil and gas for private investorsto participate in the market fields, and a relatively high chance that and to develop the NGP development cost could be higher than the regional average. This does not necessarily The Timing of Investment and the mean that gas reserves would not be found in Importance of Close Cooperation Yemen, or that it would not be economically and Coordination between the viable to develop them. On the other hand, it Power and Gas Sectors does suggest that measures may need to be taken by GOY to encourage investment in Inthe gas industry, the developerof the reservoir gas E&P andthe end userof the gas are linked bya chain that connects the processing plant, the The geologic potential is only one of the transmission network and the distribution elements that determine the attractiveness of a network. Eachlink correspondsto a commercial country: well head prices, development costs, relationship, and is dependent on every other political risk andthe fiscal regimeare alsotaken link. Because the chain is vulnerable to into consideration by investors in evaluating disruptions, firm and long-term relationshipsare potential investment opportunities. A host the norm ("take-or-pay") and/or "ship-or-pay" government can affect most of these elements clauses are generally used). through its policies and actions. Ingeneral terms, countrieswith favorable geologic potential, high An anchor proiect or sector is normally needed well head prices, low developmentcosts and low to underwrite the development of the domestic politicalriskwill tend to offer tougher fiscal terms gas market. In the case of Yemen, the power than countries with less favorable geologic sector would be the major anchor customer. potential, lowwell headprices, highdevelopment Other larger industries, such as the cement costs and high political risk. sector which is growing rapidly, could also act as anchor customers. Because each link in the No ideal or model regime is available for policy chain depends on every other link, it is unlikely makersto adopt. Eachcountry's circumstances, that investment will be made in transportation, needs and objectives define the key f.eature of processing, andfurther upthe chain ifthe power an appropriate sector policy for hydrocarbon sector is not ready to receive the gas, or is development. Decisions on the design of the unwilling to convert to gas. On the other hand, appropriate policy can be supported by an before making such a commitment and understanding of how its various elements converting its appliances to gas, a power sector and instruments influence decision making operator would need to be sure that the NGP and outcomes. will be built and that the gas and transportation tariffs will be attractive. To mitigate the risk, Barriers to Gas Exploration and long-term gas supply and gas transportation Development and Possible Options agreements are normally used. to Address them GeologicalPotentialand Sector Policy Inorder to design an appropriate policyfor gas explorationand development, GOYwould need Limited data are available on the potential size to identify the barriers to investment and to of probableand possiblereservesinYemen, and devise appropriate measuresto overcomesuch onthe likelyexploration and developmentcosts. barriers. Some of these barriers may beshort in The available data would seem to indicate a nature, and/or can be addressedvia initiatives REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK that have a short-term or temporary focus. variety of potential project conditions. Key Others may requireregulatoryinterventionsand operational principleswould needto be laid carry long-term effects. Addressing these out, including procedures for obtaining the barriers would decrease the perception of risk necessary permits and licenses, evaluation and/or reduce the finding and lifting costs. In of discoveries and commerciality, other words, addressing these barriers would preparation, submission and approval of lower the exploration and development development plans, domestic market threshold for investment, that is, the minimum obligations and pricing principles. size of reservesthatwould be necessaryto justify Contractorsshould begiventhe rightto build an investment. and operate high-pressurepipelines, directly or in association with third parties, to A number of potential barriers to investment transport their gas. The principles for TPA were identified in this paper, and possible would be laid out in regulations or in the measures were suggested to overcome them. relevant contract. Service contracts and/or Thesewere divided into three categories: amendments to existing PSA could be consideredin respecttothe developmentand Measures which are needed to enable gas production of known gas reserves; exploration. Yemen does not have a hydrocarbon law. Contractual agreements Measures in which economicimpact cannot in the form of Production Sharing bepracticallyquantified.Thesewould include Agreements (PSAs) are used to regulate administrativemeasuresaimed at promoting exploration, development and production the attractivenessofYemen's E&Pto investors, activities. However, existing PSAs and the and improving the efficiency of petroleum 2006Model PSAdo notgrantthe contractor operations. In particular, the following were the right to explore for and produce gas, considered: improving the quality and whether associated or nonassociated with quantityof geotechnicaldata, facilitatingand oil. Should gas be discovered, GOYand the coordinating multiparty work programs, contractor would need to negotiate a gas encouraging multifield gas development development agreement or gas project projects, streamlining approval procedures, agreement within a time frame specified in increasingthe expenditurethresholdsunder the PSA. While the requirementto enter into the PSA, and developing the domestic gas negotiations every time gas is found in market. The clarity, simplicityand stability of potentially economic quantities may be the legal and fiscal regime are also key justified bythe government's needto ensure elementsto attracting investors; and that fiscal and nonfiscal obiectives are adequately taken into consideration, the Measureswhich impactcanbeestimated. The prospectof potentiallylong negotiationsand fiscal regime could be used to convert the uncertaintyof their outcome are likelyto government's policy into economic signals discourage investors. to the market, and influence investment decisions, provided that the framework is One possiblesolutionwould beto grant gas clear, is not changed retroactivelyand does E&P rights to contractors under the relevant not discriminate between the actors. PSA, and to provide for flexible, progressive Several countries have used favorable fiscal terms so as to minimize distortions to taxation of gas to support the development investment decisions, and to adapt to the of the gas sector in addition to relevant EXECUTIVESUMMARY sector reforms. Fiscalterms for gas in any Revenue Volatility and Risk given country very much depend on the Mitigation Strategies distance to market and/or on the ability of the domestic market to absorb the Countries that derive a considerable portion of volumes that are being produced. For their revenue from exploiting nonrenewable projects that are closed to large markets resources such as hydrocarbons, typically face the fiscal terms for gas are rather similar two problems: the revenue stream is uncertain to those applicable to oil. When gas andvolatile; and it does not lastforever. Volatile markets are distant, the government and uncertainfiscal revenue makesit difficult to take is normally lower for gas than for oil. plan expenditure and to efficiently use public This is done either by simply defining a resources. Inorder to ensurefiscal sustainability lower government take for gas, or by when revenue falls sharply and unexpectedly, using self-adjusting profit oil share, taxes governments often respond with expenditure and royalties. cuts. This can be expensive, inefficient and politically unpopular. In addition, it is not easy Because of the high risk and considerable to distinguish, ex ante, a permanent priceshock investmentinvolved in gas exploration and from a transient one: oil and gas prices have development, the fiscal system would need been knownto be mean-reverting, butthe mean to take into account the divergent interests they revertto may not be the same over time. If of investors and the government. In the price increases substantially, a government particular, the fiscal system would need to may be under pressureto increaseitsspending, be able to allocate risks equitably. As risks but it may be difficult to do it efficiently. can be substantially different for different projects and, over time, it would be Oil and natural gas are among the most price desirable to build enough flexibility into a volatile commodities. Gas price volatility has system to allow for unforeseen changes, traditionally been addressedthrough the use of and to minimize the need and cost of long-term contracts. Although for LNG negotiations and/or renegotiations. exporters, Yemen's long-term LNG contracts Furthermore, the probability of success, are still the norm, the recent development of the expected average size of future a short-term LNG market, and the increased discoveries and the average finding and flexibility in price-setting formulae and lifting costs are key data for the design of contract terms of the most recent LNG an appropriate fiscal system, that is, a contracts, may warrant a more sophisticated fiscal system that is suited to the particular approach to risk management. country circumstances. Especially in frontier areas where little is known on To insulate its fiscal revenue from price prospectivity and cost of development, the volatility, a producing country can adopt use of fiscal systems based on profitability different strategies or, better, a podfolio of risk indices would be suggested as they are management strategies: more likelyto capturethe variability among projects. Because of their flexibility, these Establish a Contingent Stabilization Fund types of arrangement are more likely to (CSF). A CSF could be structured to encourage the development of marginal specifically deal with price volatility, that is, fields, and of complex projects with a long the fund would accumulate during periods lead time for implementation. of high commodity prices. The resources so REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK accumulatedwould be usedto offset revenue renegotiation of the price floor and ceiling fluctuation in periods of low commodity are usually provided for in this type of prices. In order to provide a meaningful agreements; to (b) enter into derivative insurance against price volatility, the CSF contracts. Futures and options markets would need to be able to accumulate provide the seller (buyer)the ability to either sufficientliquidity. Countries' experiencewith put a floor (ceiling) on prices or buy an CSFs has been mixed. In general terms, a insurance against falling (rising) prices. CSF can contribute to insulate government Derivatives may be traded in exchanges or expenditure from price shocks. However, its Over the Counter (OTC). Although they effectiveness depends on the government's mitigate price volatility, these instruments overallfiscal discipline; present different degrees of risk and complexities, and entail a certain level of Borrowabroadto weather temporaryshocks implementation costs. or to adjust to permanent price shocks. In practice, the government may not haveeasy Expertise is required to understand the risk access to foreign capital markets on structure, identify appropriate risk management reasonable terms, especially in a period of instruments and to implement and supervise low commodity prices. In addition, repaying a risk management program. The design and the debt when the situation reverses may implementation of a risk managementprogram proveto be difficult; maybesubcontracted, but GOYwould still need to developsufficient internal capacityto monitor Setfiscalpricesfor thepurposeofcalculating the program, and communicate its resultsto the royalties, production sharing and corporate relevant stakeholders. taxes. The fiscal price could be defined as a The financial, legal and institutionalimplications fixed value over a certain period of time, or of setting up a risk management program vary it could be indexed to an international according to the type of instrument used. Commodity Price Index (CPI)or a portfolio Commodity hedging programs may requirethe of indices. Although the use of fiscal prices passing of legislation to authorizethe program may reduce the volatility in fiscal revenue, and establish the boundary conditions for its it is likely to have a distortive effect on implementation. Stabilizationfunds also require investment decisions; and specific legislationto regulatethe obiectives, the rulesfor accumulationinto andwithdrawal from Transfer the risk of price shocks to those the fund and its governance structure. betterableto bear it. There are variousways of doing this: (a) if the State is a party to a No risk management program is without risk. gas sales and purchase agreement, floors The objective of the program, its governance, and ceilings could be established in the andthe principlesto be usedto defineitssuccess, pricing mechanism. These provisions are would needto be clearly specified at the outset, designed to provide a minimum sales price and communicated to the Parliament and the to the seller. In exchange for this protection, civil society. The political implications of the buyer is ensured a maximum purchase implementing and managing the outcome of price. Alternatively, a less risk adverse seller these programs should not be underestimated. may prefer to negotiate a lower floor, and maintain the possibility to benefit from a Before implementing a particular risk rise in price. Indexation and periodic management program, it isgood practiceto set up a virtual program. This would allow GOYto considerable investmentinvolved in developing explore different risk management instruments a gas sector, attracting foreign capital and and strategiesfor a suitablylong period of time, expertise will be essential. To this end, in withthe obiectiveto determinetheir effectiveness, addressing the public interest and developing the relativecosts and ease of implementation. the preferred policies, GOYshould ensure that decisions on project development and Conclusions technologies will be based on their economic The development of a gas sector has the merits, and gas will be allowed to find its highest potential to substantially contribute to value market. Without this assurance, investors Yemen's economic growth and fiscal revenue will have lessconfidence, and gas reservesmay generation. Because of the high risk and remain undeveloped longer than necessary. .---- WtCPOSED NAllOEUUOASPIPEtINES .---- Y E M E P ~ ~ ~ ~ K ~ P ~ P E U N E ~ C M T ~ Z U AL jAWk SITES FOR NlIW POWERG E N E R A W POWERSTATION UMKR CONSTXUCIkX4 EXtSTlm THEM& POWER STATKW - OIL TERElUNALS O K PIPELINES C@@% OIL &GASFIELDS @ E B R I N S CEMEM W M S 0 UFIocRCONURVCTION C E M M PlANlS .--e%" m 5 --- -*-- w-bLMwnEs W m B 1 A T I O N A t m E S 0 TOWWSANIWIIPE*S 0 BOMRNORARcmm 1. Macroeconomic Outlook for Yemen Macroeconomic Environment However, as noted in 2006 in the Development Policy Reviewfor Yemen byWorld Bank2and the Yemen's fiscal accounts and balance of ArticleIVreportof the InternationalMonetaryFund payments depend upon oil revenues.' Nearly (IMF3),negativeshocks could easily push Yemen 75 percentof central governmentfiscal revenues over the external debt sustainability thresholds. and 90 percent of export receipts depend on Examplesof such negativeshocksarea 20percent the oil sector. In the absence of major new oil permanent drop in oil prices or nominal discoveriesor major technologicaladvance, the depreciation of 30 percent. long-term outlook lookschallenging, as mature To ensure the long-term sustainability of its fields head toward the end of their economic external debt, measuresshould be devised and life cycle. implementedto foster economic growth, and to Yemen's current external debt levels are limitthe expansion of publicexpenditure.To this moderate. Mostly concessional, external debt end, the long-termobjectiveshould beto obtain: (i)a positivenonoil balance; (ii)a manageable amounted to US$5 billion at the end of 2005, level of debt; and (iii) a level and composition about 23.3 percent of the Gross Domestic of public expenditure that favors growth and Product(GDP)in Net PresentValue (NPV)terms povertyreduction.The government's expenditure with a debt-service to export ratio of 3 percent. plan should be tailored to match the level of Underthe most likelyscenario, Yemen's external revenue that can be anticipated with a debt ratios do not breach thresholds of reasonable degree of certainty. sustainabilityfor a moderate Country Policyand Institutional Assessment (CPIA) performer like Based on current knowledge, Yemen's oil Yemen. The relevantthresholds are NPVof debt reserves are likely to be insufficientto cover the to GDP ratio of 40 percent and debt-serviceto enormous need for pro-poor and development export ratio of 20 percent. s pen ding.^ However, Yemen is developing the In March 2007, Yemenjoined the ExtractiveIndustriesTransparencyInitiative (EITI).The ElTl is an international organization with a small secretariat located in Oslo, Norway. Involving governments,industry and civil society, ElTl aims to increasetransparency in financial transactions between companies and their host governments. Transparencypermits more accountability which, in turn, is expected to improve the prospects for growth and poverty reduction in countries where extractive industries,such as oil and gas, dominate. Yemen is now in the process of completing the initial sign-up steps to ensure compliance with the EITI process. More background information on EITI can be found on www.eitransparency.org. Development Policy Review, Yemen, The World Bank, 2006. Article IV, International Monetary Fund (IMF), 2006. The latest official information provided on oil production forecasts by Government of Yemen (GOY)is from November 2004. However, Petroleum Exploration and Production Authority (PEPA) indicated to the authors that, on the basis of more updated information, the production levels are expectedto increaseover the medium term due to improvements to the production facilities in producing fields and new discoveries. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK gas sector and is planningto export gasthrough from the current 38 percent of GDP to about Yemen Liquefied Natural Gas (YLNG) starting 30 percent by 2025. Half of this adjustment is from 2009. Yemen is also aiming to develop expected to come from the removal of oil the domestic gas market, in particular subsidies, which are targeted to be completely gas-to-power. Developing the gas sector is eliminated by 2007. The other significant imperative for fiscal sustainability(Figure 1.I). expendituresavingsare anticipatedto comefrom reforms of the civil service. No savings are The expectedrevenuesfrom LiquefiedNational expected incapitalexpenditure,which isprojected Gas (LNG) exports and domestic market gas to remainat around 7.5 percent of the GDP would only partially offset lossesfrom declining oil production, therefore fiscal adjustment is PotentialSources of EconomicGrowth neededfor sustainability. Nonoil Sector In 2002, the IMF estimated that in Yemen, a SeveralareasoftheYemenieconomyhave been target level of nonoil primary deficit should be identified as potential sources of growth for around 2.4 percent of the GDF?Revaluing in the nonhydrocarbon economy: agriculture 2005 prices and allowing for projected gas (particularly honey), fishing, building stones, export revenues, a reasonable level of leather products and tourism. However, even nonhydrocarbon primary deficit would be substantial increases in exports of these sectors approximately 5 percentof the GDF?The actual do not have the same potential to contribute to nonhydrocarbon primary deficit has, to date, GDP growth and fiscal revenue as the exceededthis optimal rate. hydrocarbon sector does. To achieve this objective, savings on the expendituresidewould needto beimplemented. Nonhydrocarbonrevenueisexpectedto increase Itshould be possibleto reducethecurrent levelof from about 12 percent of the GDP in 2007 to expenditurebyapproximately0.5 percentof GDP about 20 percent by 2025.5Mostof this growth per year. This will allow expenditurelevels to fall would COmefrom the successful introduction of Figure1.l :ProjectedGovernmentRevenuefrom GasSales(2008-28) Domesticand Export - Dividend ----------- Dividend p"'-""-""--' Governmentof Yemen 1 I (GOY) I I I I I A I GovernmentTc~ke* I 1 USS10.8billion I Dividend Yemen Oil ond Gas Company I Dividend Lwer CrudeOil Allomtion Dividend USS4.2 billionlo USS540million USS2.4 RefinelyCompany (ARC& MRC) PublicElectricity Cooparatian Yemen Gar Compony (YGCI Note: LNG Government Jake includes royalty, bonuses, fixed tax, profit share. *' Domestic Government Jake includes feed gas sales to PEC. This assumes a relatively narrow definition of fiscal revenue, excluding some of the elements shown in Figure 1 . 7 . 2 MACROECONOMIC OUTLOOK FOR YEMEN the General Sales Tax (GST)which is expected Marib I and the 400 MW Marib II. It is to increase the overall level of tax revenue by understoodthat a gas price between US$0.60- 1-3 percent of the GDP over the nextfew years. 0.80/Million British Thermal Units (MMBTU) is being negotiatedfor these plants. Tothisend, Yemenwould needtofurther intensify itsefforts to developthe still-emergingindustrial For all future gas sales, the opportunity costs of and service sectors. It is expected that a exportingthe gas through YLNG was assumed temporary boost to the GDP growth will be felt to represent the "economic" cost of domestic in the construction phase of the YLNG and the gas. The opportunity cost of the current proven Marib power plant in the period up to 2009.6 gas reserves is estimated at US$2.6/MMBTU in Some spillover effects of these projects will be real terms (Table 2.2).8 It was further assumed seen in the construction and services sectors. thatall currentandfuture plantsuse Open Cycle Inaddition, the constructionand services sectors Gas Turbine (OCGT) technology which is would benefitfromthe realizationof the National currently proposed under the least-cost power Gas Pipeline (NGP) and the installation of new expansion plan prepared by PEC.9 generation capacity. GOYis currentlysubsidizing sales of petroleum RevenueGenerated by Switching to products in the domestic market, including Natural Gas inthe Power Sector Heavy Fuel Oil (HFO) which is mainly used by Once the domestic gas market has been the power sector. By switching to natural gas, developed, the government can expect a fiscal the government could reduce the allocation of revenue stream from selling its existing gas its profit oil to the refineries and earmark that reserves from Block 18 at Marib to the crude oil for additional exports. The difference power sector. between the revenue from selling the freed-up crude oil in international markets and the Annex 1, Table A l . l sets out the calculations relatively lower revenue it generates by for the government revenue from gas sales to subsidizing the domestic refineries (and end Public Electricity Cooperation (PEC). It is users) are additional fiscal revenue to the estimated that, from 2008 to 2028, the government.1° Once petroleum subsidies are government would receive approximately abolished, there is no additional fiscal revenue US$4.2 billion for sales to PEC of associated to the government from switching the power gas coming from the Marib field.7It is expected sector to natural gas, except the revenue that 2.5 Giga Watt (s)(GW)of newor converted generated through the feed gas sales from the gas-firedgenerationcapacitywould be installed Marib Block 18. over the next 20 years. The Government of Yemen (GOY)is currently in negotiations with Despitefiscal revenue from domestic gas sales PECfor gas salestothe 360 Mega Watt (s)(MW) being relativelysmall, there are major benefits The total investment in the YLNGproject is estimated at US$4 billion and the total investment in the 360 MW Marib power plant and associated eledricity infrastructure is estimated at US$500 million. 'The natural gas at Marib belongs to the government. The operator of the field is Safer, a Stote-owned company. Using the opportunity costs at US$2.6/MMBTU is a conservative approach to calculoting economic costs of gas. As pointed out, the economic netback of selling the gas to domestic power sector would be much higher at around US$7/MMBTU. Should Combined Cycle Gas Turbine (CCGT) technology be introduced, this would reduce the gas volume uptake for power generation by up to 40 percent due to the higher efficiency of theseplants. As a consequence, government sale of gas would also decreaseaccordingly. loEven if Yemenruns out of crude oil (which is anticipated in 20 78) and becomes a net importer, those fiscal revenuesavings will accrue to the government as long as the petroleum products continue to be subsidized. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK to the economy as a whole by switching the There are also indirect efficiency gains that are power sector (and potentially other sectors and generated by lower energy input costs to the customer groups) to natural gas. Natural gas is Yemeni economy in general. However, a relatively cheap and clean source of energy quantifying these indirect efficiency benefits that will reduce power generation costs and would requirea comprehensivemodeling of the create direct and indirect efficiencygains to the whole economy (inparticular changesin supply Yemeni economy through lower energy costs. and demand for each sector and subsector) which is beyond the scope of this study. Directefficiencygains from switchingthe power Revenue Generated from LNG Export1' sector to natural gas arise from lower fuel costs for power generation that lead to lower InMay2005, the shareholders12of YLNG made generation costs (per Kilo Walt (s) Per Hour the Final Investment Decision (FID) to proceed [kwh])andeventuallyresultin cheaperelectricity with the construction of an LNG plant in Balhaf for final customers. Annex 1, Table Al.l shows and related facilities. Initial capacity of the that the power sector will spend US$4.2 billion two-train plantwould be of 6.75 Million Tons Per in the period 2008-28 to supply all generation Annum (MTPA), with possibility of further load with natural gas. This assumes that the expansion. The total investment is estimated to gas is priced at the opportunity cost of beapproximatelyUS$4billion,13dividedintothree selling the gas through YLNG, namely at phases: a preliminary phase prior to FID; a US$2.6/MMBTU. If one would assume that the constructionphase; and a commercialproduction government charges the economic netback phase. The investmentwill cover the construction price to the domestic power sector at US$7/ of a pipeline from the Marib field to Balhaf, MMBTU, the government would earn US$10.5 processing, liquefaction, storage and loading billion for feed gas sales over the 20-year facilitiesandothersupportfacilities. Inaddition, YLNG forecasting period. agreedto constructand partiallyfinance a spur line from the Maribfield toward Maber. Annex 1, Table A1.2 calculates that in case Yemen continues to use HFO instead of Threesales and purchaseagreementshavebeen natural gas to supply power generators, PEC signed respectively with Suez ED1 (2.5 MTPA), will have to spend between US$8.6 billion and Total Gas and Power (2MTPA)and KoreanGas US$27.8 billion for purchasing HFO, with a Corporation (Kogas)(between 1.6 and 2 MTPA). base case scenario of US$13.3 billion. These Thefirsttwo contractswill supplythe U.S. market, are potentiallyhugefuel costs savingsfor power at a price indexed to the Henry Hub (HH).The generation and should have maior positive third contract will supply the Korean market, at impacts on lower end user tariffs and the a price indexed to the Japan Crude Cocktail economy's effectiveness and competitiveness. (JCC).14 In addition, a floor transfer price l1To be noted that in calculating the fiscal revenue from gas exports for the fiscal sustainability scenarios, all revenue streams accruing to State-owned enterprises (SOEs)s)(thatis, Yemen Gas Company (YGC)and Yemen General Authority for Social Security and Pensions [YGASSPJ) have been excluded. Since such revenue ultimately flow to government as dividends, this approach significantly underestimatesfiscal revenue. l2 Total (39 percent), SK Corporation (9.55 percent), Hyundai Corporation (5.88 percent), Hunt Oil (7 7.22 percent), Kogas (6percent), YemenGas Company (76.73 percent) and YGASSP(5percent). During Phase 7 and Phase2 of the LNGproject, YGC's equity will be carried -74.04 percent by the foreign shareholders and 2.66 percent by the YGASSP. I3Projectfinancing is expected to be arranged to cover up to 60percent of the investment. Progress has been slow in finalizing the terms of the financing, and financial closing which was expected to be reached by mid-2006, has not yet been reoched. l4 The contract price varies between a floor of US$2.08/MMBTU when the JCC is lower than US$75/Barrel (bbl) and US$3.075/MMBTU when the JCC is higher than US$4O/bbl. MACROECONOMICOUTLOOK FOR YEMEN guarantees a minimum pricefor the calculation the form of dividends), could vary between of the government profit share and royalties.15 US$9.6 billion and US$18.1 billion, with a base Deliveriesof LNG are expectedto start in 2009. casescenarioof US$13.9 billion. Annex 1, Table A1.3 to Table A1.5 show the breakdown by A sliding scale royaltythatvaries between 2 and component of government and State revenue 10 percent will apply to all sales of LNG made under different price scenarios.17 by YLNG, while a fixed royalty rate applies to Liquefied Petroleum Gas (LPG) sales. Bonuses Governmentand State Revenues Flows apply at reachingcertain milestones set forth in from Natural Gas the Gas DevelopmentAgreement (GDA). The revenueflows from YLNG are contractually Cost recoverylimitsand investmentadjustments established whereas the forecasted cumulated alsoapply. An upstreamfeewill be paid annually revenueflows inthe domesticmarketwilldepend by YLNG to compensate the investment made on whether the whole power sector will be bythe previousinvestorsinthe Maribfield. Profit switchingto natural gas over the next 20 years; will be shared between YLNG and GOY on a and/or all newlyestablishedgenerationcapacity sliding scale based on a ratio between Revenue will be gas-fired; and/or the government and Expenses (WE ratio). With the exception of continues to subsidize oil products. a fixed tax equal to 3 percent of all investment made during Phase 1and Phase2 of the project, Figure 1.1 outlinesthe cumulative revenueflows corporate taxes and other taxes applicable in to GOYand to the relevant SOEs for the period Yemen will be paid in lieu by GOY. 2008-28 based on existing information and data. It sets out the projected revenues Government revenue from the LNG project is from YLNG based on existing contractual expected to be approximately US$10.9 billion arrangements and highlights the range of over the 20 years of validity of GDA, with the potentialfiscal revenuefrom the domestic power possibility of decreasing to US$7.6 billion or sector. The size of the fiscal revenueto GOYfrom reachingUS$14.6 billion dependingonthe level the power sector will depend on whether the of future gas and oil prices, as well as the level whole sector will be converted to gas and the of capital investmentand operating costs. timing of the phasingout of petroleum products. The State Take,16 which includes both the Between 2008 and 2028, GOY will receive government's share of benefits from the LNG US$10.8 billion in royalty, bonuses, fixedtax and projectandthe StateOwned Enterprises' (SOEsr) profitsharefrom YLNG. TheYemeni government share of benefits(a substantial portion of which is also entitled to dividend payments from the can be expected to flow to government in Yemen Gas Company (YGC) and Yemen If the average sales price is lower than the floor transfer price, the difference between GOY'Sshare of profit and the royalties calculated at floor transfer price and GOY'Sshare of profit and the royalties calculated at actual sales price is advanced to GOYby YLNG. Theadvance is offset against GOY'Sshore of profit and royalties when the actual price is higher than the floor transfer price. Thismechanism allows GOYto smooth its share of benefit over time, thus reducing gas price volatility. l6The "take" measures the sharing of benefits arising from the implementation of an oil and gas projed between the host government and oil companies. The "State Take" is defined as the government's percentage of pretax projed net cash flow adjusted to take into account any form of government participation. This may include royalties, corporate taxes, production-sharing, and so on, and so forth (Chapter5 contains a detailed discussion of the take and off tax and nontax instruments commonly used in the oil and gas industry). l7Estimate of government revenue from the LNG project were made by the authors of this report on the basis of information provided by GOY,and of their own assumptions. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK General Authority for Social Security and allocation of crudeoil to two domesticrefineries, Pensions (YGASSP) which, as shareholders namely Aden Refinery Company (ARC) and of YLNG, receive US$2.4 billion and US$540 Marib Refinery Company (MRC). ARC is the million over the next 20 years respectively.l8 largest refineryinYemen refining about 80,000 barrelsof crudeoil perday (bbl[s]/d).Incontrast, Inaddition, GOYcouldderivefiscal revenuefrom MRC produces about 10,000 b/d supplying PECtsswitching to natural gas. Safer, the State- exclusively the domestic market. ARC supplies owned company that owns and operates Block boththe domestic and international marketsand 18 at Marib, supplies PEC with feed gas and is is a net importer of HF0.19 In 2003, ARC entitled to an operation fee from GOY. exported464,000 tons, imported 833,000 tons The Ministry of Oil and Minerals (MOM), as the and sold 931,000 tons of HFO to Yemen ownerof all gas reserves, iscurrentlynegotiating PetroleumCompany(YPC).20YPC isthe exclusive a GasSalesAgreement (GSA)with PECto supply supplier of HFO (and diesel) to the PEC and the Marib power plant operated by PEC with other industrialand commercialcustomers. GOY feed gas. It is understoodthat PECwill pay GOY is currently subsidizing petroleum products for (via MOM) for both the feed gas and the the domestic market, including HFO. operating costs. Saferwill pay a dividend to the government. It was estimated that over a The power sector in Yemen currently runs on 20-year period, PEC will pay between US$300 HFO. A switch to natural gas would decrease million and US$4.2 billion for feed gas to HFO consumption by 47 billion Liters (I) (or 44 GOY. In the lower case scenario of US$300 Million Tons [Mt])over 20 years. A reduction in million, it is assumed thatthe only plant running HFO consumption of the power sector would on natural gas is the 360 MWMarib I (the GSA subsequently reduce HFO production and/or has been currentlyfinalized). imports of ARC and MRC and reducethe crude oil allocation requirement by YOGC. This GOYcould increase its Government Jake from reduction in domestic crude oil allocation and/ feed gas sales to the power sector to US$4.2 or reducedproductsimportswould accruefiscal billion if all current and new power plants are revenue to the government as long as energy running on natural gas and the gas is priced at products are subsidized. Once HFO (and other an opportunity cost of US$2.6/MMBTU. In case petroleum products) subsidies are phased out, the government decides to set gas to power the fiscal revenue of the government remains pricesbasedon the economic netbackto power the same, irrespectiveof whether profit oil issold generation at US$7/MMBTUt it could increase domestically or in international markets. fiscal revenuesto US$10.5 billionfrom 2008-28. The estimated level of Government Take, which Yemen Oil and Gas Company (YOGC) is comprises revenue flows that accrue directly to responsiblefor managing GOYshare of crude GOY, and State Jake, which includes the oil production, including exporting the Government Take revenue flows that accrue to proportion of the government entitlement (that SOEs, is summarized in Table 1.I. Potential is, profit oil) to international markets and the dividend paymentsfrom SOEs (Safer, MRC and lBThe payment of dividends would depend on the dividend policy of the companies, as determined by the government as sole shareholders, but the assumption here is that all dividends from LNG to YGC and YGASSP will be transferred to the government. l9The Oil & Gas Sector in the Republic of Yemen, A Background and Issues Report, The World Bank, November 2004. 20YPC is responsible for the countrywide distribution and marketing of all petroleum produds (except LPG). YOGC acts as the holding company for both YGC and YPC. MACROECONOMIC OUTLOOK FOR YEMEN ARC) and subsidy savings to the government State Take associatewith YLNG US$13.9 billion by PEC switching to gas are not included in totaling US$14.2 billion over 20 years. this analysis. Two different scenarios are demonstrated showing different levels of Under Scenario B, itwas assumedthatthe whole power sector conversion. The Government power sector will be switching to natural gas and State Take of YLNG is the same in both (TableA1.I). Inthat case, the domesticStateJake scenarios as those fiscal revenue flows are is US$4.2 billion andtheStateTakeassociatewith contractually established. YLNG US$13.9 billion totaling US$18.1 billion over20years. The reasonwhytheStateTakefrom Table 1.IScenario A, shows that Government the domestic sector increased substantially is Take from YLNG and domestic feed gas sales because of the additional feed gas sales to the are US$11.2 billion from 2008 to 2028. YGC powersector over the period at opportunity cost, and YGASSP would receive US$3 billion over US$2.6/MMBTU. Under Scenario C, it was the same period. This assumes that only the assumed that the whole power sector will be 360 MW Marib plant is using natural gas over switchingto natural gas and that the feed gas is the next 20 years. In total, under Scenario A, sold based on the economic netback value of the domestic State Jake is US$0.3 billion and the US$7/MMBTU. In that case, the domestic State Table 1.l:Government and State Take 2008-28 (in US$ billion) - Scenario A -Conversion Government YGC & YGASSP State Take of 360 MW Marib Plant Take Domestic 0.3 - 0.3 LNG 10.9 3.0 13.9 Total 11.2 3.0 14.2 Scenario B -Conversion Government YGC & State Take of Whole Power Sector Take YGASSP at OpportunityCost Domestic 4.2 - 4.2 LNG 10.9 3.0 13.9 Total 15.1 3.0 18.1 Scenario C Conversion - Government YGC & YGASSP State Take of Whole Power Sector at Take Domestic Netback Value Domestic 10.5 - 10.5 LNG 10.9 3.0 13.9 Total 21.4 3.0 24.4 Source:Authors' estimates. Note: Dividend payments of Safer, MRC and ARC and energy subsidysavingsof PEC switching to gas ore not included in the above revenue flows. It is further important to stress that Yemen may find new associated and nonassociated gas resources that would further increase government revenue from export and domestic sales which are not included. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Take is US$10.5 billion and the State Take Evenif successfulfiscal reformsare implemented associate with YLNG US$13.9 billion totaling that allow GOY to double the contribution of US$24.4 billion over 20 years. nonhydrocarbon revenueto GDP over the next 15 years, additional sources of government Conclusions income would need to be sought to avoid Based on data provided by GOYin 2004, the having to implement sharp fiscal adjustments country will experience a sharp decline in oil at a later stage. productionand associatedcrude oil exportswith Figure 1.2 shows the sharp decline of oil the potentialof becominga netcrudeoil importer production, the YLNG Government and in the near fut~re.~'Figures 1.2, 1.3 and 1.4 set State Takeand the relativelysmallfiscal revenue out expected State revenue from gas and oil in flow from feed gas sale to the 360 MW Marib the period 2008-28 under different scenarios. gas-fired power plant operated by PEC. It isfurther understoodthat recentdiscoveries in Figure 1.2 assumes that only the Marib plant existing and new producing blocks maysmooth will be supplied by natural gas. Overall, gas that trend (but new data have not been made exports and domestic sales contributeto reduce available to the authors). some of the fiscal revenuedecline dueto falling For purely macroeconomic planning and fiscal crude oil production. However, the overall fiscal purposes, a prudent approach ignores revenue position remains challenging and further from l'possible" future hydrocarbonreservesuntil highlights the importance that the government such time as such reserves are proven. This is efficiently uses the revenue generated from oil becausethe aim of fiscal policyisto ensurefiscal and gas over the next decade. sustainabiliv2which requiresthat government's expenditureplan are tailored to matchthe level Figure 1.3 assumes that the "whole" power of revenue that can be anticipated with a sector switches to natural gas, including newly reasonable degree of certainty. constructed generation plants and pays US$2.6/MMBTU for the feed gas. This could Inorder for Yemen to achievefiscalsustainability generate substantial fiscal revenue from feed and reach a level of nonhydrocarbon primary gas sale to PEC and could further offset some deficitz3of 5-6 percent of the GDP by 2025, of the revenue losses expected from declining strict fiscal policy measures will have to be crude oil production. implemented, including introducing the GST, abolishing petroleum subsidies and promoting Figure 1.4 assumesthat the whole existing and the nonhydrocarboneconomy (in particular, the future power generation load runs on natural industrial and services sectors). gas and the sector payseconomicnetbackprices Toestimate GOY'Soil revenue the average take at country level was applied to the production profile provided by PEPA in 2004. No detailed modeling of the termsof existing production sharing agreements contracts was attempted. PEPA has recently provided a new production forecast which takes into account the effect of the use of secondary and tertiary recovery methods on existing fields, as well as new discoveries. The new production profile shows a considerable improvement in production levels over the medium term. Given that secondary and tertiary recovery normally involves high levels of investment, and that commercial terms applicable to new production sharing agreements are likely to differ from historical terms, applying the average take at country level to the new production profile would not be correct. For this reason no attempt was made in this paper to update the revenue forecast. It is however recommended that a more detailed analysis be carried out at contract level. "A government's fiscal program is sustainable if its implementation does not result in unacceptable risk of insolvency for the State now or in the future. 23A primary deficit is the deficit without interest payments. MACROECONOMIC OUTLOOK FOR YEMEN Figure 1.2: ExpectedState Revenuefrom Gas and Oil (2008-28) -- -CrudeOilRevenue(basedon2004PEPAdata) - Gas Revenue (GovernmentTake FeedgasSale to 360 MW Marib I) - - Gas Revenue (GovernmentTake LNG) - Gas Revenue (StateTake LNG) - ,TotalCrudeOilandGasRevenue(StateTake , -LNG and Feedgas Sales) Source: Authors' calculations. of US$7/MMBTU. This would create substantial To unleash this potential, GOY will have to fiscal revenues from feed gas sale to GOYand promote the development of a domestic gas feed gas revenues from selling gas to the pipeline infrastructurethat is requiredto provide domestic power sector match the Government the power sector (and potential other customer Take from YLNG over the 20-year period and groups)with access to this relativelycheap and substantially raise fiscal revenues. clean fuel. This report demonstrates the Figure 1.3: Expected State Revenue from Gas and Oil (2008-28) - Years Crude Oil Revenue (basedon 2004 PEPA data) I ..-, Revenue(GovernmentTake-FeedgastoWholePowerSectoratUS$2.6/MMBTU) Gas - Gas Revenue(GovernmentTake - LNG) -Gas -- Revenue(StateTake-LNG) Total Crude Oil and Gas Revenue (StateTake LNG and Feedgas Sales) - Source: Authors' calculation. REPUBLICOF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Figure ExpectedState Revenuefrom Gas and Oil (2008-28) 4500 - 1500 - 1000 - -Crude Years - - - . Oil Revenue (basedon 2004 PEPA data) -Gas Revenue (GovernmentTake - Feedgasto Whole Power Sector at US$7/MMBTU) -Gas Gas Revenue (GovernmentTake -LNG) -- Revenue (StoteTake -LNG) Total Crude Oil and Gas Revenue(State Take LNG and Feedgas Sales) - economics of developing the domestic gas provide the government with additional market in Yemen and recommends that the opportunitiesto generatefiscal revenuesthrough private sector or a private-public partnership additional LNG exports and/or domestic leadsthe effort. gas sales. However, the conversion of the domestic In addition, substantial nonfiscal benefits could power sector to natural gas, and the be generated by switching the power sector to construction of new gas-fired plant to meet natural gas. These efficiencygainswould result future power demand, will not fully from lower generation costs that would compensate for the fiscal revenue loss eventually reduce end user tariffs. It was expectedfrom falling oil production and crude estimated that efficiency gains could vary oil exports. The most likely potential for between US$4.4 billion and US$23.2 billion additional sources of revenue is the oil and over a 20-year period, with a basecasescenario gas sector, and it is imperative that GOYtake of US$9.1 billion if government charges measures to encourage gas and oil opportunity costsfor natural gas. If GOYdecides Exploration and Production (E&P) activities. to price along the economic netback of the Future oil and gas discoveries would allow domestic power sector, direct revenues to the the government to halt the sharp decline of government will increase as discussed above. production and its profit share. New Simultaneously, direct efficiency gains to the associated or nonassociated gas discoveries power sector will be lower. 2. Determining the Economic Costs of Natural Gas Introduction requirementsof the YLNG hassecured an offtaketotaling 6.7 MTPA, which isequivalent Yemen is in the process of developing its gas to the guaranteed capacity of the facility. industry and of constructing a LNG facility at The facility will have the capability to produce Balhaf (YLNG)to export natural gas initially to up to 7.2 MTPA of LNG and the incremental the Republic of Korea and to the United States, 0.5 MTPAof LNGwill beemployedfor spotsales with the possibility of later expansion and first to existing customer and then to market diversification of markets. Yemen also aims to where appropriately 7.2 MTPA over a 25-year develop its domestic gas market, in particular period would require approximately 9 Tcf of gas-to-power, switching the power generation natural gas reserves, andthe remainingreserves sectorfrom HFO and dieselto natural gas. GOY could be used for the domestic market or for also envisages supplying the industrial, extending the YLNG capacity. The BPStatistical commercialand potentiallythe residentialsector Review has estimated Yemen proven gas with natural gas in the near future. reserves at 16.9 Td at the end of 2005.27 In April 2007, PEPA has estimated 18.2 Tcf of There is currently a debatewithin Yemen about proven Gas-In-Place(GIP).28 the size of the Yemeni provengas reservesz4and how to supply both YLNG and the domestic Gas costing and pricing principles for selling market. It is understood that GOYhas allocated gas in international markets and domestically 5.2 Trillion Cubic Feet (Tcf) of gas to domestic can be very different. Today, Yemen is able to gas market devel~pment.~~The Petroleum sell its gas abroad at competitive international Exploration and Production Authority (PEPA) is gas prices. Underthe contractualarrangements, currently carrying out an independent audit of YLNG has agreed to sell gas at prices that are its gas reserves. linked to HH for exports to the United States andtoJCCfor exportsto Korea.All gas inYemen Under the GDA, dated September 1995, GOY is currentlyowned by GOYwho makesrevenues dedicatesto YLNG gas reservesfrom the Marib by selling feed gas under the Feedgas Supply fields in sufficient amounts to meet the Agreement (FSA) from the Marib gas fields to Proven gasreserves aregenerally takentobe thosequantitiesthatgeologicaland engineeringinformation indicatewithreasonable certainty, and can be recovered in the future from known reservoirs under existing economic and operationalconditions. Ministerial Degree (Ref.2005/66). 26 Gas DevelopmentAgreement (GDA),September 21, 7995. 27BP StatisticalReview of World Energy, 2006. 28A detailed break-up of GIP per field is aitoched in Annex 2. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK YLNG and by being a stakeholder through customers are relatively low. The financial cost YGC under the GDA with Total, the proiect of the gas will also include any additional taxes developer of YLNG. YGC has a 16.73 percent the governmentdecidesto imposeon end users, shareholding in YLNG and YGC and GOYare but the overall financial costs seem to be entitledto bonuses, royaltiesand a shareof profit relatively low. underthe GDA. Alternatively, Yemen could sell its remaining proven gas reserves from Marib Theeconomiccost isa measurementthat reflects domestically to power generators, commercial the "true" cost of consumingthe gas. Thosetrue and residential customers. In order to assess costs are determined by using efficient prices whether to export the remaining proven gas that would exist in a fully competitive market reserves or sell it domestically, the economic not distorted by any market imperfections costs or true costs of these two alternativeshave (suchas labor marketrestrictions, limited access to be further analyzed. to capital, restrictionson the free movementsof that gas). The term economic costs implies the Economicversus Financial Costs cost of something in terms of an opportunity of Gas foregone (andthe benefitsthat could be received from that opportunity), or the most valuable There are views in Yemen that, because the foregone alternative. current gas reserves in the Marib fields are readilyavailablewithoutfurther E&P investments, InYemen, the benefitsof supplyingthe remaining and because the only required investment is to Marib gas reserves (andany future gas that will develop the infrastructure to transport the gas be developed) to domestic customers at to final customers, for example, power plants, economic and financial costs would have to be the costs of domestic gas are small and comparedwith the revenuesthe country receives negligible. In this context, it is important by exporting the gas at international market to distinguish between the "economic" and prices or leaving the gas in the ground for "financial" costs of providing Yemeni gas to consumption in the future. final customers. Knowingthe financial and economiccost of gas Financial cost is measured from the flow of isessentialfor Yemeni policy makersfor not only actual cash and these flows may include calculatingany implicitsubsidyfor domesticgas, subsidies and taxes (transfer payments). Those but also to compare the net benefit of selling costs do not necessarilyhaveanythingto do with the gas in the domestic market compared to the true cost of consuming the natural gas. In selling it abroad or leaving it in the ground. Yemen, all gas is owned by GOYand, hence, the financial cost for the "commodity" gas to Approaches and Methodsfor the government is zero. In addition, the gas is Determining Economic Costs readilyavailableat a gas cap atthe Maribfields, and it is assumed that operating and capital The way economic costs (and associated gas expenditure for producing that gas is relatively tariffs) are being determined for domestic gas low. A pipeline network will be required to ship varies depending on the level of gas market the gas from the fields toward the load centers development. Infully liberalizedand competitive in and around Sana'a and further. However, gas markets (suchasthe UnitedStates, Australia, because YLNG is required to pay part of the United Kingdom), multiple gas suppliers constructioncost of the pipeline networktoward compete to sell the commodity gas to domestic Sana'a, it is further assumed that the actual or foreign customers ensuring that the gas is financialcostsfor GOYto supplythe powersector priced economically. The construction of DETERMININGTHE ECONOMICCOSTS OF NATURAL GAS the pipeline network is "regulated" by an maximizes economic welfare. This is because independent entity to ensure that Transmission such pricesreflectthe costs involvedin providing and Distribution(T&D)tarifk reflectthe economic an additional amount of output. Where a costs of supplying customers through the customervalues an extra unit morethan itwould pipeline network, and at the sametime to allow cost to produce it, it is economically efficient to the "natural monopoly" network operator to produce that unit. Setting gas prices equal to recover prudently incurred investment costs for marginal cost means that customers will operating, maintaining and expanding continue purchasing additional natural gas, infrastructureand to make a reasonable rate of for example, until it is no longer economically return on its investment. efficient to produce the gas at that price. Marginal cost pricing, therefore, provides Inemerging or verticallyintegrated gas markets signalsto customersand producersencouraging (suchasYemen), competitionamong buyersand them to balance the benefits obtained by sellers does not determine the economic value consuming natural gas with the benefits of of the gas at the customerend and governments producing the resource. have to assess both the value of the gas commodityand the associatedcostsfor network The short-run marginal cost are the marginal development to establish final gas tariffs. costs of an extra unit of output from existing capacity. Long-run marginal costs are the Inthe case of Yemen, currentlyall gas is owned marginal costs for an extra unit including the bythe governmentandthe powersector isState- cost of increasing capacity. The latter concept is controlled. At the initial stage of domestic gas more relevant to the costs of long-term market development, there will be no infrastructuredevelopmentssuch as natural gas competition between buyers (the State-owned upstream and downstream network. power sector) and the sole seller of gas (that is the government)and GOYwill haveto determine Despitebeing theoretically robust, and ensuring the economiccosts of supplyinggas to domestic that costs are recoveredin an expanding system, customerswhich will require analysis of: a) the the calculation of marginal costs is a difficult cost of gas atthe production stage (thatis at the process and calculation requires modeling of well head); and b) the costs at various ofhake alternative investment plans (or production points from the network (supply). schedules in the case of gas fields) to meet Gas ProductionCosts incremental demand. There are three methods that can be Netback-of-Market Value considered to calculate the economic cost of gas at the production stage (that is at the well The principle of this approach is that the head), including: economic value of gas is based on the price of substitute goods that customers are willing to Marginal cost; pay, with the intermediate costs netted off. This establishes a maximum Willingness-To-Pay Netback-of-market value; and (WTP)for gas. The netback-of-market value is therefore the price at which a gas company Opportunity costs. would price to obtain the maximum possible Marginal Cost pricefrom customerswithout losing marketshare to another form of energy. The netback-of- Economictheorystatesthat, in efficientmarkets, marketvalue can be applied both for domestic pricing a good or service at its marginal cost and international customers. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Box 2.1:Methods for CakukatingMarginalCosts at the Well Head Netback calculations can be used to generate The data for calculating a netback curve is demand curves that show the quantity of gas differentfor each sector and customer, based that might be bought for a range of prices. on the alternative fuels used; This pricing method is a way of calculating the maximum price at which gas could be sold to a It may not encourage a rapid development competewith the substitute fuel for each type of of the domestic gas market, asthe pricemay customer. The market value of natural gas is, be too high to encourage switching and by definition, the break-even level that makes demand; and gas as attractive as the best alternative fuel, taking into account differences in efficiencies, 'Theresultinggaspricesmaybe~msidered operating costs and investment costs. too high from a social equity perspective. Netbackpricing isa concept applied in different However, if successfully applied, this approach ways in the gas sector. It is commonly used to would ensure that the gas seller maximizes its estimate well head prices. Netback pricing revenues from domestic and/or international "nets-back" to the producer from the value of customers. gas at the point of consumption. Knowing the netback price will inform the gas seller of what * OpportunityCosts certain types of customers are willing to pay for natural gas in Yemen and abroad. Although Economic pricingtheory draws heavily on the the concept of market value pricing could concept of opportunity cost. Opportunity cost be applied in Yemen, there are several is the simplest and most direct way of challenges, including: estimating economic cost. Opportunity cost is the value foregone by using a resource in Calculating netback is a data-intensiveand one activity, which necessarily precludes its time-consumingexerciseand the calculation use in an alternate activity. In Yemen, the needs to be carried out in a "bottom-up" opportunity cost of gas in the domestic market approach starting from final customers; is the lost export earnings. DETERMININGTHE ECONOMICCOSTS OF NATURALGAS Yemen is in the process of developing LNG of the commodity gas at the well head one has export facilities and the LNG market offers to calculatethe infrastructurecosts of supplying competitive access to international gas prices. gas to different offtake points from the The opportunity cost of current Yemeni gas is transmission network such as maior customers the international price from a relevant (forexample, a power plant inAden or Marber), destination market (for example, the United the costs of supplying different customer States and Korea markets) and netted back to categories (for example, cement factory, the Marib fields. commercial customers)and also average retail costs for residential load supplied from the Theopportunitycost approachis relevantso long distribution system. as gas is assumed to be substitutable between exports and domestic consumption. As long as This requires an analysis of: (a) the total Yemen has limited gas reserves and the option infrastructure development costs and cost to export gas, one can assume that gas is structure, essentiallyfixed and variable costs of substitutableat the margin.29 the networks; and (b)an approachfor allocating those costs to different offtake points from the The opportunity cost approach is economically gas network and for different categories and theoretically valid and its adoption would of customers. ensure an efficient use of gas resources for the economy as a whole. It is also a relatively The opportunity cost and marketvalue concepts simple calculation not depending on detailed do not provide the information required for cost data (as required for marginal cost and determining costs for physical infrastructure, netback-of-marketvalue calculations).However, suchasgas pipelines. The appropriateapproach there are alsoa numberof challengesassociated . IS marginal cost. with this approach. International gas prices are not a unique numberand dependon contractual EconomicCosting Optionsfor Yemen - commitments aswell as beingdriven byexternal factors. For contracts are From an economiccosting perspective, one has indexed to JCC and HH prices which may be to distinguishbetweenthe cost of gas production volatile and unpredictable over longer periods at the well head and the cost of supplying the of time. In pricing basedOn gas to customersthrough the T&D network. To costs, if translated into domestic prices, is likely determine the well head price, or production to imply higher domestic gas prices compared costs, Yemen can, in principle, employ three to an approach based on marginal costs. approaches, namely marginal cost, opportunity G~~~ ~ ~ and i ~~ ~costs i ~b ~ cost and netback-of-market value. Table 2.1 ~ ~ i~ ~ ~ ~ i ~ summarizes the economic costing options for In addition to determining the economic costs domestic gas in Yemen. 29The difference to the netbock-of-market volue approach is that o gas seller would price discriminate among various customer and customer groups abrood bosed on their WTP to maximize revenues. In contracts, the opportunity cost calculation relies on a single benchmark for o gos price to colculote economic costs, for example, HH far the United States or JCC for Korea, without netting bock to the fino1 customer (for exomple, o power plont or industrial food in each market). REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Box 2.2: Methodsfor CalculatingMarginal Costs for Pipeline Network Table 2.1:EconomicCosting Options for Domestic Gas Costing Options Production (atthe well head) Marginal Cost * Opportunity Cost * Netback-of-Market Value End User Supply (from network) * Marginal Cost In assessing these options, there are two As long as Yemen faces gas reserve or major concepts that have to be considered production constraints to meet future domestic in determining the economic value of and international demand, incrementalYemeni gas, namely: gas is tradable by exporting it through an expansion of the existing LNG facility. * The size of Yemeni gas reserves and its gas Consequently, the economicvalue of the Yemeni production capacity; and gas sold in the domestic market can be evaluated usingthe opportunitycost or netback- * The substitutability (or tradability) between of-market value approach. If the netback from domestic consumption and export. domestic users is higher than the opportunity costsfrom internationalcustomersand markets, The size of a country's gas reserves, its then Yemen receives the highest economic productioncapacityandwhether or notthey are benefit by selling the gas domestically. tradable, are of key importance in determining the appropriate approach for determining the Assuming that Yemen finds large gas reserves economic value of the gas at the well head. to meet both future domestic and international 16 DETERMININGTHE ECONOMICCOSTSOF NATURALGAS demand, and there are no gas production Table 2.2 sets out the various costing principles constraints, the appropriate methodfor valuing for domestic gas taking into consideration a the gas at the well headto be sold domestically country's reserve position and whether it has is marginal cost. The marginal cost calculation viable export facilities. includes a depletion premium because natural gas is a nonrenewable resource. Using an If it is assumed that the combined incremental opportunity or netback-of-market value domestic and international gas demand for approach for calculating domestic gas price Yemeni gas will be greater than Yemeni supply, costsand priceswould reduceeconomicviability an opportunity cost or netback-to-market value because prices would not reflect the true costs approach (whichever is higher) based on the of providing the gas. substitutability of export for domestic gas demand would be correct. This assumptionmay Gas reserves and production constraints, and change based on a short-, medium- or long- the extent to which gas is assumed to be term time horizon. If there are large gas finds in tradable, may change over time in Yemen. the nearfuture, for example, this would indicate The domestic gas market will remain relatively that a marginal cost approach would be more small for the foreseeable future and, if Yemen appropriate in the short-to medium-term. finds new gas reserves, incremental gas may initially not be fully tradable (for example, until In the Yemeni context, even if there are the LNG facility is extended). In the short- to short-term constraints, because of the medium-term, there may be gas production or substitutabilityof domestic gas for export gas, export constraintswhich could suggestapplying the opportunity cost and netback-to-market the marginal cost approach in a "transition value approach is relevant and important for period" before moving to an opportunity cost GOYto understand the foregone revenues for or netback-to-market value approach until the dedicating gas to the domestic market at constraints have been addressed. The marginal cost (ratherthan exporting the gas at marginal cost approach would include a opportunity costs or selling it domestically based depletion premium to ensure that the trade- on netback-to-market value). off of leaving the gas in the ground today, for production tomorrow, is incorporated in Today, Yemen has limited gas reserves and no the analysis.30 existing downstream gas network. To determine Table 2.2: Economic Costing Principlesat the Well Headfor Domestic Usage Unlimited Gas Reserves Limited Gas Reserves and ProductionCapacity and Production Constraint Tradable Marginal Cost Opportunity Cost or Netback-of-Market Value Nontradable Marginal Cost Marginal Cost 3oThe estimation of a depletion premium for a nonrenewable resourcesuch as natural gas is also an opportunity cost calculation. Thisis based on the option to extract the resource, sell it and reinvest the proceeds or leave it in the ground for use at o later dote. The depletion premium is an additional omount equivalent to the present value of the opportunity cost of extracting the resource at some time in the future, over and above its economic cost today. If the resourceconstraint is a long way in the future, the depletion premium would be small. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK the economic costs and value of domestic gas gas, but an indication based on currently in Yemen, this would suggest following a long- available information and data aiming to term costing approach based on: highlight the considerations that go into determining the economic and financial costs Opportunity cost or netback-of-market of selling gas domestically in Yemen. value from international and domestic customers; and These calculations are highly sensitive to forecasts of international oil and gas prices, Marginal costs for T&D. and to assumptions about the dynamics of market penetration by YLNG. Further, the Charging solely on a long-run marginal cost analysis uses the capital and operating costs basis may ensure that production and of a typical oil-fired and gas-fired power transportationcosts are recoveredto guarantee plants in the Middle East and North Africa the sustainable development of the upstream (MENA) and the cost structure and operating and downstream gas ma rket in Yemen.31 characteristics of the existing plants in Yemen However, itis importantto highlightthat ifYemen may differ. values its remaining gas reserves based on marginal costs for supplying the domestic OpportunityCosts market, instead of a costing approach based on opportunifycostor netback-of-marketvalue, The opportunity cost of selling gas to the it may miss out on economic rent. domestic marketinYemen isthe foregoneexport revenue. The components for calculating the IndicativeCost Calculations opportunity costs in Yemen are set out in Table 2.3: This section sets outs preliminary calculations using the different costing approaches YLNG has signed long-term gas supply discussed above. These cost calculations are agreementswith Kogas (tosupplygas to Korea) not intended to be an accurate forecast of and Suez and Total (to supply gas to the United the economic and financial costs of Yemeni States). Gas pricing arrangements from these Table 2.3: Opportunity Cost for Domestic Gas in Yemen Long-term LNG contract price for gas Less regasificationcost in target market Less gas shipping cost from Yemen to target market Less liquefaction cost at Balhaf Less cost of pipeline deliveryfrom Marib field to Balhaf LNG plant Equals netted back gas price at the gas well head at Marib 3' Long-run marginal cost pricing in the downstream sector may not ensure full cost recovery in case of low network capacity utilization.Cost recovery can only be assured under a two-partpricing methodology, wherethecapacitypayment is linked tosome concept of long-run average capacity cost. 18 DETERMININGTHE ECONOMICCOSTS OF NATURALGAS contracts are a good indicator for calculating for the gas which is sold under the YLNG opportunity costs (andforegone revenues).The contract to Korea which is linked to the JCC. international gas price has to be netted back to CRA calculated that Korean LNG prices will the well head to arrive at opportunity costs. vary between US$6.01/MMBTU in 2007 and US$3.52/MMBTU in 2015. No annualizeddata The opportunity cost calculations are based on was available to the authorsfrom the CRAstudy. the World Bank gas price forecasts up to 2030 using Energy Information Administration (EIA) Shipping rates vary depending on the status of and International EnergyAgency (IEA) gas and the shipping market but, according to CRA, crude oil price forecasts. Based on those rates from Yemen (ex-Balhaf) to the United forecasts, the average U.S. natural gas price States will be around US$1.2/MMBTU.33 between 2006 and 2030 is US$5.5/MMBTU Regasification cost depends on the size of the (Table 2.4). facility and its utilization rate. In the United As part of reviewing the YLNG Charles States, regasification costs are estimated at Rivers Associates (CRA)32forecasted HH prices US$0.30/MMBTU.34 for the next 10 years and estimated gas prices to decrease from US$8/MMBTU in2008 to The largest cost component in the LNG value around US$4/MMBTU in 20 15. Similar chain is the liquefaction plant. LNG plant costs calculationswere carried out by the consultant are typically high, relativeto comparableenergy Table 2.4: Natural Gas Price Forecasts(in US$/MMBTU) Year Pricess Year Price 2018 5.00 Average 5.50 Source: The World Bonk forecastsbased on EIA and IEA data. 32CRAwas commissionedby the MOM to review the economic and financial viability of YLNG. Shipping costs to Korea were estimated in the range of US$0.86 to US$0.97/MMBTU. 34This is according to the Gas Technology Institute (GTI). REPUBLICOF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK projects for a number of reasons including of the associated gas and a FSA has beensigned remote locations and strict design and safety betweenthe governmentandYLNGthatspecifies, standards. Liquefaction costs vary by size and inter alia, quantities (tobe suppliedon a regular, also whether it is a greenfield or expansion daily, monthly and annual basis) flexibility, project. Itwas estimatedthat generic liquefaction specifications, nominations, coordination costs amountto around US$1.1/MMBTU for an procedures. The FSA also specifies the price 8 MMTPS greenfield LNG project.35 YLNG has to pay to GOYfor the gas and it is understood to be US$O.SO/MMBTU at the feed There is no information available for the gas delivery point. project-specificpipelinecostsof shippingthe gas from theMaribfield to the LNGliquefaction plant Assuming that current proven gas reserveswill in Balhaf. For the purpose of this illustration, we cover all future demand for the domestic assume a cost of US$0.30/MMBTU.36 market, the marginal production costs of Marib gas would be the minimum cost that Table 2.5 summarizes the above cost an operator would require to recover to assumptions.The opportunitycostof Yemeni gas operate the facility. Ramboll, a consultant, at Marib is US$2.6/MMBTU for gas sold into estimated marginal costs at the well head for the U.S. marketoverthe next25 years assuming existing fields at below US$0.50/MMBTU. annual average gas prices of US$5.5/MMBTU. However, it is important to stress that these Table 2.5: OpportunityCost of Natural Gas inYemen until 2030 US$/MMBTU United States Gas Price Forecast 5.5 Regasification Cost 0.3 Shipping Cost to the United States 1.2 Liquefaction Costs at Balhaf 1.1 Pipeline Cost from Marib to LNG Plant 0.3 Netback Gas Price at Marib 2.6 Source: The WorldBank estimates based on existing studies, 2006. Marginal Costs are short-run marginal costs from existing fields. To determine long-run marginal costs, Yemen's proven gas reservesat Marib are readily one would haveto make an assessment about available at relatively low production costs, future capital and operating expenditures for because it is associated gas that was reinjected Yet-to-find Fields (YtF) to meet future gas into a gas cap over many years by the operator. demand. This analysis has not been carried It is assumed that the capital cost for producing out to date, but it can be assumed that it will Marib gas is relatively low and costs are mostly be higher than the current short-run marginal relatedto operatingthefacilities. GOYisthe owner cost estimates for the Marib gas. 35EIA, the Global Liquefied Natural GasMarket, Jensen Associates Inc. 36Ramboll assumed pipeline costs of US$O.29/MMBTUin its 2005 Gas UtilizationStudy. DETERMININGTHE ECONOMIC COSTS OF NATURAL GAS The difference between the opportunity cost calculationof thefinancial netbackwhen switching approach (calculatedbased on the netback to from an existing oil-fired plant to a CCGT plant. the field at US$2.6/MMBTU) and the short-run HFO is highlysubsidized inYemen, and currently marginal cost approach (assumed to be the power sector in Yemen pays USQ13 per liter below US$O.SO/MMBTU for existing fields) is of HFO (or US$15.2/bbl). This translates into US$2.1 IMMBTU. That difference is the current fuel costs of an oil-fired boiler plant of "economic rent" or revenue of the government about USQ2.7/kWh37(or US$2.7/MMBTU). by selling incrementalgas from the Marib field domestically at short-run marginal cost. Underthe existing oil plant assumption, capital costs are treated as "sunk" costs (because it Netback-to-Market Value is an existing plant) and, consequently, excluded from the netback calculation. Adding The netback-to-marketvalue is the price a gas Operation and Maintenance (O&M) costs of company would set to obtain the maximum USQ0.7/kWh to the per unit HFO fuel price of possible price, or WTP, from customers. USQ2.7/kWh lead to total generation costs of The netback concept can be applied to both USQ3.4/kWh for the existing plant. domestic and internationalcustomers. Netting those total generation costs back to a Carrying out a netback analysis for every single typical CCGT plant gives a financial netback of customer (and customer group) in Yemen US$2.7/MMBTU. This requiresdeductingcapital (and internationally), including the domestic, costs of USQ0.7/kWh and O&M costs of commercial and industrial sector, would be very USQ0.4/kWh from the total generation costs of data-intensive and time-consuming. US$3.4/kwh. The resulting USC2.3/kWh per unit fuel costs are converted into BritishThermal Units However, the key sector for the development of (BTUs) and multiplied by the higher efficiency the future gas market in Yemen, and for the factor of 52 percent resulting in a netback of allocation of existing gas reserves, is the power US$3.5/MMBTU.38 sector and the calculations below provide some indicativenumbersonthe economicandfinancial Further deducting average pipeline netback of supplying a Combined Cycle Gas transportation costs of US$0.80/MMBTU to Turbine (CCGT) plant with natural gas. supply the gas-fired generator in Yemen results Internationalmarketpricesfor HFOwereassumed ina financialnetbackat a CCGTplantof US$2.7/ for the economic netback calculation. Current MMBTU. In theory, GOYcan sell the remaining subsidized HFO prices were adopted for the Maribgas reservesto a newgas-firedpowerplant financial netback calculation. For both netback at up to US$2.7/MMBTU under the current calculations, the plant characteristicscorrespond subsidized regime and still ensuring that the totypical existingMENAoil- and gas-firedplants. generatorwill switch from HFO to natural gas. Financial Netback-to-Market Value from The financial netback calculation further Existing Oil-fired Plant indicates that returns are higher by switching Table2.6 setsoutthe keycharacteristicsof a typical existing and newoil-fired plantto a CCGT plant oil-fired and CCGT plant and an indicative instead of exporting the scarce gas reserves. 377 MMBTU is equivalent to293 kwh on an energycontent basis.Hence, HFO that is priced at US$2.7/MMBTU and is consumed at a thermal efficiency of 34 percent, has a unit fuel cost of US~2.67/kWh. 3a The US$3.5/MMBTU netback is calculated as follows: USq2.3/kWh (per unit fuel price) *293 (1 MMBTU equals 293 kwh)"0.52 (energy efficiency)/700. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Table 2.6: Financial Netbackof Existing Oil-fired Plant Assumntions Oil-fired Boiler Plant CCGT Plant Generating Capacity (MW) 300 300 Load Factor 75% 75% Output (GWh/y) 1,971 1,971 Heat Rate (Btu/kWh)** 10,035 6,561 Thermal Efficiency* 34% 52% Capital Cost (US$/IW) 800 600 Life of the Plant (years) Fuel Price (US$/MMBTU) 2.7 3.5 Per Unit Fuel Price (USQ/kWh) 2.7 2.3 Other O&M Costs (USC/kWh)* 0.7 0.4 Per Unit Capital Cost (USC/kWh)* 1.4 0.7 Generation Costs (USQ/kWh) 3.4 3.4 PipelineTransportationCosts (US$/MMBTU) 0.8 Financial Netback at Gas Plant (US$/MMBTU) 2.7 Note: *MENA average basedon IEAdata, **3412BTU/Efficiency Rate. World Bank estimates. However, the financial netback calculations aware of regulatory and political risks and, do not take into consideration regulatory in particular, domestic energy pricing policies, and political risk (for example, potential and is mostly unwilling to provide large regulated tariffs that do not recover costs and upfront capital investments in infrastructure nonpayment) of supplying gas into the projects unless those risks are mitigated by domestic market. This is also referred to as a the government. "risk-adjusted" financial return. In Yemen, private capital has been adequately Intheory, if potentialprivateinvestorsignoresuch available for developing YLNG, but not for gas risk, scarce Yemeni gas resources should be projectsthat supplythe domestic market. This is an allocated to enable the development of gas indication that, to date, the risk-adjusted financial infrastructure by private investors. However, return for supplying the domestic market, as experiences from Yemen and other countries perceived by the private investors, is lower than suggest that the private sector is very well the returns expected from exportingthe gas. DETERMININGTHE ECONOMICCOSTS OF NATURAL GAS EconomicNetback-to-MarketValuefrom As inthe caseof the financial netbackcalculation Existing Oil-fired Plant for existing plants, the capital cost component of the oil-fired plant isconsidered as "sunk" and For the economic netback calculation, a is not included in the economic netback long-term market price of HFO of USQ26 per calculation. Considering the higher thermal Liter (I) (orUS$30/bbl)was assumed. Thiswould efficiency and lower per unit capital and O&M translateintofuel costsforanexistingoil-firedpower costs of a new CCGT plant, compared to an plantof US$5.3/MMBTU. The economicnetback existing oil-fired plant, the economic netback, for a typical CCGT plant, switching from an or the maximum price GOYcan charge for the existing oil-fired plant, iscalculated inTable 2.7. Marib gas (or the WTP of the CCGT plant Table 2.7: Economic Netbackfrom Existing Oil-fired Plant Assumptions Oil-fired CCGT Boiler Plant Plant Generating Capacity (MW) 300 300 Load Factor 75% 75% Output (GWh/y) 1,971 1,971 Heat Rate (BTU/kWh)** 10,035 6,561 Thermal Efficiency* 34% 52% Capital Cost (US$/kW)* 800 600 Plant Cost (US$ MM) 240 180 Life of the Plant (years) 30 30 Fuel Price (US$/MMBTU) 5.3 7.4 Per Unit Fuel Price (USQ/kWh) 5.3 4.9 Other O&M Costs (USQ/kWh)* Per Unit Capital Cost (USQ/kWh)* 1.4 0.7 Generation Costs (USQ/kWh) 6.0 6.0 Pipeline Transportation Costs (US$/MMBTU) 0.3 Economic Netback at Gas Plant (US$/MMBTU) 7.1 Note: "MENAaverage based on IEA data, **3472 BTU/Efficiency Rote.World Bank estimates. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK operator)is upto US$7.1/MMBTU (considering the opportunity cost of selling it in international US$0.30/MMBTU gas transportation costs).39 markets (through YLNG) or the netback-to- market value of selling the gas to domestic Theabovecalculationssuggestthatthe economic customers (that is, mainly power generation). returnof sellinggasdomesticallyisvery high, and If Yemen discovers substantial gas reservesthat potentially higher than selling it in international would besufficientto cover bothfuture domestic markets at opportunity costs. However, this and international gas demand, the appropriate assumes that a private investorwill carry out the domestic pricing approach would solely be necessary investments required to develop the based on LRMC. domestic gas sector and that may require in the Yemeni contextthatthe governmentsubstantially GOY could, for policy reasons, decide to reduces investment risk. "dedicate" some of its scarce gas resources, based on marginal costs, to encourage the Conclusions penetration of natural gas in the domestic market. However, this may create market There are some views in Yemen that because distortions as the gas could be considered naturalgas isreadilyavailableatthe Maribfield, subsidizedanddemandwould beinflatedbeyond that gas should be cheaply available for what might be considered efficient resulting in domestic usage, in particular gas-to-power. wasteful use of energy. The volume of this excess There is a difference betweenthe economicand demand would depend on the gap between financial costs of supplying gas to the domestic marginal cost-based prices and opportunitycost market and this paper argues that GOYshould or netback-to-market value-based prices. consider the true value of its gas resources In addition, by pricing at marginal cost, GOY reflected in the economic costs of consuming would missout on "economic rentffwhich itcould the gas. generatebyexporting its reservesat international market pricesor selling it to domestic customers There are three principal approaches for at netback prices. calculatingeconomic costs, namely opportunity cost, netback-to-market value and marginal Theopportunitycost iscalculatedby netting back cost. Marginal cost is the minimum price a gas the international gas price to the well head in seller has to charge to recover its prudently Marib. Preliminary calculations have shown incurred costs. Being a nonrenewable an opportunity cost of US$2.6/MMBTU over resource, the size of a country's gas reserves 25 years compared to a US$O.SO/MMBTU as well as its tradability (that is the option to based on a short-run marginal cost approach. sell it in international gas markets) are of key There are currently no data available on the importance to determine the most efficient LRMC of producing natural gas in Yemen. It is costing approach. importantto point out that this opportunity does not reflect the actual financial payments GOY Today, Yemen has limitedgas resourcesandthe (and its agencies) receives through the export economic value of the existing gas reserves is of the gas. These financial payments would 39TheWorldBankestimatedin2007thatthe netbackvalueof gosinYemenwas at5.35/MMBJU for an open-cyclegas-firedplant and 7.49/MMBJU for a combinedcycleplantrespectively.Referto Razavi, H., NaturalGas Pricingin Countriesof the Middle East and NorthAfrica, A World Bank Publication. 24 DETERMININGTHE ECONOMICCOSTS OF NATURALGAS include the revenues from selling the feed gas export options, in which the private sector has underthe FSA, as well as the bonus and royalty demonstrated its willingness to invest. payments, and GOYprofit split from YLNG, and the dividends received by YGC for its equity This may suggest that although the financial share in YLNG. However, it is unlikely that a netback calculations in this paper suggest a project developer would accept financial higher financial return for domestic usagethan payments that are higher than the economic for exporting the gas, the "risk-adiusted" netback in the long run. financial return by the private investors may actually be much lower. This is mostly caused The power sector is the most likely customer by regulatory and political risk assumptions of for Yemeni gas and a preliminary netback-to- the private sector and, most importantly, by the marketcalculation hasshownthat the economic perceptionthat domesticgas priceswill noteven netback for an existing oil-fired plant that allow for cost recovery of supplying the switches to a gas-fired power plant would be gas domestically. US$7.1/MMBTU respectively. The current financial netback for a similar existing oil-fired The likely unwillingness of private investors to plant switching would be US$2.7/MMBTU. develop gas reserves and infrastructure for the domestic market also has implications for using These indicative calculations suggest that the theeconomicnetback, whichiscomparativelyhigh economic and financial rate of return to using for domestic gas usage as a policy benchmark the gas domestically for power generation are for utilizingthe remaining Yemeni gas reserves. higher than the rate of return generated by exportingthe remaining gas reserves. Intheory, Unless domestic gas prices, regulatory and if economic netback values from the domestic political risks are reduced, it is likely that no power sector are consistentlyhigher than future private investor will be willing to contribute to gas export revenues, then allocating any the development of the domestic gas market. additional limited gas reservesto export is only This could leadto the allocation of scarcepublic advisableonce domesticuseisfully assured over resourcesto develop domestic gas infrastructure the long run. In practice, policy makers have to and crowd out public investment in education, be awareof severalissuesbeforetranslatingthe health, infrastructure and other sectors that above indicative findings into actual decisions may potentially create higher economic of allocating remaining gas reservesto develop returns for Yemen. the domestic sector. This public financing effect could be mitigated In principle, if the economic return is much by the government recovering fiscal resources higher for domestic use than for gas exports, from the gas sector by taxation of the investment in domestic use is the preferred considerable amount of "economic rent" from option for GOY.Further, if the financial return is the development of natural gas resources in higher for domestic use than for gas exports, Yemen. These tax revenues could be utilizedfor this would suggest that the private sector would public expenditure in other sectors. prefer to develop and supply the domestic market. However, what we have experiencedin A more important aspect may be that financing Yemen is that the private sector has been requirements for developing the domestic gas unwilling, to date, to provide capital to invest in market are substantial and public borrowing gas E&P and to develop gas infrastructure. could seriously reduce the government's ability That has encouraged GOY to explore gas to borrow for other important investment REPUBLIC OFYEMEN:A NATURALGAS INCENTIVEFRAMEWORK projects that can only be financed publicly. It Consequently,unlessitcanbeassuredthatthe private was estimated that the construction of the NGP sector develops the domestic gas sector, it may be would require an investment of approximately undesirablefor decision makersto followeconomic US$800 million. At the same time, current retums as their principal criterion for allocatingthe public debt of Yemen is about US$5 billion. As remaining gas reserves, and for developing the a consequence, public borrowing of a large domestic market. Incontrast, if the private sector share of the capital required to develop gas iswilling to finance domestic gas infrastructure, transportation infrastructure may affect the the above calculations indicate that the country's overall borrowing capacity and economic returnsare much higher bysellingthe jeopardize its servicing of debt capability. gasto the domestic powersector than for export. 3. A Framework for Developing the Domestic Gas Market Introduction conveyance of the gas in the transportation system. That anchor customer in Yemen is the The previous Chapter has highlighted the power sector. comparativeeconomic benefitsof supplyingthe domestic market with natural gas for power Consequently, it is the economics of converting generation in Yemen. Various gas utilization and connectingthe power sector to naturalgas, studies have been carried out over the last and its willingness to enter into long-term decade evaluating the economic and financial contractual arrangements with the pipeline viability of developing the domestic company, which will be a key determinant of Although there remain uncertainties about the the timing and sizing of new gas transmission exact technical specification and sizing of infrastructure. Switching the power sector to pipelines, there seems to be a broad consensus natural gas in Yemen would reduce its oil on the viability of building domestic gas dependency which could be earmarked for infrastructure and on the routing and corridor exports to boost government revenues. It was for a future NGF! estimatedthat over a 30-year period, about 800 million bbl(s)of crude oil could be saved by the Justifying the development of a domestic gas power sector by switching to natural gas. infrastructurenetworkbasedon ambitioussector Analyzingfurther, the powersector as a potential growth forecasts of the commercial, industrial anchor customer for gas and addressing and agricultural sector inYemen, and based on potential barriers is one of the objectives of new sunrise industries in the country (for this Chapter. example, petrochemical sector, fertilizer industries), have to be viewed with some It was further argued that Yemen has limited skepticism. International experience shows that publicfunding, and that scarce public resources greenfield gas development and setting up of should be allocated to areas where private new gas markets requireanchor customerswho capital is not available, and where public consume large volumes of gas, preferably with financing may create potentially higher high load factors, and are willing to enter into economic returns. Consequently, creating an long-term commercial agreements for the investor-friendly environment that reduces purchase of the commodity gas and for the regulatory and political risk for domestic gas 40Ramboll, Natural Gas Utilization Study, Yemen, November 2005; Gas Strategies, Natural Gas Pipeline PrefeasibilityStudy, August 2002; Beicip-Franlab, Master Plon for the Development of the Electricity Supply and the Utilization of Notural Gas, October 7 999; GosunieEngineering B.V. Gas Utilization Study, June 1992. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK pipeline developmentwill be of key importance and implementation which could increase to develop the domestic gas market. Broadly domestic production to around 6 MTPA from setting out such a framework isanotherobiective 2011 This would require 500 Million Cubic . of this Chapter. Meters (Mcm) of natural gas annually to meet that cement sector demand if switched to The PowerSectorasAnchor Customer natural gas. FutureGas Demand and the Importance Currently, National Cement Company (NCC) of Anchor Load and Arabia-Yemeni Cement Company (AYCC), two private project developers, plan to import Ramboll, a consultant, had carried out a gas coal from South Africa and Indonesia at an demand forecast in 2005 which is summarized estimatedcost of US$2.5-3.7/MMBTU to provide in Figure 3.1 .4' For existing industries, it shows both plants with energy. This price is the plant the key importance of the power sectorwhich is delivery price and includesall duties and taxes, discussed in more detail below. Switching of freight and handling. In addition, these plants existing and construction of new cement plants are installing imbedded power generationof 32 offers additional opportunities for natural gas. MW and 36 MW using fuel This power demand could add another 100 Mcm of gas In 2006, Yemen State-owned cement plants annually if those plants can be connected to produced 1-5 Mt of cement and importing an natural gas supply at a later stage. additional 2.2 Mt to meet domestic demand. It is understood that two existing State-owned All other industries on the graph, including plants are currently being expanded and new fertilizer, desalination and CNG/transportation - ~ privately financed proiects are under planning are not establishedto date in Yemen. Figure 3.1:Estimateof Gas Consumption (in Tcf) 2007-25 Power -4- Cement Ferhl~rer Derolmotton * CNGflronrport tcx- Years Source: Ramboll, June 2006. Ramboll hasestimatedthe total annual gas market in Yemenin 2025 at 0.42 Tcf (correspondingto 72 BillionCubicMeter [Bcm]) using a bottom-up or sector approach. The consultant's top-down approach, based on Total Primary Energy Supply (TPES)per capita, and the natural gas share per TPESfrom other relevantjurisdictions estimated demand between 72.2and 7 7.6 Bcm. 42 TheNCC plant will be built near Aden and theAYCC plant near A1Mukalla wheresupply from the currently planned NGP is not envisaged but could, in theory, be supplied from another gas source in Hadramout. Thenew Aden cement plant could potentially be supplied from the NGP if it is built until Aden. A FRAMEWORK FOR DEVELOPINGTHE DOMESTICGAS MARKET While new industries may develop in the near The Characteristicsof the Power Sector future, the construction of a greenfield gas transmission pipeline requires that anchor An "anchor customer" is a largecustomer(s)that customers are willing to enter into long-term is neededto make a pipeline projectfinancially contractual arrangements for the supply and attractiveto investors. The Yemeni power sector transportation of gas to mitigate the risk of is of key importance for the developmentof the potential pipeline investors. Typical long-term domestic gas market and the economics of contractual arrangements for greenfield gas greenfield gas pipeline construction. There is transmission pipeline developments include: some potential to convert existing industrial load to natural gas, that is, cement, but the Gas Sales Agreement(s) GSA(s); and- gas volume uptake of those sectors are Gas Transport Contract(s)- GTC(s). relatively small. GSA(s) are contracts between parties for the Yemen is short of power and the least electrified purchase and sale of the commodity natural country in the MENA region, with only about gas and tend to include take-or-pay clauses.43 40 percent of the population having access to GTC(s)are contractsfor the conveyance of gas electricity. The PEC, the State-ownedpower utility on a pipeline network and tend to include firm and sole supplier of electricity, has around 774 capacity rights.44 MW of installed generation capacity on its interconnectedsystem.46All of PEC's plants are International experience shows that without those currently running on HFO/ Light Fuel Oil (LFO) contractualarrangements, includingtake-or-pay and/or diesel and the company estimated that clauses and firm capacity rights, it is unlikely with demand for electricity growing steadily and that a private investorwould finance greenfield assuming a reserve margin of 21 percent for gas pipeline development in Yemen. maintenance and unplanned outages of There are industriesthat GOYaims to promote, generation units, it would require an additional such asfertilizer, desalinationplants, naturalgas 1,400 MW of installed generation capacity to vehicles and others that could use natural gas meet its target of 2,200 MW by 2010. In total, in the future. However, those are not industries about 3,000 MW is planned to be constructed that are established to date. Hence, it is the over the next 20 years4' This is an ambitious power sector that will have to act as the anchor plan but highlights the potential for future customer for the gas market and pipeline gas-fired plants in Yemen. development and sign long-term GSA(s) and GTC(s). Without that commitment, it is unlikely To ensureefficientinvestmentin newgeneration that a privateinvestorwould bewillingto finance capacity, GOYshould consider developing and the constructionof pipelinesin Yemen.45 establishing policies that attract private 43A contract provision obligating the buyer to pay for a certain minimum quantity of a produd irrespective of whether or not the buyer actually takes that quantity during the stated period. " A firm wpacifyprovidestheshipper witha rightto useresend, prespecified and definedcapacityon a pipelinetoshipgas.However,the shipper will have to pay for the firm capacity irrespective of whether or not gas is actually shipped on the pipeline on his behalf. 45 Generators who are required to sign take-or-pay contracts for gas supply tend to mitigate that risk by requiring take-or-pay minimum offtoke of power under their long-term power sales agreements with final customers. Thiswill mitigate and avoid the risk of mismatch between fuel purchase and fuel consumption. 46PEC operates an estimoted 80 percent of the country's generating capacity. Theremainder of Yemen's electricity is generakd by small off-grid suppliers and privately-owned generators in rural areas. "Kennedy & Dunking prepared a Power Generation Master Plan covering theperiod 2000-2025. Theplan was updated in 2003 in cooperation with the World Bank and PEC. REPUBLICOF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK investmentin power generation by Independent gas. However, that capacity supplies isolated Power Producers (IPPs).~~ systems in the western desert part of the country which is not located near any proposed gas Currentpowertariffsdonotreflectthecostsofsupply pipeline infrastructure. Consequently, it is not and PEC lacks liquidity. Despite the demonstrated included in the subsequent analysis. economic and financial benefits to the power sector, moving away from HFO and taking up Table 3.2 sets out new gas-fired power plants natural gas requires financial strengthening of that are currentlybeing commissionedor are at the sector and reform and restructuring. the planning stage. PEC is currentlyconstructing a new 360 MW open-cycle gas-fired plant PEC's least-costgenerationexpansionapproach (OCGT)inMariband is preparing the extension not only aims to commission new gas-fired of the plant with an additional 400 MW. power plants, but also to convert some of the The Marib plant will be supplied by a short existing plantswhich currently run on HFO and dedicated gas pipelinefrom the Marib gasfield. diesel to natural gas. PEC's least-cost generation expansion plan Table 3.1 shows that 600 MW of existing plant further envisages the construction of an OCGT capacity could be converted to natural gas in plant in two phases in Maber, south of Sana'a. the interconnected system. In principle, 94 MW Phase I would install 400 MW of capacity and of generation capacity at Al-Rayan and Wadi Phase II an additional 800 MW. Both phases Hadramout could also be converted to natural are still at a planning stage. Table 3.1: Existing Generation PlantsSuitable for Conversionto Natural Gas Power Station Fuel-type Total Installed Total Energy Capacity in Generated in 2005 (MW) 2005 (GWh) InterconnectedSystem Ras Katnib HFO 150 1,014 Al-Mokha HFO 160 767 AI-Hiswa HFO 125 719 Al-Mansoura Diesel 64 277 Hizyaz-1 Diesel 30 690 Hizyaz-2 LFO+HFO 68 Total 597 3,467 IsolatedSystem Al-Rayan HFO 47 227 Wadi Hadramout Diesel 47 211 Total 94 438 Source: Information provided by Public Electricity Cooperation (PEC). 48Even under the existing market structure for the power sector, with PEC as a vertically integrated electricity utility, IPPs could be promoted and established selling power under long-term supply agreements to PEC. This could help to meet the ambitious new power generation capacity requirements ond may improve overall efficiency of the sector. 30 A FRAMEWORKFOR DEVELOPINGTHE DOMESTIC GAS MARKEl Table 3.2: Commissioned and Planned Gas-fired Power Plants Power Station Fuel-type Total InstalledCapacity (MW) Commissioned - - - - -- Marib I OCGT 360 Planned Marib II OCGT 400 Maber I OCGT 400 Maber II OCGT 800 Total 1,960 Source: Informationprovidedby PEC. PEC is planning open cycle insteadof combined (possibly in combination with a desalination cycle plant technology for both Marib and plant). PEC is in the process of reviewing its Marber.An opencycle gas-fired plant burnsgas least-cost power generation expansion plan by to operate a turbine; a combined cycle turbine carrying out a technical and economic analysis also uses waste heat to produce steam and of moving the planned new 1,200 MW generate further ele~tricity.~~With 34 percent generation capacity from Maber to the coast, efficiency, OCGT plants have a lower efficiency using CCGT technology. than CCGT plants.50Modern CCGT plants can get upto 58 percentefficiency, but are generally In total, there is about 2,500 MW of existing around 55 percent. and planned power generation capacity that could potentially run on natural gas. According to PEC, for cooling the steam The economics of converting or building a new turbine and for producing steam in a CCGT gas-fired plant can be analyzed by calculating plant, large quantities of cooling water are an "economic" netback. The economic netback required that are not readily available in the is the maximum price an existing power plant Marib and Marber desert areas where the operator would be willing to pay for the gas plants are being located. Consequently, without losing market or without being "worse- OCGT technology was selected. o f f than running the plant on current fuel. Oneof the major advantagesof the construction The economic netback calculation is a of a NGP, which will partly run along the Red comparative analysis of running a new or Sea coast, is the access to cooling water and existingHFO plantandan OCGT or CCGT plant potential to construct modern CCGT plants and includes an assessment of: 49A two-stage electrical generation process is carriedout in a CCGT. In the first stage, electricity is generatedby a gas turbine. The waste heat is then usedto generate morepower bysteam turbine. The thermal efficiency rate of 34 percent for OCGT plant reflects the rate of older simple cycle generators. Modern aero-derivativesimplecyclegenerators can havean efficiencyrateof around43 percent. The mostsuitabletechnologyfor Yemen will haveto be further assessed. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Fuelcosts at marketprices(thatis, gasversus The calculations in Table 3.3 are based on HFO or diesel); an average long-term oil price forecasts of Operational efficiency of plant; US$30/bbl and sets out an indicative economic netback calculation for the Capital costs; proposed 400 MW OCGT Marber I (or Gas pipeline transportation costs to the alternatively a new CCGT ~ l a non the ~ e d t plant; and Sea coast) compared to the newly constructed oil-fired power plant. Conversion cost^.^' Table 3.3: Economic Netback for Natural Gas for New OCGT and CCGT Plant Plant Characteristics Average Existing Maber Hudaidah Oil-fired Plant OCGT CCGT in Yemen Generating Capacity (MW) 400 400 400 Load Factor 75% 75% 75% Output (GWh/y) 2,628 2,628 2,628 Heat Rate (BTU/kWh)* 10,035 10,035 6,200 Thermal Efficiency Capital Cost (US$/kW) 800 700 700 Plant Cost (US$ MM) 240 280 280 Life of the Plant (years) 30 30 30 Per Unit Capital Cost (USC/kWh) 1.4 0.7 0.7 Fuel Price (US$/MMBTU) 5.3 6.3 10.2 Per Unit Fuel Price (USC/kWh) 5.3 6.3 6.3 Other O&M Costs (USC/kWh) 0.7 0.4 0.4 Generation Costs (USC/kWh) 7.4 7.4 7.4 Pipeline Transportation Costs (US$/MMBTU) 0.8 0.8 Economic Netback at Gas Plant (US$/MMBTU) 5.5 9.4 Note: '34 72 BTU/Efficiency Rate. Source: The World Bank calculations based on data provided by PEC. 51A gas conversion involves changes to the engine, the control system and power plant systems. The conversion of the engine is mainly restricted to the installation of a gas fuel system on the engine. For the plant systems, it is necessary to install gos feed and gas handling systems, to change the exhaust gas system and to replace the power plant control and automation system. 32 A FRAMEWORK FOR DEVELOPINGTHE DOMESTIC GAS MARKET The Marber plant is a proposed new plant and, capital costs are treated as "sunk" costs and hence, the capital cost component of the consequently excluded from the netback oil-fired plant is considered in the economic calculation. Adding O&M costs leads to total netback analysis. Thermal efficiency of both the generation costs of USI6.0/kWh. Netting oil and open cycle gas-fired plant are similar those generation costs back to a typical OCGT whereas itis higherat combined cycle gas plant. plant and deducting US$0.8/MMBTU gas Per unit capital and O&M costs of OCGT and transportation costs and plant conversion costs CCGT plants tend to be lower.52Since it is a of US$0.2/MMBTUt givesan economic netback new plant, no conversion costs are applied. of US$3.9/MMBTU.54 Assuming an average gas transportation tariff of US$0.8/MMBTUt the economic netback is This indicative analysis demonstrates that for around US$5.5/MMBTU (US$6.3 minus existing and new plants, even at very US$0.8) for the OCGT plant and US$9.4/ conservative oil priceforecasts of US$30/bbl, a MMBTU (US$10.2-US$0.8) for a CCGT plant potential generator would be willing to pay up at the Red Sea coast, possibly Hudaidah. to US$5.5/MMBTU for natural gas atMaber and up to US$3.9/MMBTU at Hizyaz. In case, the As a consequence, the maximum price GOY Maber plant is movedto the coast, for example, can charge for its gas to be sold to the Marber Hodaidah, and a combined cycle gas plant is plant (orthe WTP of the OCGT plant operator) being constructed, a potential investorwould be is up to US$5.5/MMBTU. Due to the efficiency willing to pay upto US$9.4/MMBTU for natural gains, the maximum price a CCGT plant gas. These economicnetbacksare much higher operator on the coast would pay for the gas than the opportunity costs of US$2.6/MMBTU is US$9.4/MMBTU. of exporting the remaining gas reserves as set out in Table 2.5. This demonstratesthat unlessthere aretechnical constraintsor relativelyhigher costs of bringing The Marib Plantand Gas Pipeline the generated electricity from the coast to the load centers, it may be preferable to construct GOYhas commissionedthe construction of the new power generationcapacity, for example, in Marib OCGT plant in two phases. Phase I, Hudaidah, to capitalize on the efficiency gains currently under construction, has an installed of a CCGT plant.53 generation capacity of 360 MW and is jointly financed bythe Arab Fund, the Saudi Fund and Table 3.4 sets out an economic netback analysis GOY.GOYhas further secured financing for the for the conversionof the existing 98 MW Hizyaz extension of the Marib plant by adding an units near Sana'a which currently runs on HFO additional 400 MW of generation capacity. It is to an OCGT plant. For an existing plant, understood that the plant extension will be 52Unitcosts for OCGT plants tend to be lower than for CCGT plants and are around US$SOO/kW. However, for thepurpose of the calculationsin this report, the authors adopted the costs figures provided by PEC. CCGT and desalinotionplants tend to go side by side, and there are some technical efficiency gains which can be achieved between these two plants. Typically, desalinotion plants use the waste heat from CCGT plant for the desalination process and provide raw water for make-up to the steam cycle. "Assuming Hizyaz pays opportunity costs of US$2.6/MMBTU for the Marib gas, the break-evenpoint for making the conversion economically viable will require average long-term crude oil price of at least US$8/bbl. REPUBLICOF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Table 3.4: Hizyaz 1 & 2 and Economic Netback for Natural Gas Plant Characteristics Hizyaz Oil-fired Plant Hizyaz OCGT Generating Capacity (MW) 98 98 Load Factor 75% 75% Output (GWh/y) 645 645 Heat Rate (BTU/kWh)* 10,035 10,035 Thermal Efficiency 34% 34% Capital Cost (US$/kW) Plant Cost (US$ MM) 78 68 Life of the Plant (years) 30 30 Per Unit Capital Cost (USC/kWh) 1.4 .0.7 Fuel Price (US$/MMBTU) 5.3 4.9 Per Unit Fuel Price (USCIkWh) 5.3 4.9 Other O&M Costs (USC/kWh) 0.7 0.4 Generation Costs (USC/kWh) 6.0 6.0 PipelineTransportation Costs (US$/MMBTU) 0.8 Economic Netback at Gas Plant (US$/MMBTU) 4.1 Note: "3412BJU/EfficiencyRate. Source: The World Bank calculationsbased on dato provided by PEC. financed by several institutions, including the It is understood that a price in the range of Arab Fund, Saudi and Oman funds. USC50-80/MMBTU is being negotiated. PEC finances, constructs and owns the Table 3.5 gives an indication of potential 3 km gas pipeline between the Safir gas field generation costs of the Marib OCGT plants andthe Marib plants. This isa dedicatedpipeline which could be as low as USC1.8/kWh. and will not be connected with the NGP that is Transmitting the generated electricity from the envisaged to run from the gas fields at Safir to Marib plant to the market will require new and Maber, Sanata and along the coast south upgraded power T&D infrastructurewhich has of Aden. to be included in the supplied electricity costs GOY, as the owner of all proven gas reservesin from that plant at the customer end. Yemen, has allocated proven gas reserves to Consequently, the USC1.8/kWh does not reflect the plant from the Marib field (Block 18) and is the economic cost of supplying the generated currentlynegotiatinga long-term GSAwith PEC. electricity at the customer end. A FRAMEWORK FOR DEVELOPINGTHE DOMESTICGAS MARKET Table 3.5: Power GenerationCosts of New Marib OCGT Plants Plant Characteristics Marib OCGT Plant I Generating Capacity (MW) 360 Load Factor 80% Output (GWh/y) 2,523 Heat Rate (BTU/kWh) 10,004 Thermal Efficiency 34% Capital Cost (US$/kW) 700 Plant Cost (US$ MM) 252 Life of the Plant (years) Per Unit Capital Cost (USQ/kWh) 0.7 Fuel Price (US$/MMBTU) 0.5 Per Unit Fuel Price (USQ/kWh) 0.5 Other O&M Costs (USQ/kWh) 0.6 Generation Costs (USC/kWh) 1.8 Note: The World Bank calculationsbased on data provided by PEC. The NationalGas Pipeline (NGP) phases and the existing and new power generation plants along the pipeline routing. The Two-phase Approach Phase Iof the NGP is envisagedto run from the Several studies have been carried out to date Safer-operated gas fields in Safir, following the on the economic and financial viability of Ras Isa oil pipeline to the cross-section point on domestic gas pipeline development in Yemen. the highway between Sana'a and Maber. In the most recent study by Ramboll, the This Phase also includes proposed spur lines construction of a national high-pressure northwards to Sana'a and the cement plant in transmission pipeline,the NGP,from the gasfield Amran, and south, the planned power plants at at Safir toward markets in Maber and in and Maber.The pipelinethen further runs in parallel around Sanata/Amran and eventually south to with the oil pipeline until Bajil and finally Aden along the costal areas via Hudaidah to Hudaidah. was proposed. Phase II is envisaged to follow the Red Sea Based on the gradual development of gas coastal line from Hudaidah passing Al-Mokha demand in various parts of Yemen, the (withspur linestoTaiu andAl-Mokha)andfrom construction of the NGP was proposed in two here along the Gulf of Aden to Little Aden phases. Figure 3.2 sets out schematicallythe two (Aden Refinery)and Aden city. REPUBLIC OFYEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Figure 3.2: Proposed PipelineRouting and Gas-fired Power Plants ., I e SAUDI ARALIA PFWBUE W YESEN PROPOSB)BPEIIFJE BQUJING AND GAS PkaRLB, POWEW PLANTS Source:The World Bonk based on informationprovided by Romboll, June 2005, and PEC,September 2006. PotentialGas Demandof However, PEC should reassess shifting the Power Generation proposed Maber plant(s)to the Red Sea coast. This would provide access to cooling water and While some of existing and new industries in would enable the construction of a CCGT plant enmay develop inthe nearfuture as major (possibly in combination with a desalination gas customers, the economic ~ ~ financial n d plant). This would substantially reduce power viability of the NGP will depend on the power generation costs and improve the economics of sector as an anchor customer. the NGP through lower gas volume uptake per kwh of electricity generated and would Of the existing power plants that could be require a smaller sizing of the NGP with converted, only Ras Katnib (located near subsequent lower construction costs and gas Hudaidah) and Hizyaz-1 and 2 (located near transportation tariffs. Sana'a) fall in Phase I. The construction of the Maber power plant(s) is important for the One GWof electricitygeneratedfrom an OCGT economics of the pipeline because there is no plant requires 1.6 Bcm of naturalgas, assuming other sizable customer onthe pipeline routethat a 35 percent efficiencyfactor. Incontrast, 1 GW may justify the construction of the 300-km of electricity generatedfrom a CCGT plant only Phase I of the NGF? requires 1 Bcm of gas, assuming a 55 percent A FRAMEWORKFOR DEVELOPINGTHE DOMESTIC GAS MARKET efficiency factor. The exact gas volumes will annually or about 17 Bcrn (0.6 Tcf) over a further depend on the age of the plant, 30-year life period. geographic location and the exact technology used. Table 3.6 sets out potential annual gas In total, 1.8 GW of gas-fired generation demandof the powersector in bothphases using capacity from existing and new plants would exclusively OCGT technology. require 2.9 Bcm of natural gas annually, or Table 3.6: PotentialAnnual Gas Demand of Power Plants Using OCGT Technology Electricity(MW) Natural Gas Consumption (Mcm*) Phase I Hizyaz I & II 96 154 Ras Kadnib 150 240 Maber I & II 1,200 1,920 Total 1,446 2,314 Phase II Al-Mokha 160 256 Al-Hiswa 125 200 Al-Mansoura 64 102 Total 349 558 Marib I & II 760 1,216 Sources: PECandthe World Bankcalculations. "Million CubicMeters. The conversion of existing plants in Phase I in 87 Bcrn (or 3.1 Tcf) over a 30-year life period Hizyaz and Ras Kadnib would require 400 of plants from the NGP. This is based on the Mcm of gas annually. The proposed 1.2 GW power sector using only OCGT plants. capacity of Maber I & II plants would require (As discussed above, by potentially using 1.9 Bcrn of natural gas annually and would CCGT technology for 1.2 GW of generation be by far the largest customer on the NGP. If capacity, this would reduce total annual gas technically feasible, moving the proposed consumption to 2.1 Bcm, or 63 Bcrn - or 2.2 1,200 MW OCGT plant from Maber to the Tcf - over a 30-year life period.) Red Sea coast, and using CCGT technology, annual gas consumption of the plant could The cement sector is the second largest be reduced from 1.9 Bcrn to 1.2 Bcm. existing gas customer, and it was estimated that the existing cement plants in Amran and The conversion of the existing power plants Bajil (Hudaidah) could use about 80 Mcm in Phase II, namely Al-Mokha, Al-Hiswa and of natural gas annually or 2.4 Bcrn (0.08 Tcf) Al-Mansoura, would require 560 Mcm assuming a 30-year life period of the plants. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK Table 3.7: The Economic Feasibilityof the National Gas Pipeline Discount Rate: 12% Internal Rate of Net Present Unit Transportation Oil Price: US$25/bbl Return (IRR) Value (NPV) Costs in US$ Million (US$/MMBTU) Full System (PhaseI & 11) 26 Phase II (Hudaidah to Aden) 15 81 1.34 Source: Ramboll,June 2006. Al-Mokha, Al-Hiswa and Al-Mansoura (both Although pipeline material costs are constantly located in Aden) fall into Phase II of the gas changing, those estimates provide a good conversion plan. indication of the overall investment requirements. Itisfurther understoodthat under The Marib plant is not directlysuppliedfrom the the YLNG deal, the YLNG partnership will NGe but from a dedicated pipeline, the Marib provide up to US$110 million toward the Gas Pipeline. Marib I requires about 17 Bcrn construction of the NGF! That funding will not (0.6 Tcf) over a 30-year life period and Marib 11, be sufficient to fully construct Phase 1 and/or if constructed, an additional 19 Bcrn (0.7 Tcf). Phase II of the pipeline, and substantial In total, Marib I and II would require 36 Bcrn additional resourceswill be required. (1.3 Tcf) of natural gas over a 30-year period from the Marib Gas Pipeline. The economicfeasibilityof the NGP is set out in Table 3.7. Using gas demand forecasts until It is understood that GOY has allocated 2025, a discount rate of 12 percent and an oil 5.2 Tcf (or 150 Bcm)of existinggas reservesfor price of US$25/bbl, Ramboll calculated an the domestic market. The converted and new Internal Rateof Return (IRR) of 26 percentif both power plants on the Marib Gas Pipeline and Phase Iand Phase IIof the NGP are constructed, the NGPwould requireabout 4.5 Tcf (123 Bcm) deriving an average gas transportation tariff of of natural gas over a 30-year periodss US$0.83/MMBTU. The analysisfurther highlights (or 3.6 Tcf - 99 Bcm) if CCGT technology is that with an IRRof 15 percent, the economics of used for 1.2 GW of new generation capacity). Phase II is less favorable than Phase This would leave 0.7 Tcf (37Bcm)of provengas reserves for the development of the nonpower It is important to point out that the consultant's sector with natural gas. In case CCGT calculations do not include the YLNG technology is used, the remaining gas reserves contribution which would reduce the capital are 1.6 Tcf or 45 Bcm, respectively. expenditure requirements for the NGP (that is, US$110 million) which would further The Economicsof the National substantially reducethe unit gas transportation Gas Pipeline costs of US$0.83/MMBTU. The total construction costs of the NGP were Further, if CCGT technology is used for new estimated at US850 million in August 2005.56 power generation, the associated lowervolume 55 7 Bcrn of natural gas is about 6.5 million bbl[s] of crude oil. ( 7 bbl of oil equivalent is 5,487 Cubic Feet [cf] or 757 Cubic Meter [m3]of natural gas). 56Ramboll, Natural Gas UtilizationStudy, Pricing and Economic Viability, June 2005. " Ibid., 27. A FRAMEWORK FOR DEVELOPINGTHE DOMESTIC GAS MARKET uptake may enable a reduction in the sizing of volume uptake, the power sector still has the pipeline that could further reduce substantial economicandfinancial incentivesfor construction costs and transportation tariffs. switching from HFO and for building new gas-fired power plants. From the data and information available, one can calculate the maximum gas transportation It further indicates that GOY has substantial tariff that an existing power plant planning to leeway to create financial incentives for switch to natural gas would be willing to pay potential private investors to construct and assuming that the plant operator has to pay operate the NGP by offering attractive economic costs for the gas. transportation tariff arrangements. Thisanalysisissetout inTable 3.8. The economic Establishment of an Attractive Gas netback of an existing HFO plant switching Industry Structure to natural gas was calculated in Table 2.7 at The designof the future gas marketstructure and US$4.9/MMBTU1 minus the plant conversion clarification on "who" is allowed to do "whatr1in costs of US$ 0.2/MMBTU1 minus the the Yemeni downstream gas market is of key opportunity cost of the gas at the wellhead of . ~mportanceto attract investors. In principle, the US$2.6/MMBTU. gas sector should be organized to allow for Table 3.8: Maximum Gas Transportation multiple buyers and sellers to enter the market, Tariff on NationalGas Pipeline promote the growth of the power, industrial, commercial and residentialsectors, and provide aneconomicand reliablesourceof energyto meet Economic netback of existing future demand in Yemen. At the same time, the HFO plant 4.9 market structure has to be attractive to private investorsto develop the NGP and any additional Natural gas conversion cost 0.2 T&D network in the future.58 Economic cost of gas (well head) 2.6 The Current Natural Gas Maximum Gas Transportation Tariff 2.1 Industry Structure Source: The WorldBonkcolculotions. To date, the government undertakes various Hence, an existing plant iswilling to pay, on an roles in the gas sector, many of which conflict average, up to US$2.1/MMBTU for gas with principlesnecessaryto assure privatesector transportationtariffs onthe NGF!This compares participation in the market. favorablywiththe actual unittransportationtariff of US$0.83/MMBTU calculatedbythe consultant GOY,through itsfully-owned subsidiarySafer, is for constructingthe NGF! the owner of the Marib gas reserves at Block 18 and the sole monopoly gas supplier in the These calculations are indicative but Yemeni market. The MOM is in the process of demonstrate that even if the gas is priced at signing a long-term GSA to provide the Marib opportunity costs and unit gas transportation power plant, operated bythe State-owned PEC, costsare muchhigherthan US$0.8/MMBTU due with natural gas. The 3-km Marib Gas Pipeline to higher pipeline capital costs and lower gas between the field at Safir and the plant will be Gorcio, R., Guidelines for Developingthe DomesticGas Marketin Yemen, November2006. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK financed, constructed and operated by PEC. are allowed to use the gas for reinjection The current State-owned gas industry structure to increase reservoir pressure and/or is schematically set out in Figure 3.3. flare associated gas for operational purposes and or use gas at the platform to GOY has further indicated the desire to be machinery. involved in the downstream gas sector and has also expressedan interestthat the privatesector In theory, operators also have the opportunity leadsthe developmentof greenfieldgas pipeline to market associated and nonassociated gas development, in particular, the construction of domestically or internationally. In practice, this the NGF! requires that an operator sign a GSA(s)with an At this stage, the terms of private sector end user(s)within six monthsof finding the gas. participation remains unclear. GOYwill have to The PSA further specifies that if an operator set out a clear gas market framework that cannot secure such an agreement within that specifies "who" is allowed to carry out "what" time period, the operator's right to market the Figure 3.3: The Current Gas IndustryStructure Gas Supplier Marib Marib Plant Safer Gas Pipeline PEC PEC in the gas chain with defined roles and gas will cease and will be fully transferred to responsibilities of the various players. That the government. framework includes a clear vision on the potential role of the public and privatesector in In addition to the GSA, operatorswill also have the gas market. The nextsection discussesareas to sign a GDA with the MOM. If associated gas that GOY has to address while developing a isfound, itisspecifiedinthe PSAthatYGC would framework for an efficient development of the own not less than 60 percent of the marketed domestic marketand privatesector participation gas and its share and costs of marketing that in the construction of the NGF! gas would be fully carried out by the operator. For nonassociated gas, there is no prescribed The Gas Market Players minimum share specificationin the PSAand the operator andthe MOM maynegotiatethatshare The domestic gas chain in Yemen consists of under the GDA. four key activities, namely: (i)domestic gas production; (ii)gas T&D; (iii) gas shipping and Oil and gas companies that find associated or supply; and (iv)gas consumption. The rolesand nonassociated gas fields in the future face large responsibility of each participant in these challenges to sign GSA(s) and a GDA within the activities will have to be addressed when time period specified. From an organizational or designing an efficient gas market structure gas marketstructureperspective,this leadsto GOY for Yemen. monopolizingthe supply of gasinto the domestic Gas Production market and preventsthe emergenceof multiple gas producers/suppliers. The emergence of Under the current Model PSAs 2005, GOYis multiple gas supplies is important to creating the sole owner of all gas in Yemen. Operators an efficient downstream gas market. A FRAMEWORKFOR DEVELOPINGTHE DOMESTIC GAS MARKET There is also an urgent need to support of the system, for compression, for system integration between natural gas and power balancing in case of nomination overruns). production in Yemen to encourage investors in gas production. Yemen needs substantial new In a merchantpipeline, the pipeline owner and generation capacityto meet its growing energy operator also carries out the commercial demand and a policy that supports private functions of a shipper and/or supplier, namely investment in power generation by lPPs may the buying and selling of the commodity natural further providecomfortto oil and gascompanies gas and arranging for transportation on itsown to increase E&P activities. (and potential other) pipeline network. Inthe future, operators maydiscover additional Merchantpipelinesarecommonindevelopedand associated and nonassociatedgas fields along less developed markets. However, to avoid or near the proposed NGP which they may conflicts of interests, in competitive gas markets wish to sell domestically. Hence, upstream there is a clear separation(or unbundling)of the contractual arrangements should be merchant and transportation function of gas readdressed to allow for the emergence of transmission ~ipelines.~'Such a separation will multiple gas producers/suppliers in the future. ensurethatcosts cannotbeshiftedbythe pipeline from the commercialactivityof buyingandselling Gas Transmissions9 of natural gastothe regulatedtransport business. There are basically two options for organizing For the NGP (and any future gas transmission gas transmission in a market, namely, as pipelinedevelopment), a potentialprivateinvestor "merchant" or "nonmerchant" pipelines. shouldbeallowedto operatea merchantpipeline to create incentives for its participation in the In the case of a nonmerchant pipeline, market. Inaddition, the operator of the NGPmay transmission companies are only allowed to also be allowedto carryout otherfunctions inthe carry out the function of transporting third party market and no cross-ownership restriction may gasfrom the injectionpoint intothe transmission apply. Separate GSA and GTC contracts and network to the city gates (wherethe gas enters regulatory accounts should be put in place to the distributionsystem).60Long-termGTC(s)are ensure transparency and avoid cost-shifting signed between the pipeline company and the between regulated and unregulated businesses. agents who buy and sell the gas. Those agents can be gas producers, shippers, suppliers or In addition, cross-ownership should only be large customers. Transmission companies will allowed ifthe regulatoryframeworkadopted will only be able to buy and sell gas for operational ensure the avoidance of monopoly power purposes(forexample, to maintainthe line-pack against third parties. 59Foundation Contracts and Greenfield Gas Pipeline Developments: Experience from the United States and Other Jurisdictions, A Final Report to the Australian Consumer and Competition Commission (ACCC), Gerner, F., Richards, C., Houston G., N E W March 2002. In Great Britain, Notional Grid owns and operates the national transmissionsystem, but is not licensed to act as a shipper or supplier of natural gas. Hence, National Grid does not have any incentive to discriminate among shippers and suppliers who sell gas to final customers but focuses on maximizing its revenues by increasing network utilization. 61In the United States, for example, the Federal Energy Regulatory commission (FERC)requiresseparate contracts for the purchase of gas and the transportation of gas for interstate pipelines under Order No. 636. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Gas Distribution to offer a "bundled" service to customers. Further, no cross-ownership restrictions may The economics of gas distribution in Yemen is apply and a potential gas distributor may also yet to be established. Once the NGP is be allowed to carry out other activities in the constructed, it may be viable to build some gas market. Cross-ownership should only be distribution networkto convertcommercialload, allowed ifthe regulatoryframework adoptedwill especiallyfrom more expensivealternativefuels ensure the avoidance of monopoly power such as fuel oil and, in particular, LPG. against third parties. Separate regulatory Considering that there is no heating load, the accounts for pipeline distribution and supply economic and financial viability of connecting activities should be established to allow residential households may be challenging. regulatory oversight, prevent cost-shifting and However, this will have to be assessed by the increasetransparency in the market. marketand an attractiveand efficientgas market framework should allow agents to enter the Gas Shipping and Supply market and develop, own and operate gas distribution network. A gas shipper is an individual or organization who arranges with the gas transporter for the In most markets around the world, gas conveyance of gas on the transporter's pipeline distribution companies act as both pipeline network. Gas supplymeans activities relating to owners/operators and gas suppliers to final the purchase of gas from a producer, gas customers. There are economics of scale62and merchant pipeline or shipper and sale of that economics of scope63betweenthe pipeline and gas to end users.65 supply functions on the distribution network, includingmeteringand billing, and international Inmore developed and competitivegas markets, experience hasdemonstratedthat greenfield gas gas shippers play an important role as distribution pipeline developers tend to prefer aggregator of supply and demand, buying and to carry out both functions simultane~usly.~~selling bulk gas and arranging for shipping the Governments tend to provide geographic gas on the network.66Gas shippers can also exclusivityto greenfield distribution companies carryout otherfunctionsinthe market, including for the pipeline and supply function and, thus, acting as suppliers. Large customers and encourage investment. distribution companies often act as shippers in their own right in developed gas markets. No separate commodity and transportation contracts should be required on the distribution At the initial stage, the MOM will be the sole network and the distributor should be allowed supplier and shipper of natural gas. As the 62Thesituation that ariseswhen the cost of performing multiple business functions simultaneously is more efficient than performing each business function independently. 63 Reduction in the average cost of a product in the long term, resulting from an expanded level of output. One reason is that overheads and other fixed costs can be spread over more units of output. Turkey's Experience with Greenfield Gas Distribution Development since 2003, The World Bonk, January 2007; Greenfield Gas Distribution, Cross-Country Experience, The World Bank, January 2007. In principle, a supplier should be able to buy natural gos directly from a shipper. A supplier could also directly buy gas from a producer, arrange for shipment through the pipeline network ond sell it tofinal customers. Under such a scenario, o supplier would, by definition, also be o shipper. 66 In the British gas market, there are currently about 90 licensed gas shippers including upstream operators, foreign utilities, banks, power generators and gas suppliers. A FRAMEWORK FOR DEVELOPINGTHE DOMESTIC GAS MARKET market develops, and if further gas is being distributionbusinessesandthepotentiallycompetitive found, other gas suppliers should beallowedto production/supply and shipping businesses. sell gas directly to large customers and utilize the gas infrastructuresystem.67 A Future Gas Market Structure Considering the few players in the market in It is envisagedthat inthe future gas market, the Yemen, and the small size of the future gas following activitiesand agentsshould beallowed market, it is unlikely that sole gas shippers will to emerge, including evolveinthe nearfuture. The marketframework Multiple gas producers who can sell their for Yemen should, however, beflexible enough gas directly into the downstream market to allowfor multiplegas shippers and suppliers to customers; to develop. A gas supplier and shipper should also beallowed, in principle, to owntransmission Merchantgastransmissioncompany(ies)that and/or distribution network. However, there has own, operateand maintaintheir gas network; to be a separation between the regulated and unregulatedactivities. Integrated gas distribution and supply company(ies)that havegeographicexclusivity; Gas Customer Independent shipper(s)and supplier(s)that PECwill bethe anchor gas customer inYemen. areeligibleto supplycustomersandthat have There is potential for other State-owned and TPA to the network; and privatecompanies to consume gas in the near future, including the cement sector. Large Large industrial customers who have the customersshould be able to negotiateand sign freedom to choose their own gas supplier. long-term GSA(s)and GTC(s)with the pipeline ownerand operator and gassuppliers/shippers. Not all of those functions will emerge in the short- to medium-term. However, the dynamics Once the gas distribution network has been of gas markets change rapidly, and even for a developed, commercial and residential small market likeYemen, a small gas finding customers could be supplied by distribution near existing gas infrastructure can change companies, and with whom they would get into the dynamics of the market. An efficient gas a contractualarrangement. market structure must ensure that it is flexible for new market entrants and, atthesametime, In summary, to incentivize private participation protectcustomersfrom potentialmarketabuses in the development of the NGP and the of participants. Figure3.4 sets outschematically Yemeni gas market, there should not be any an attractive future gas market structure cross-ownership restrictions on private for Yemen. companiesto operatein any segmentof the gas chain. However,toensuretransparenqandprotect To date, the gas market in Yemen is dominated customers, there must be accountingseparation by the public sector. GOYhas indicated that it for the natural monopoly transmission and/or aims to get the private participati~n~~in the 67In Great Britain, there are about 30 domestic gas suppliers (that is, for small residential and commercial customers) and about 60 business gas suppliers. Most shippers also operate in the gas supply market. A full list of gas suppliers can be found on www.ukpower.co.uk/suppliers. 68Under private participation, the private company must assurneoperating risk during the operational period or assurne development ond operating risk during the contract period. In addition, the operator must consist of one or more corporate entities with significant private equity participation that are separate from any government agency. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Figure3.4: A FutureGasMarket Structure for Yemen - Domestic Gas Producer --) -- Shipper(s)/Supplier(s) *- Domestic Gas Producer Industry(ies) - - Transmission Company(ies) Domestic Gas Producer i Distribution Companies I Residential Domestic Gas Producer - ---) Physical Gas Flows Contractual Arrangements downstream gas sector and, in particular, in the transmissionnetworksin developing countries. constructionof the NGFThisreportrecommends Table 3.9 provides an indication of investment that the private sector should be allowed to volumes and regionalfocus of privateinvestment participate in all parts of the gas chain. in gastransmissioninthe period 1990to 2005. Most private investment projects were carried Private Participation in the Development out in Latin America. In there were two of the National Gas Pipeline69 major gas transmission developments with a However, the most immediate area where Goy total investmentvolume of about US$3 billion. seeks private investment is for the construction of the NGPGastransportation constructionand I" principle, there are four types of private operation new activities yemenand are in investmentin gas transportation infrastructure, internationalcompaniescan providesubstantial including (i) divestures; (ii) concessions; expertisearea on boththecommercial inthis (iii)operation and managementcontracts; and bv) greenfield and operationalaspects of runningthe business. prOiects. International experience shows that private In a divestiture, a private consortium buys an participants are willing to invest in gas equity stake in a SOE. The private entity stake Table 3.9: NaturalGasTransmissionPipelinelnvestmentby Region 1990-2005 East Asia Europe and Latin Middle East South Sub-Saharan Total and Pacific Central Asia America and North Asia Africa Investment and Africa Caribbean US$ million 3,962 3,666 1 1,407 2,927 571 354 22,887 Project Number 7 5 24 2 1 2 41 Source: Private Participation in lnfrastructure(PPI) Project Database, PPIAF. 69Private Participation in Infrastructure (PPI) Project Database, Public-Private lnfrastructure Advisory Facility (PPIAF), The World Bank, http://ppi.worldbank.org/index.aspx. 44 A FRAMEWORK FOR DEVELOPINGTHE DOMESTIC GAS MARKET may or may not imply private management. contractsforbulksupplyfacilitiesor minimum Under a concession, a private entity takes over traffic revenue guarantees; the management of a SOE for a given period duringwhich itmayassumesignificantinvestment Build, Own, Transfer, or Build, Own, risk. In an operationsand managementcontract Operate, Transfer(BOTor BOOT):A private (whichincludesmanagementcontractand leases), sponsor builds a new facility at its own risk, the privateentitytakes over the management of owns and operates the facility at its own risk, the SOE for a given period of time. It may also then transfers ownership of the facility to the includesignificantinvestmentbythe privateentity government at the end of the concession under the contractual arrangements. period. The government usually provides revenue guarantees through long-term For Yemen, the greenfield proiect-type of take-or-paycontractsfor bulksupplyfacilities investmentisthe most relevant. Undergreenfield, or minimum traffic revenue guarantees; a private entity or a public-privateJoint Venture (JV)/partnershipbuild and operatea newfacility. Build, Own, and Operate (BOO): A Table 3.10 provides an overview of the various private sponsor builds a new facility at types of private participation in developing its own risk, then owns and operates the countries. Itindicatesthat, over a 15-yearperiod, facilityat itsown risk. The governmentusually private participation in greenfield transmission provides revenue guarantees through pipeline developmentwas widespread whereas long-term take-or-pay contracts for management/lease contracts and concession bulk supply facilities or minimum traffic did not really play any major role. revenue guarantees. Table 3.10: Natural Gas Transmission Pipeline by Investment-type 1990-2005 Concession Divesture Greenfield Management/Lease Total Contract US$ million 600 6,665 15,62 1 0 22,886 Project Number 1 7 33 0 41 Source:Private Participation in Infrastructure (PPI)Project Database, PPIAF. There are various options for designing a Merchant: A private sponsor builds a new relevant private sector-led contracts for facility in a liberalized market in which the greenfield projects including: governmentprovidesno revenue guarantees. The privatedeveloper assumesconstruction, Build, Lease and Own (~10):A private operating and market risk for the project. SPonsor builds a new facility largely at its The boundaries bekeen these categories are Own transfers ownership the not always clear, and some proiects have government, leases the facility from the features of more than one category. Getting government ~ ~ operates it at its own risk, n d further clarification and consensus on the most then receives full ownership of the facility at appropriate form of private participation in the the end of the concession period. The NGP is the most important next step for GOYto government usually provides revenue takeintheprocess'ofdevelopingthedomestic guarantees through long-term take-or-pay gas market. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Key Contract/Market Design Issues70 Anti-competitive conduct occurs when the monopoly part of the vertically integrated To attract private participation in the financing business (that is, T&D) behaves in a way that of the NGP and ensure the development of an givesitscompetitivebusinessunits (thatis supply efficient gas market that will protect customers and shipping and production) an advantage from anticompetitive behavior, a set of broad over its competitors. Separation or unbundling principles should be adopted in the design of seeks to prevent this type of anti-competitive the market and the contract(s), including: behavior. This is achieved through the isolation of the monopoly elements of a vertically Unbundling of competitive from monopoly integrated business from the competitive activities; elements, thereby reducing both incentives and opportunities for anticompetitive conduct. Regulatoryaccounts; While companies should be allowed to act in Separate contractual arrangements; various parts of the gas chain in Yemen, it is Third PartyAccess; imperative that there is a clear separation of their activities. In principle, there are four types Open season; of separation or unbundling methods: including (i)financial; (ii)physical; (iii)legal; and Pipeline capacity; (iv) full ownership. Gas pricing structure; Financialseparationhaseffectsatthe accounting level and requires separate accounts for the Transportation tariffs; and monopoly and competitive activities of the gas chain. The major objective of financial Other relevant concepts and provisions. separation is to enable the company and the Each of these will be discussed below in regulator to identify the costs of each business more detail. activity and report these costs in a transparent way to avoid "cost-shifting" among business Unbundlingof Competitivefrom activities in a more competitive market.'' MonopolyActivities Physicalseparation is a more stringent form of In order to encourage private participation, an unbundling. In addition to providing separate industry structure that allows gas producers, accounts, physical separation requires having shippers and suppliers to compete on a level separateofficesin separate buildings, or, ifwithin playing field with each other has to be allowed the same building, by locating offices on to develop. Hence, introduction of effective separate floors and providing restricted access market structures that prevent anti-competitive of staff and restricting information-sharing. behavior should be developed. A business unit within a utility that is physically The analysis presented in this section has been largely drawn from Gerner, F., Richards, C., Houston G., Foundation Contracts and Greenfield Gas Pipeline Developments: Experience from the United States ond Other Jurisdictions:A Report to theAustralian Consumer and Competition Commission (ACCC), NERA, March 2002. "Cost-shiftingoccurswhereautilityattributesthecostofprovidingitsunregulatedservicetoaregulatedservice.Theeffectisthat the utility is able to provide its unregulated service more cheaply, and customersof the regulated service must bear higher costs. In addition, the utility gains an unfair advantage over its competitors in the unregulated part of its business. A FRAMEWORK FOR DEVELOPINGTHE DOMESTIC GAS MARKFT separatedis likelyto haveseparatemanagement Publiclylistedcompaniesuse statutoryaccounts for that unit. as the basis for preparing annual financial statements. In essence, statutory accounts are Legal separation incorporates all the for tax purposes whereas financial statements characteristics of financial and physical will be based on international accounting separation. However, it is a stricter version of standards to make them comparable for physical separation requiring the formation investors and creditor^.'^ of different, independent business activities. The advantage of this form of separation is Statutory accounts and financial statements do that it facilitates a clear audit trail, allows for not provide sufficient information necessary greater transparency and promotes for regulating monopoly businesses. Therefore, independent business activities of the legally regulatedcompaniesshould prepareand submit separated entity.72 regulatory accounts. The main focus of regulatory accounts is to provide more detailed The most stringent form of unbundling involves and focused information about regulated full ownership divesture of a network business businesses for use by the regulatory agency. activity implying a new ownership arrangement independent of competitivegas activities. Most jurisdictions around the world require companiesto prepareregulatoryaccounts as part Internationalexperience showsthateffectiveand of their licensecondition. Itis recommendedthat meaningful vertical separation is an important GOYdevelops regulatory accountingguidelines prerequisitefor gas marketdevelopment. Inthe that provide guidance in the preparation of case of Yemen and for the construction of the regulatory accounts for companies. NGP, the minimum of financial separation is recommended. Separationof ContractualArrangements Regulatory Accounts Vertical unbundling or separation of monopoly from competitive gas activities also requires Regulation of gas markets require information contractual separation of the "commodity" gas and financial data from companies to be able from the "activity" of transporting or conveying to make coherent and credible regulatory of gas on the pipeline network. decisions. Companies have incentives not to conceal relevant informationthat is required to Commodity contracts are defined as contracts regulatethe business. This problemis commonly between parties for the purchase and sale of referredto as informationasymmetrythat arises the commodity natural gas. Transportation when companies have important information contracts are contracts for the conveyance of that the regulator does not have. In principle, gas on a pipeline network. Without separate accounts can be divided into: (i) statutory; and contractual arrangements, it is not possible to (ii) regulatory accounts. effectively unbundle the potentially competitive "One could also have a legal separation without a physical separation. Two fully separate companies could operate out of the same physical location and with common economicgoals. 73The accounting process encompasses three principal financial statements: The balance sheet shows assets, liabilities and stockholder's equity. The income statement reflects revenues, expenses, and gains and losses. Thestatement of cash flow includes operating,investing and financing inflows and outflows. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK from the natural monopoly element of the There are mainly two ways of arranging access gas ha in.'^ to transportation network namely, Negotiated Third Party Access (NTPA) and Regulated Third ForYemen, it is recommendedthat for the NGP, Party Access (RTPA). Figure 3.5 sets out those separate contracts for transportation - that is options graphically. GTC(s) - and for the commodity gas - that is GSA(s) - are being offered. This will not only In case of NTPA, the owner and operator of the allow customers to compare gas and transportation network "negotiates" terms and transportation tariffs, but will also enable new conditions with a potential shipper(s) and/or entrants (such as gas producers and suppliers) supplier(s) to convey gas on its transportation to arrange for separateGTC(s)to sell gas directly network. If the transporter is a fully unbundled to customers. companywhose onlyresponsibilityistotransport gas on its network (like National Grid in the OpenAccesstothe NationalGas Pipeline United Kingdom), it has an incentiveto increase usageof its pipeline bythird partiesto maximize Open, nondiscriminatory access to the its revenues. Being a sole transport company, transmission (and distribution) network is a the transporter does not have any conflict of prerequisite for the development of a dynamic interest, and it is likelythat negotiation of access downstream gas sector. This is of particular can lead to optimal outcomes. This can allow importancein marketswhere transport is notfully for negotiatedprices and discountson standard divested from other activities. Openness ensures pipelinetariffsthat can maximizethe usageand that the transportation network is open the economic benefits from the pipeline. to other parties than the transporter. Nondiscriminationis an obligation on part of the The situation is different in case of gas markets transporternotto favor any partyfor the usageof that continue to be vertically integrated (or not transportation network. However, that does not fully unbundled). In such market environments, implythata transporter mustofferthe sameterms where the gas transporter operates a merchant and conditionsto shippers for usingthe pipeline. pipeline and is also involved in upstream Figure 3.5: Optionsfor Accessing the National Gas Pipeline I I National Gas Pipeline I I Negotiated Third Party Regulated Third Party Access (NTPA) Access (RTPA) 74Prior to introducingcompetition, verticallyintegrated gas companiesaroundtheworld had a tendencyto sell natural gas to final customers at "bundled" prices, which incorporate the commodity gas and the transportotion of gas into a single toriff. As o consequence, customers were unable to distinguish between the cost of the commodity gas and the cost of the transportation service.Separationthrough contractualarrangementsnot only allowscustomerstoget a better understandingof the costsinvolved in buying and transporting gas, but also forces network owners to operate the transportationbusiness as a separate cost center. A FRAMEWORK FOR DEVELOPINGTHE DOMESTICGAS MARKET purchaseof gas and supplyactivities, NTPAdoes the Yemeni gas market. It will also depend on not leadto efficientoutcomes. The main reasons how transportation tariffs are being structured, beingthatthetransporterhasa conflictof interest but generally a system basedon clearlydefined in allowing accessto its pipelineto third parties, terms and conditions of TPA to the pipeline is as that would allow other partiesto compete in recommended, and that can beachieved under the supply of gas to final customers. both, a RTPA and NTPA regime. InNorthAmerica, the useof RTPA iswidespread. The Open Season Process While there is scope for tariffs to be negotiated, shippers retaina rightto beserved on regulated The open season essentiallyconsistsof "requests tariffs. Such a regime prevents the balance of for capacity" from potential new customers power from leaning toward either pa* in the onthe NGF!Inthisway, an open seasonenables negotiations. In Europe, the European Gas a private pipeline developer to assess the Directive allows the adoption of a system of demand for its proposed new pipeline network. either NTPA or RTPA. Further, in Europe, most The open season does not deal with the issue of new gas systems will be able to obtain transportation tariffs for new pipeline derogation for up to 10 years according to the development; its principle purpose is to get an Dire~tive.'~Most countries currently follow indication of shippers demand for newcapacity. negotiatedTPA rules, and the lack of common rules releaseverticallyintegratedtransporters in A pipeline operator normally is allowed to most European markets from some regulatory require a minimum term for new transportation constraints. While this freedom increases the capacity from customers on a new pipeline short-term bargaining position of the gas development. During the open season process, transporter, it can also lead to multiple an interestedshipper mustcomplete a "letter of disputes, hinder the introduction of effective intent," which states that the shipper is competition and be potentially damaging to contemplating signing a pro forma GTC with investment incentives. the private operator within a specified number of days after the close of the open season. Hence, a system of RTPA not only guarantees Typically, GTC(s) are signed before the nondiscriminatoryaccesstothe network, butalso construction of the pipeline which specifies the ensures that the pipeline owner and operator terms and conditions, including tariffs and do not abuse its market position to block the capacity, for shipping gas on the pipeline. It is developmentof competition inthe shipping and recommendedthat an open season process be supply of gas by refusing new entrants access conducted for the NGF! to the pipeline network. However, the strict applicationof RTPAcan restrictdesirableoutcomes Pipeline Capacity suchas negotiationfor lowertransportationtariffs for marginal users under underutilized pipeline International experience shows that greenfield network. NTPA can provide stronger incentives transmission network developed is driven by and better alignment with economic goals. transportation contracts with "firm" capacity rights. This is mainly based on the fact that a The most appropriate access for the NGP will private pipeline developer is unlikelyto be able partlydepend onwhetheror notthefuture owner to finance the construction of the new capacity of the pipeline will carry out other activities in without shippers who are committedto payfor it. " A derogation is the right of the pipeline owner to refuse access to its pipeline network for a specificperiod. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK A firm transportation contract provides the can be avoided. Two-part pricing (capacityand shipper with the right to use reserved, energy) isthe normfor powersalesagreements, prespecifiedand defined capacityon a pipeline becauseit avoids the incentivesfor uneconomic to ship gas. In general, firm transportation dispatch which could occur under a single-part contracts define a specific volume of capacity tariff. Hence, a gas pricing structure in GSA(s) over a certainspecified distancebetweenspecific and power purchase agreements should be receiptand delivserylocations, or a possibleset developed that is compatible with least-cost of locations.76 dispatch of power plants, and will likely require the establishmentof a two-part tariff structure. Itis very likelythat initiallyonlythe power sector will be in a position to sign long-term GSA(s) Transportation Tariffs and GTC(s)with firm capacity. Some additional uncontracted (spare)capacity in the pipeline will Gas network costs are driven by the need to be requiredand ensure that future customers, in meet peak demand. These are fixed costs of particular, industrial plants and the commercial increasing network capacity. The variable costs sector, will be ableto contractfor capacityon the of network operation are generally quite small NGF! Spare capacity in this context means all in relation to the fixed costs. Therefore, noncontractedor noncommittedcapacityas part customers who have a peaky load shape are of the open season in the process of developing causingmorecost on the systemthan customers the NGF!The exact volume of the spare capacity with a flat or base load demand shape. Hence, will depend on an assessment of the future - costs would have to be divided into fixed demand on the pipeline. and variable costs which can translate into a capacity and commodity charging regime for For the construction of the NGP, it is system users. recommended that firm capacity rights are offered as part of the GTC(s). Further, the It is assumed that gas demand overall will be pipeline owners should be allowed to create quite flat in Yemen (there is relatively little some reasonableexcesscapacity inthe pipeline seasonal differencefor power demand)and the and recover those additional costs from the costsof within-day balancingare probably quite gas tariff. small as well. There could, nevertheless, be significantlydifferentcosts of supplying different Gas Pricing Structure categories of customers (for example, power plants versus industrial load). The integration of the gas and power markets is crucialfor the development of the NGF!If power GOY could provide a long-term tariff to the generators have to sign long-term take-or-pay potential investorthat is "fixed" and not directly contractswith upstreamoperatorsfor the supply linked to volume throughout. Alternatively, of the "commodity" gas, they may tend to a two-part tariff design could be adopted. This mitigate that take-or-pay risk by requiring a is a structure underwhich one part is a periodic minimum offtakeof power undertheir long-term availability charge that covers fixed costs, power sales agreements. These back-to-back and the other part is applied to the actual contractsshould ensurethatthe risk of mismatch amount of service that is provided and covers between fuel purchase and fuel consumption variable costs. 76In more developed gas markets, shippers can also obtain "interruptible" transportationservice or by tradingfirm or interruptible capacity in a secondary (capacity release) market. However, interruptible service is less relevant for greenfield developments. A FRAMEWORK FOR DEVELOPINGTHE DOMESTICGAS MARKET In principle, the level of tariffs should allow the The economic analysis above has demonstrated efficient service provider to recover costs, that there is substantial leeway in the design including a reasonable return on assets. (both size and structure) of gas transportation A transportation tariff that is mostly fixed may tariffs onthe NGF! To createan attractive regime be more attractive to a private pipeline for a potential private investor, the exact design developer.The advantage of having a fixed tariff will require more methodological discussions for a greenfield pipeline is that this will not only and analysis. simplify the supervision of the GTC(s), but also encourage the pipeline operator to further seek Other Relevant Concepts and Provisions gas connections from industry and others to for Greenfield Pipelines increase the profit margin. More gas uptake, in contrast, would benefit Yemen as industrywould "Blue sky" isa term referring to the possibilityof switch away from more expensive and/or a private pipeline operator realising financial polluting alternativefuel sources such as HFO. rewardsarisingfrom a greater-than-anticipated increase in future gas throughput on a pipeline A two-part tariff is more complicated to than expected at the outset. This provision may administer, but would further reduce overall provide a good incentive for the developer of tariffs as more users take up gas in the long the NGP to actively seek additional customers run. Such a tariff could be linked to "blue sky" on the pipeline beyond the power sector. provisions (discussednext)that create incentives Benefits-sharing mechanisms might be for the pipeline operator to avoid undersizing negotiated between shippers and the pipeline of pipelines. This will avoid asymmetric risks to share some of those benefits. Blue sky only where the pipeline bears the costs if volumes ariseswhere regulatedtransportation tariffs are are less than expected but does not enjoy the volume-related ratherthan fully capacity-related. benefits of higher-than expected volumes. Most FavouredNation (MFN)clauses in GTC(s) Costs of transmission networks also vary with have the potential to prevent a pipeline owner distance and length of pipelines and pressure and operator from offering different tariffs for of supply and a locational or distance related transportation services to shippers on the charging regime could be adopted. Distance pipeline. Price discrimination on a pipeline related pricing provides signal on whether to networkgenerallyincreaseseconomicefficiency expand the network especially into remote through itsencouragementof increasednetwork areas.77 However, there are often social and utilization and in many developed gas markets political factors that prevent governments from with a wide network of gas transmission introducing such pricing regimes. Further, to networks, such as the U.S., price discrimination simplify the tariff regime on the NGF:GOYmay tends to be enco~raged.~~In some larger gas consider establishing a uniform or postage- markets in developing countries, such as stamp pricing regime. Mexico and Argentina, MFN clauses exist in 77As in the case of transmission, each potential gas distribution area in Yemen may have different costs. Key costs drivers for distribution are the customer density of the region (which principally affects the pipeline length per customer) and the demand volumes. Theproportion of small commercial or residential customersin the mix will lead to much higher unit coststhan areas with larger industrial loads. "IntheU.S.,MFNclausesarenotincludedingastransportationcontrads.However,underFERCrules,interstatepipelinenetwork owners are only allowed to offer different tariffs for transportation services to shippers on a pipeline who are not "similarly situated." Similarly, situated shippers are interpreted as shippers that take service over the same part of the pipeline and have similar alternatives options. See Alternative Ratemaking Policy Statement: Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines, 74 FERC 6 1,076, 7996. REPUBLICOF YEMEN: A NATURAL GAS INCENTIVEFRAMEWORK transportation contracts. MFN clauses and blue and provide governments with a reason to sky provisions could be applied in Yemen. intervene in the operation of the market. The appropriatenessof these terms will depend on the final transportation tariff structure Some monopolies exist because of the intrinsic and pipeline capacity arrangements and economic conditions of production. These incentive regime. monopoliesare called "natural monopolies" and require permanent regulation of their behavior, Developmentof an Efficient if the undesirable effects of monopoly are to RegulatoryRegime be avoided. Therearefour keyregulatoryquestionsthat have Natural gas pipelines are natural monopolies to be addressed, namely "why" do we have to and are characterized by large economies of regulate the gas industry, "what" regulation scale (relative to the size of the market), such intends to achieve, "what" parts of the gas that one firm meeting total demand is always market has to be regulated and "how" should cheaperthan the total cost of two or morefirms, regulation be conducted. each meeting a share of total demand. In such conditions, continuing competition inthe market Why Regulationof the Gas Sector iseither inefficient or impossibleand could lead is Necessary to pipelineduplication and lossof socialwelfare. The primarymethodof organising privatesector Economic regulation is the process for setting activity is through the operation of a market. termsandconditionsfor accesswheretheycannot Provided that certain basic rules are defined be set through competition. (principally, who owns what), markets allow producers to compete against one another, What Regulation Intendsto Achieve unfettered by any constraints other than the conditions of supply and demand. Under Profit-maximizingmonopolies restrictthe supply those conditions, competition will produce the of a product or service in order to drive up the best outcome. priceand to raisetheir profits. Thestartingpoint for regulation is simply the desire to increase However, if some criteria are not met, output and to bring prices back down toward competitionproducesundesirableoutcomes. For the levelof costs, includingthe costsof ~apital.'~ example, in case of monopolistic market structures, competition is not feasible and a Regulatory interventions increase allocative profit-maximizing monopoly will raise its prices efficiency, that is, the efficiency with which above its costs, to increase profits. High prices customers choose which products and services do not only allow the firm to earn profits that to consume (and, hence, the efficiency with are higher than they need to be, but also which resources is allocated to production). discourage demand that could be met at a cost Setting prices in line with costs helps customers that customers are willing to pay . Both factors to allocate their expenditure efficiently - and result in the loss of potential benefits to society prevents monopoly profits.80 79Regulatory economists divide the accounting profits of a regulated company into two parts: the cost of capital, or the rate of return required to reimburse investors, sometimes known as the "normal profit"; and any rent or "supernormal profit" earned above the cost of capital. However, regulation can also result in allocative inefficiency if it discouragesor prohibits price differentiation and discountsthat would avoid deterring use of the pipeline where users are willing to pay more than the marginal costs, but less than the average costs. This is particularly relevant for gas pipelines where the difference between marginal costs and long-term average costs can be very large. A FRAMEWORK FOR DEVELOPINGTHE DOMESTICGAS MARKET To increase efficiency overall, monopoly multiple importers, producers, shippers and regulation must also avoid causing an suppliers compete to sell gas to numerous unnecessary increase in production costs. If customers are unregulated. Regulation is prices are set equal to costs (including the cost not required as efficient competition creates of capital) at all times, then the monopolist has optimal outcomes. no incentiveto minimizecosts, since increasein cost do not cause profits to fall. Such a regime In some developed gas markets, full retail would allow costs to rise and would reduce competitionhas been establishedand gas prices productive efficiency, that is, the efficiency with for residentialhouseholdsare alsodeterminedby which the company produces a given level of competition (that is, the United Kingdom). The output. Therefore, regulatory regimes should regulator simply has an oversight role to ensure offer incentivefor regulatedcompaniesto reduce that retail competition is effective and does not their costs, essentially by reducing profits if the interfere in the market as long as this is ensured. company is inefficient, and increasing profits if the company is efficient. In less competitive or uncompetitive markets, a gas regulator also has to supervise the The main terms of monopoly regulation are?' import, supply and shipping of gas to protect customers from monopoly power. In Yemen, Legal protection of a monopoly in returnfor there will be a very limited number of buyers an obligation to meet all reasonable and sellers of gas, and efficient competition demands for the service; is unlikely to evolvefor the supply and shipping of natural gas in the short- to medium-term A promise that the company will recover its future. Hence, regulatory oversight of all parts prudently incurred costs, balanced by a of the gas chain will be required for the restrictionon revenuesor pricesthat prevents foreseeable future. the company from earning monopoly profits; and How should the Gas Sector be Regulated A set of minimum quality standards that prevents the company from profiting by A regulatory framework needsto be developed reducingthe qualityof service (asa substitute for the gas sector in Yemen that is congruent for rising prices). with the potential size of the gas market and What in the Gas Sector should existing governance structures, and consistent be Regulated with international best practice. To achieve this, instruments used to implement a regulatory In competitive gas markets (such as Australia, framework must be able to provide stable and the U.S. and the U.K.), where there are multiple legally enforceable regulation in order to buyersand sellersof naturalgas andthe industry promote the certainty that is needed to attract is "unbundled" the only areas that are subiect to private sector investment for pipeline economic regulation are the natural monopoly development. Further, the instrument(s)should elementsof the gaschain, namelythegaspipeline involve a degree of prescription in defining the T&D businesses.The competitiveelementswhere framework to ensure it isworkable and effective. Shuttleworth, Graham, The Principles of Good Monopoly Regi)lotion, NER.4, February2007. REPUBLIC OF YEh4EN: A NATURAL GAS INCENTIVEFRAMEWORK GOY has two major options for setting up an "first-order instrument" andtends to state broad efficient regulatory framework for the gas general principlesand conceptsthat are unlikely market, namely: to be subiect to change for a reasonably long period. Table 3.1 1 sets out what a potential gas Full legislation; and law tends to cover. Regulation by contract. Legislation is typically implemented through a combinationof subordinate instruments, such as Full Legislation decrees, regulations, licenses and enforcement Legislation is typically used in the regulation of guidelines, which spell out more specific utilities industries in advanced economies procedures and rules. .These subordinate globally and in larger energy markets in instrumentstend to be more specific, yet, easier developing countries (for example, Indonesia, to amend and adopt to changing industry Nigeria, Argentina), but has not been used conditions. Matters covered in subordinate widely for governing the energy sector in instruments are set out in Table 3.12. general, andthe oil and gas sector in particular, in The advantagesof legislationarethat it provides a robust and certain framework for industry Under this approach, primary legislation (such administration and allows more detailed as a gas law)sets outthe overarchingprinciples, regulatoryarrangementsto beestablished in less rights and obligations of the participants in the rigidsubordinateinstruments. However, the rigor market, and this is enacted by the legislature of the implementation process means that there (that is, parliament). The legislation is the may be a substantial delay in implementation.83 Table 3.11: Coverage of Potential Gas Law Coverage of the regulatory framework Prohibitionof regulated activities without license Authority to issue licenses and criteria for issuing licenses Obligation to provide Third PartyAccess Broad pricing principles Broad regulatory processes Right to independent dispute resolution Rights of appeal 82The upstream oil sector is basically governed by contract through PSAs. 83An alternative to the full legislation approach is to implement the regulatory framework through one or more decrees. Under this model, the enabling provisions and broad principles are provided through a decree. The detailed arrongements may then be set out in further implementing decrees, licenses and/or enforcement guidelines. The advantage of the decree approoch is that it is promulgated by the government, and therefore, avoids the lengthy approval processes necessary to pass legislation through the Yemeni parliament. On the negative side, a decree, due to its less rigorous nature, does not provide the same degree of certainty as legislation. A FRAMEWORKFOR DEVELOPINGTHE DOMESTIC GAS MARKFT Table 3.12: Coverageof Subordinate Instruments Proceduresfor application and issuinn of licenses Technical standards (for example, safety, health, metering) Detailed price regulation methods and formulae Standard license conditions Detailed regulatory decision-making processes Regulatoryaccounting requirements Hence, while a robust framework may be A regulation by legislation approach tends to achieved inthevery longterm, the lengthyperiod be more appropriate when the gas industry is of uncertaintyin the medium term, arising from already well established. To improve the delays in the development and passing of efficiency of the industry, governments often legislation, may have a significantly harmful restructure and break up existing gas markets effect on development of a gas market. and newly assign roles and responsibilities for market participants by passing primary Regulation by Contract legislation (and subsequent subregulations). Further, the size of the future gas market The other option for implementation of the and required gas pipeline infrastructure regulatoryframework is regulation by contract. developmentsare decisive. In largegas markets, This approach involves GOY and the owners such as Indonesiaor Brazil, asthe marketgrows, and/or operators of gas pipelines establishing additional gas pipeline networkwill be required a regulatory regime that applies by force of to serve customers throughout the country. To contract. All aspects of the regulation set out ensure the development of a competitive gas above would thus be set forth in a contract. market, and avoid different regulatory regimes The advantages of this approach are that it for each gas pipeline, a regulatory approach does not involve the delays inherent in the based on full legislation is preferable. legislative option and allows the application of Otherwise, the risk is that regulation istailored principles that are unique to the particular to each particular project, making regulatory pipeline situation. However, the disadvantages activity (adiudication during conflicts and are that it requires consensus of both GOYand issuing new legislation) difficult to be exercised the pipeline owner/operator, so may still take consistently over time and as the market some time to implement. further develops. Furthermore, another new proiect will require In contrast, regulation by contract is often used negotiation of another unique agreement and when a government wishes to grant a revision of any provisions over time will require "special status" to ensure a greenfield pipeline further negotiation. In addition, a contract proiect is being realized as soon as possible, approach is less transparent than regulation by and to make it financially attractive for private legislation and may make it more difficult to investor. In Yemen, the biggest net benefit to ensure uniformity and fairness of regulation. society isto get the NGP built and through fuel- REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK switching savings by the power sector. Setting The proposed licensing/concession regime, and up a regulatory framework based on full who is allowed to carry out what function in the legislation would delay that process for many market, should be consistentwith the gas market years and, hence, regulation by contract may structure set out above. There should be no be more suitable.84 ownership restrictions and barriers to participate in any part of the gas chain. Further, once the NGP has been built, there will However, Iicenses/concessions will set out be limited opportunities for additional gas unbundling requirements and the need to transmission development and any additional establish separate regulatory accounts, and transmission pipeline could be regulated by these and other responsibilities will be set out contract. There are also limited gas distribution in the respective authorizations. networkdevelopment opportunitiesinYemen in the near future, and contracts are likely to be The licensing instrument could also be used to the most efficient means to ensure distribution develop a "middle-ground" option distinguished network development down the road.85 from regulation by legislationand regulation by contract for the NGP and other transmission Licenses and Concessions network development whereby the license conditions attached to the approval of a GOYshould issue licenses/concessions for each greenfield pipeline development sets out the activity carried out in the market, including gas access regime and includes broad regulatory supply, shipping and T&D. A license grants principles such as pricing principles, rights of companies the right to participate in the gas appeal, rightsof independentdispute resolution, market and sets out their respective roles and and so on. The pipeline developer could, then, obligations. Concessions are arrangements in offer a long-term access regime and further which a firm obtains, from the government, the clarify the terms and conditions of access, for long-term right to provide a service under example, technical standards, detailed pricing conditions of signification market power by methods and formulae. Once those terms creatinggeographicexclusivityrights.Concessions and conditions are agreed, the access regime are often granted in gas distribution. would effectively be the contract between the pipeline and users that contain the necessary Separate T&D licenses/concessions should be regulatory provisions. issued. Transmission licenses tend not to have regional exclusivity whereas distribution Who should Regulate concessions generally have exclusivity on a regional basis. In principle, a network company Standardtheoryon utilityregulationrequiresthe could hold both a transmission license and a establishment of an "independent" regulatory distribution concession and also hold gas agency. Although the independent regulator supplier and/or shipper licenses. Distribution model is a widely accepted best practice model companiesoften carry out supplyfunctions, and of regulation for developed economies and should also be issued a supply license. mature gas markets, it is unrealistic to expect 84Regulationby contractis also consistentwith Yemen'supstream regulatoryexperience in oil and gas. TheMOM issues authorizations to perform the various activitiesin the hydrocarbon sector, and regulatory provisions for the upstream are provided in the oil/gas- sharing agreements. Notural gas could potentially replace LPG in urban and semiurbon areas for the domestic sector in and around Sana'a and Aden, but it is unlikely that distribution network development will be economically and financially viable in more rural areas. A FRAMEWORK FOR DEVELOPINGTHE DOMESTIC GAS MARKET that the model can be adopted immediately in investmentplan for new gas-fired power plants all countries and at all times. This is particularly (and for the conversion of existing generators) the case in countries with limited institutional matches the timing of the construction of the capacity. Further establishing such an NGP; and to (b) assist in structuring suitable independentagencyto supervisethe gas market terms and conditionsof the long-term GSA and requires substantial financial resources for GTC and licenses. creating and runningthe agency, hiring qualified staff, political will and time. It further requires For the foreseeable future, the Yemeni gas regulatory powers to develop, implement and market will comprise a limited number of supervise compliance with regulations. In pipelinesandthe conditionsand terms of access, countries which do not have those institutional including tariffs, can be covered by contracts and legal capacities, more attention needs to and the licenses/concessions. The primary be directedto good-fit ratherthan best-practice regulatory task would be to verify that regulatory systems.86 compliance with the contract(s)/license(s)/ concession(s)and, in principle, that task could In Yemen, the government has various roles be carried out by: (a) a separate government that are proneto createconflictof interests.GOY agency within a ministry(ies); (b) existing owns gas reserves(throughSafer),finances and governmentagency(ies);and (c)a newlycreated potentially operates the Marib Gas Pipeline government authority. (through PEC) and will initially be the sole customer of the gas (through PEC). At the same To ensure that regulatory activity is conducted time, GOYis responsiblefor developing energy in a transparent manner, a limited set of policies (including natural gas policies) which functions could be assignedto that government are conducted through its ministries and agency under the direct jurisdiction of GOY. If it government units, and is also responsible for is embedded within an existing government promoting privatesector participation.While the agency(ies), committees could be established creation of an independent regulatory agency comprising civil servantsfrom MOM, MOE and is impractical, creatingsomeseparation between other relevant stakeholder (for example, the the political and economic functions in the gas Ministry of Industry and government agencies market, and creating a suitable regulatory that are responsiblefor privatesector investment, regime that provides some comfort to market private sector representation). participants and potential private investors, is necessary. This relevant government agency(ies) could develop implement and supervise a regulatory The active participation of the Ministry of regime based on contracts, and could also be Electricity (MOE) in setting up a suitable responsiblefor issuinglicensesand concessions. regulatory regime for the gas market is The agency(ies) could further develop broad paramount considering that the existing and regulatory principlesthat would govern the gas projected gas-fired plants will anchor the market and would engage in the monitoring of development of the NGF! Close cooperation compliancewith technical and safety standards between the two ministries (namely, M O M and obligations set out in licenses and and MOE) is crucial to: (a) ensure that the concession contracts (for example, mandatory 86See Handbook for Evaluating Infrastructure Regulatory Systems, Brown, A., Stern, J., and Tenenbaum, B., The World Bank, WashingtonDC, 2006 and Groom, E., Halpern, J., Ehrhardt, D., ExplanatoryNotes on Key Topicsin the Regulationof Water and Sanitation Services, Water Supply and Sanitation Sector Board Discussion Paper Series, Paper No. 6, June 2006. 57 REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK investments, information requirements, economic and financial viability of that pipeline disclosure of technical and commercial was demonstratedinthisChapter.To avoidfurther information). Further, the agency(ies) could constraints on public financing and considering advice the government in technical and the large investment requirements, the private commercialmattersthat may be neededfor the sector, or a public-private partnership, should purpose of granting new concessions and lead the development of the greenfield proiect. licenses. Credibility of the regulatory regime could be enhanced in some or all of the Timing is a keyfactor and the earlier the NGP is monitoring functions, for example, GTC(s) on constructed, the higherthe neteconomicbenefits the NGP would be carried out by international to the Yemeni economy. Consequently, a auditors on an annual or biannual basis.87 regulatory regime and gas marketstructure has to be put in place that is practical, attractive to In the longer run and given the close link private investors, consistent with international between the gas and power sectors in Yemen, best practice, suitable for the small size of the the establishment of a "joint" government or gas market and in conformity with Yemen's independent regulatory agency may also be legal and institutional practice and history of considered. There are economies of scope and governing the utilities sector. scale in establishing a joint gas and power regulatory agency, for example, in the areas of The currentgas marketisdominated bythe State technical regulation and price-setting. However, and the government should allow for private the establishmentof such an agency should not participation in all parts of the gas chain. It is delay the development of the gas market and, recommended that no cross-ownership in particular, the constructionof the NGP restrictions apply and market participants are allowed to participate in all parts of the gas Conclusions chain, including gas production, transmission, distribution, shipping, supplyand consumption. Yemen has a unique opportunity to reduce the This would mean that the owner and operator oil dependency of its domestic market by of the NGP should also be allowed to be a gas switching to natural gas, in particular, gas-to- producer, buyerand sellerof the gasor customer. power. It was estimated that over a 30-year However, to ensure transparency and protection period, about 800 million bbl[s] of crude oil of end users and to prevent anti-competitive could be saved by the power sector and those behavior, companieswho engage in several gas could be earmarked for exports to boost businesses along the gas chain will have to government revenues. Natural gas will also unbundle and prepare separate accounts for provide current and emerging industrieswith an each business activity. opportunity to have access to relatively cheap, clean and reliable source of energy. The analysis hasfurther demonstratedthat GOY has substantial leeway in designing a market The development of the domestic gas market and regulatory regime for the NGP that will will requirethe construction of the NGPand the make it attractive for private investors to 87Yemen may not yet be in a position where the legal arrangements allow regulation by contract (or licenses)administered solely be a government agency(ies), or the courts in case of disputes. One possibility is to provide contract(s)/license(s)supervision and enforcement by an agency outside the country, for example, on international arbitration body or on international group of experts. While this still leaves major problems of enforcement with the country, the increased transparency may enhance private investors' willingnessto participate in the market. A FRAMEWORKFOR DEVELOPINGTHE DOMESTIC GAS MARKET participate. It is proposed that separate should also consider creating a framework commodity and transportation contracts, TPA to allow for the participation of lPPs to meet rules, anopenseasonprocess, firm capacityrights future power generation demand. Without and an attractivetariff structure be adopted. addressing the shortcomings of the power sector, the construction of the NGP will likely Yemen isa verysmall gas marketand has limited be delayed. history and expertise in regulating network businesses. An approach based on full Yemen has limited institutional capacity and legislation (gas law, subregulations and effectiveness and although the independent guidelines) for developing the domestic gas regulator model is a widely accepted best market is likely to be a lengthyprocessand will practice model of economic regulation for further delay the construction of the NGF! It is developedeconomiesand largeand maturegas notagood ideatowaste valuabletimethatcould markets, it is unrealisticand not suitablefor the be used in the implementation of the project in developmentof the Yemeni gas market.A more trying to pass a law and creating subsequent practical approach is to carry out regulatory regulations and, consequently, "regulation by duties through an existing government contract" should be adopted. agency(ies) and possibly mitigating some of the conflicts of interests of the government The future development of the gas sector will by appointing an international agency require close coordination and cooperation (for example, auditing company, panel of between the power and gas sectors. No private experts)to periodicallyreviewcontractsto ensure financier will invest if the power sector is not compliance.However, some considerationcould ready to receive gas or is unwilling to convert. still be given to a joint independent gas and In contrast, before making such a commitment electricity regulatory agency to benefit from and converting their appliances, the power economiesof scaleand scope in regulation(such sector has to be sure that the NGP is going to as technical regulation and price-setting). It is be built and that the gas and transportation recommended that the most suitable and tariffs are attractive. This will require long-term practical agency(ies)will be identified as part of gas supply and gas transportation agreements developingthe detailed regulatorycontractsand betweenthe various partiesto mitigatethat risk. overall framework. It is further required to reform and restructure the powersector and itselectricitytariff structure Theseflexible ownership, marketand regulatory to ensure that PEC, the incumbent, can arrangements will increase the incentives for recover its prudently incurred cost of supply privateinvestorsto participateinthe marketand and has the financial capacity to carry out developthe NGPand, at the same time, protect the investmentto uptake gas. The government the interest of Yemeni customers. 4. Analysis of the Key Features of Proposed Legal and Fiscal Terms for the Exploration, Development and Production of Hydrocarbons Introduction that the policy makers could take into consideration for application in Yemen. It is expected that oil production from currently producing fields will steeply decline after 2010. The starting point of this analysis is to present The revenuesthat are expectedto be generated alternative legal and fiscal arrangements, and by the planned LNG project will only partially to definetheir principal componentsand relative offset the decline in government revenues. attractiveness from the points of view of the A higher level of exploration is considered investor and of the host government. Against necessary to increase the probability that this backdrop, the legal and fiscal framework sufficient reserves of gas will be found and for petroleum operations in Yemen will be brought to market in time to meet future presented. Finally, features of the petroleum domestic and international gas demand. At the fiscal regime in a selected group of countries same time, there may be scope for devising will be outlined. incentives to enhance the recovery of existing oil reserves so as to partly offset the expected Alternative Petroleum Legal and decline in production. FiscalSystems: Advantages and DisadvantagesEE The global nature of petroleum investments poses challenges to government policy makers The extraction of hydrocarbons involves the who areoften notina positionto makeinformed transformation of nonrenewablephysicalassets decisions to determinewhat types and levels of intocapitalor financial assets.The initial decision taxation and what types of legal arrangements to investand the resultingallocation of revenues can or should be appliedto petroleum projects. and benefitsare greatlyinfluencedbythe content This Chapter provides an overview of the key of existing legal arrangements and fiscal features of petroleum legal arrangements and policies. In today's competitive market, many fiscal systems, and outlines desirable features diverging interests must be recognized and The analysis presented in Chapters4 and 5 has been largely drawn from Silvana Tordo, "Fiscal Systems for Hydrocarbons: DesignIssues," Working PaperSeries, The WorldBank, forthcoming. 61 REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVEFRAMEWORK accommodated to establish an effective and on their legal systems. Where no unique policy attractive legal and fiscal framework for regime existst9' comprehensive contractual hydrocarbon E&F! No ideal or model regime is agreements between host governments and available for policy makers to adopt. Each investors are used. country's circumstances, needs and obiectives define the key features of an appropriate legal Various legal systems have been developed and fiscal framework. As these circumstances, to address the rights and obligations of the needsandobiectivesare likelyto changeintime, State and of the investors, as well as the the most effective and efficient legal and fiscal ownership of the natural resources. These can be frameworks are those that are flexible enough grouped under two main systems: concessionary to accommodate these changes. systems (alsocalled tax and royalty systems) and contractual systems (these include PSAs, and Decisionson the design of an appropriate legal service and risk service contracts). Box 4.1 and fiscal framework can be supported by an summarizes the key features of the two systems. understanding of how its various components influencedecision making and outcomes. In both systems, the investor assumes all risks and costs associated with the exploration, Legal Frameworksfor the development and production of hydrocarbons, PetroleumSector and receivescompensationadequatetothe risk. Often the investment risks are assumed by oil The legal basis for hydrocarbon exploration, companies rather than the State/owner of the development and production is normally set in resource. In general terms, the higher the risk a country's c ~ n s t i t u t i o n .Normally, the ~ ~ of investment activities in a country, the higher hydrocarbon law, formulated at parliamentary the portion of the rent received by the investor. level, sets out the principles of law, while those Although historical considerationsinfluencethe provisions that do not affect principles of definition of "adequate compensation," law, or that mayneed periodic adiustments(that project-specificelementsandfuture expectations is, technical requirements, administrative are also important. The notion may also vary procedures, administrativefees, and so on, and during the life cycle of a p r ~ i e c t . ~ ~ so forth) are set in regulation^.^^ Exploration, developmentand production rightsin particular The fundamental difference between areas or blocks are granted by governments by concessionary and contractual systems relates meansof concessionsor contracts, depending to the ownership of the natural resources: 89 The consistency of the legal fromework with the constitutional foundation is an importont factor affecting the security and stability of the legal framework. Thisissue is significant, in particular becausethe constitutions of many countries differ significantly in the degree to which they recognize or guorantee private property rights or prohibit private parties or foreigners from ocquiring property rights in general, and mineral rights in particular; vest the authority to grant petroleum rights in the state or provincial governments or agencies rather than the national government, vest the authority to regulate specific matters in special agencies (thatis, environment protection) or in the executive branch (for example, taxation, foreign exchange employment, and so on) or in the judiciary (settlementof disputes). Due to the capital-intensive and long-term nature of petroleum projects, certainty of rights is particularly important for private investors. 90These are normally issued at the executive or ministerial level, and do not require the approval of the legislative branch. Thisis the case in Yemen where no hydrocarbon law exists at the national level and PSAs are negotiated between the State and the investorson a case-by-case basis and are given the force of law. Thisapproach may be favored by those countries that facethe uncertainty of entering the sector for the first time or in cases where the importance of the petroleum activity moy not justify the design of unique policy regimes. 92In general terms, while geological risk begins to diminish ofter a discovery, the political and financial risks intensify. One of the reasons for this is that the bargaining power and the relotive strength of the investors' and host government's positions shift during the cycle of petroleum exploration and development. By the time production commences, copital investment is a "sunk" cost, and facilities installed in foreign countries represent a source of vulnerability to the investor. ANALYSIS OFTHE KEY FEATURES OF PROPOSEDLEGALAND FISCALTERMS FORTHE EXPLORATION, DEVELOPMENT, AND PRODUCTIONOF HYDROCARBONS Box 4.1 :Key Featuresof Concessionary and Contractual Systems REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK Under a concessionary system, the title to Furthermore, unlessspecific provisions have hydrocarbons passes to the investor at the been included in the contract (or in the borehole. The State receives royalties and relevant legislation), the government (or taxes in compensation for the use of the the national oil company) istypically legally resource by the investor. Title to and responsible for abandonment. ownership of equipment and installation permanently affixed to the ground and/or In both types of legal systems, the issue of destined for exploration and production ownership is particularly significant as it affects of hydrocarbons, generally passes to the rightsand obligations of the partiesandtheir the State at the expiry, or termination, ability to disposeoff these rights. Giventhe risky of the concession (whichever is earlier). nature of the industry, the investor's ability to The investor is typically responsible share the risk by transferring all or part of its for abandonment; and rightsto other investors, and the objectivityand transparency of the conditions for government Under a contractual system, the investor approval or denial of such transfer (including acquires the ownership of its share of any relevant performance guarantee) is an production only at the delivery point.93Title important element of the overall attractiveness to and ownership of equipment and of a country's regime. installation permanentlyaffixedtothe ground and/or destined for E&p of hydrocarbons, Table 4.1 summarizes the main difference generally passes to the State immediately. between concessionary systems m d FUs. Table 4.1:Main Difference between ConcessionarySystems and Petroleum Sharing Agreements Concessionary Systems PetroleumSharing Agreements Ownershipof Nation's Held by State Held by State Mineral Resources Title Transfer Point At the Well Head At the Export Point Company Entitlement Gross Production Less Royalty Cost Oil + Profit Oil Entitlement Percentage Typically around 90% Typically 50-60% Ownership of Facilities Held by Company Held by the State Managementand Control Typically Less Government More Direct Government Control Control and Participation Government Participation Less Likely More Likely (carriedworking interest) Ring Fencing Less Likely More Likely Source: D. Johnston, Petroleum Fiscal Systems and Production Sharing Contracts, PennWell Books, 1994. 93Under a service contract, the contractor never acquires the title to the resource. On the contrary, he is paid a fixed or variable fee for his services. In some service contracts, the fee is paid in kind. The distinction between PSA and Risk Service Contracts lies in the nature of the payment. ANALYSIS OF THE KEY FEATURES OF PROPOSED LEGALAND FISCALTERMS FOR THE EXPLORATION, DEVELOPMENT, AND PRODUCTION OF HYDROCARBONS Elements of Successful environment protection are defined in the Legal Frameworks environmental law/regulations, and so on, and so forth. Thus, the hydrocarbon law incorporates While for manyyears governmentshavefocused other laws by reference. Modularity increases on how to acquire control of the resources, transparency and accountability, reduces typically resulting in the creation of national oil administrationcosts and facilitates compliance. companies or the setting up of rigid and highly prescriptive legal frameworks, in recent years A clear, simple and nondiscretionarylegal and we have been observing a tendency by regulatory framework is an important factor for governments to scale back or rationalizethose attracting foreign investment. This affects the entities and simplify their legal frameworks. entire value chain from the award of E&P rights to the disclosure of information that affects the The successful hydrocarbon reforms have citizenry. There are various ways of improving tended to establish the legal framework on the transparency in the management and the following pillars: oversight of the sector: the standardization of the terms of E&e the reduction of the discretion Definition of the role of the State; of the administrative authorities, the simplification of awarding and permitting Security of title; procedures, the developmentof an efficientand Freedom to operate on a commercial basis functioning open title system, the adoption of standardized form of agreements, the (includingvarious forms of private access to predefinition of standard shapeform of blocks, hydrocarbon resources); the granting of greater operating freedom to Comprehensive environmental protection the contractors, the adherence to international requirements; and arbitration (in particular where the local court system does not provide sufficient guarantees) Competitive and stable fiscal terms. and the respect of international disclosure practice are examples in this direction. Thetopicsthat aretypicallyaddressedin modern legal frameworks are summarized in Table 4.2 Fiscal Regimesfor the PetroleumSector: Tax and Nontax Instruments In promoting sustainable privatesector-led E&P changes inthe banking system, trade and labor Petroleumactivitiesaround theworld are subject sectors, judicial system and foreign investment to a great variety of taxation instruments. These regulations may be beneficial. include taxes that apply to all other sectors of the economy and taxes that are specific to the Although, in most countries, all matters related oil industry. In addition, nontax forms of rent to petroleum exploration, development collection (like surface fees, bonuses and and production tend to be governed by production sharing) are typically used. sector-specific legislation and regulation, countries that have recently reformed their Special provisions are often included in hydrocarbon sector have shown a preference petroleum fiscal regimes to modify the timing for the establishment of modular legal or magnitude of the revenue appropriations. frameworks. In these cases, all matters relating These provisions are normally intended as to hydrocarbonrightsandtheir useare governed incentives designed to attract investors, or to by the hydrocarbon law/regulations, all accommodate unique attributesof a petroleum matters relating to taxation are defined in the tax asset, or to influencethe choicesof the investors code/regulations, all issues relating to toward specific public policy goals. Accelerated REPUBLICOF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK Table 4.2: Key Elementsof Successful PetroleumLegal Frameworks Area Key Components -- Government Ownership of natural resources; powers granted to government officers; Authority enforcement; penalties and fines; and the authority to negotiate contracts Access to the Qualifications for authorization to explore, develop, produce and process; areas Acreage closed to mineral activities; areas subject to special controls or conditions; right of ingress and egress; resolution of conflicting land disputes; and the relation between surface and subsurface right holders Exploration and Extent of the E&P area; duration of the term for E&P rights; renewal of Production Rights E&P rights; unitization; cancellation or termination of a right; area and Obligations relinquishment; minimum work programs; security of tenure; reporting; transferability of rights and mortgageability; and surface fees Protection of the Environmental impact assessment; environmental impact mitigation; social or Environment community impact; monitoring and reporting; abandonment liability; reclamation; and environment sureties Fiscal Terms State participation; royalties; production sharing; custom duties; income tax rate and base; special petroleum taxes; other levies and taxes; gas production incentives and other incentives; ring fencing; and stability clauses capitalcost allowance^,^^ depletion allowance^,^^ A varietyof costsarealso imposedon companies interest deduction rules,96loss carry for~ard,~' that affect the profitability of their operations. investmentcredits,98tax holidays99and stability Some are fairly common, while others reflect provisionsloOare among the most commonly specificcountry's conditions. Thesecosts include used special provisions. intercompany services, valuation of oil and gas, -- 94 Assets are depreciated in many ways over their expected life (useful life of equipment, economic life of the reservoir). Themethods used in the industry are: (a)straight-line (equal annual deductions); (b)decliningbalance (straight-linedepreciation calculatedfor the remaining valueof the asseteach year); (c)double decliningbalance (doublesstraight-linedepreciationfor the remainingvalueof theasseteachyear); (d)sum of year digits (basedon an inverted scale whichis theratio of the number of digits in a given year divided by the total of all years digits); and (e)unit of production (thecapital cost of equipment, after deductionof the accumuloted depreciationand of the salvage value, is multiplied by the ratio between the total production in a year and the recoverable reserves remaining at the beginning of the tax year). 95 Thedepletionollowance is the deduction from gross income ollowed to investors in exhaustiblecommodities(suchas minerals, oil, or gas) for the depletion of the deposits. The theory behind the allowance is that an incentive is necessary to stimulate investment in this high-risk industry: as the reservoir depletes the company will need to undertake more exploration to find new reservoirs.Thedepletionallowanceis meant tosubsidize furtherexploration. Veryfew nations grant/granted depletionallowances (for example, the Barbados, Canada, Pakistan and the United States). The Filipino Participation Incentive Allowance (FPIA) is similar to a depletion allowancefor various reasons, including the fact that in a global industry the depletion allowance may be used to subsidize explorationin other countries. 96 Project financing is quite common for large projects or for small oil companies. Normally, interests on loans are allowed in deduction of taxableincomeand qualifyfor costrecovery. Inter-companyinterests may also be costrecoverableand tax deductible, if calculated on an arm-lengthbasis. 97 This refers to the ability of a company to "carry forward" losses from one year to offset tax liability in future years. When limitations apply, the loss can be carried forward for a set number of years (normallyfive to seven) after which the benefit expires. In most cases, unlimited loss carry forward is granted. Loss carry back are quite unusual. 98 In some countries, governments provide an incentive to investors by allowing them to recover an additional percentage of tangible capital expenditure (alsoknown as investment uplifts). In some cases, investment creditscon be tax deductible. Whencapitol investment in a projectis considerable, host governmentsmay grant tax holidays to investors, that is, the investors will not pay taxes for a specified period of time. "See Box 4.2 for a description of commonly used stability provisions. ANALYSIS OF THE KEY FEATURES OF PROPOSEDLEGALAND FISCALTERMS FORTHE MPLORATION, DEVELOPMENT, AND PRODUCTIONOF HYDROCARBONS foreign exchange regulations, domestic market revenues and investment decision is given obligations, government equity, performance in Annex 3. bonds, landownercompensations, localcontent obligations and requirementintendedto ensure Elementsof Good Petroleum good environmentalpracticesand adequatesite Fiscal Regimes reclamation funding. Evaluating the impact In all countries, fiscal regimes are designed to of these costs on different investors is a very maximizethe value (not the volume) over time complex exercise. of mineral resources in terms of receipts to the The effect of a fiscal system is derivedfrom how treasury, while, at the same time, attracting it impacts investment decisionslO'in either the foreign investment on a continuous basis. short (capital allocation within an existing Host governments also have development portfolio of assets) or the long (the decision to and socioeconomic objectives (job creation, invest in or reject a project) run, in other transfer of technology, development of local words, its neutrality.'02 This can be expressed in infrastructure, and so on, and so forth). terms of NPV of the expected project cash flows. Intuitively: To achieve these objectives, more and more countriesrelyonflexible, stableand neutralfiscal All taxes reduce the NPV of a project and regimes.The characteristicsof these regimesare make it less attractive. Therefore, the higher described in Box 4.2. the level of taxation, the lower the number of possible investments under prevailing Key Featuresof Yemen's 2006 market conditions; Model PSA The timing of revenue collection is a major The analysis of anycontractualand concessional determinant of the NPV of a project. Fiscal arrangement needs to take into consideration systems that reduce or defer revenue how it relates to the country's legal and collection are preferred by companies regulatory framework. In addition, the sector because they increase the NPV and institutional set-up is an important element in accelerate the investment's payback; and analyzing the sustainability of contractual oversightand managementarrangements, while The NPVissignificantlyinfluencedbythe risk the sector policy defines the target conditions profile of the investment. Therefore, fiscal for the design of the relevant fiscal terms. systems that reduce the perceived political or economic risks are preferred. Legal Framework103and Institutional Set-up A description of the main tax and nontax instruments commonly used in the oil industry The constitution, in Article 8, establishes the andthe evaluationof their effectson government State's ownership of natural resources. Yemen lo'Host governments and investors use different system measures to assess the impact of various fiscal systems. This is because, although they share the general objectiveof maximizing the revenue generated by a project, they also pursue a number of different objectives and face different constraints. Analyzing these objectives and constraints and the related system measuresis beyond the scope of this paper. For an in-depth analysis, see Silvana Tordo, "Fiscal Systemsfor Hydrocarbons: Design Issues," Working Paper Series, TheWorld Bank, forthcoming. '" For the definition of neutrality, refer Box 4.2. '" It is worth noting that a comprehensive analysis of the petroleum sector would necessitatethe analysis of the regulato~ybody for petroleum operations and protection of the environment, as well as knowledge of the list of international convention to which Yemen is a signatory and their actual implementation. At the time of preparation of this report, this information was not avoilable. REPUBLIC OFYEMEN: A NATURAL GAS INCENTIVEFRAMEWORK Box 4.2: Key Features of Effective Fiscal Regimes doflexibility, neuimliiyand Advantages ty mean? One of the most important advantages of A "flexible" fiscal regimeisonethat provides establishing a flexible structure (that is, a the government with an adequate share of progressive mechanism for rent extraction) economic rent under varying conditions of isitsstabilityovertime: as marketandproiect profitability; conditions change over time, flexible fiscal systems limit the needfor renegotiation; A "neutral" fiscal regimedoes notencourage The advantage of a neutralfiscal regime is overinvestment nor deter investments which its economic efficiency. A neutral tax does would otherwisetake place; and notimpactresourceallocation. With respect to the investing company, a tax is neutral when it leavesthe pretaxrankingof possible investment outcomes equal to the post-tax ranking. With respectto a particularindustry, a tax is neutral when it does not divert investmentsto or from that industry; * A *stobl& fiscal regimeis one that does not In industries with longtime cycles and change over a certain period of time, or in substantial upfront investments, stable and respectof which changes are predictable. predictable contractual and fiscal terms are an important consideration in ranking investmentopportunities,withobviousefFects on a country's future prospects. The stability of the fiscal regime also impacts business confidence, andaffectsthe levelof investment in and pace of development of existing projects; and Contractand fiscalstabilityclausesare used in both concessionary and contractual systerns. Accordingto a recentstudy, out of the 110 countries analyzed, 77 percent offeredfiscalstabilityprotection(Baunsgaard, IMF, 2001). does not have a unique sector law: the Petroleum betweenthe contractor and the Statewith respect Law 25 of 1976 that was in force in southern to petroleum exploration, development and Yemen before the country's unification is no production operations in the country.lo5The PSA longer applied.lo4Therefore, the rightto explore does not become effective until it is ratified by a for and produce oil is granted to companies by President's decree law.lo6 means of PSAs negotiated by the MOM o n behalf of the State. The PSA embodies all the Several vintages of PSAs exist that were the terms and conditions that govern the relationship product of negotiations between the State and '"'However, the law has not been formally repealed. lM Theseinclude foreign exchange controls,tax provisions, customsand duties, and foreign investment regulationsand so on, and so forth. lo6Once negotiations between theM O M and the contractor ore completed, the draft PSA is sent totheSpecial Economic Committee for evaluation. TheSpecial EconomicCommittee submitsits recommendations to the Council of Ministers, which, in turn, authorizes the M O M to execute the PSA. The PSA is then submitted to the Oil and Minerals Committee of the Parliament. Once approved by Parliament, the PSA is finally sent to the President of the Republic for ratification by decree law. The process takes on an average between 72 to 78 months. ANALYSISOF THE KEY FEATURESOF PROPOSEDLEGALAND FISCALTERMS FORTHE EXPLORATION,DEVELOPMENT, AND PRODUCTION OF HYDROCARBONS investors, and as such they contain different To promote exploration in new areas; terms. This situation is quite common in petroleum-producingcountries. Legalandfiscal To review PSA terms and procedures in line frameworks tend to change over time as they with internationalpetroleum industrypractice; adapt to changes in the country's specific circumstances, the level of national and To grant tax and customs exemptions and internationalcompetition, aswell asthe improved free transfer of funds; understanding of the country's geological potential and of other technical matters. To encourage the private sector to play an important role in all stages of hydrocarbon The MOMensures the application of contracts, development; and formulates policies and implements the government's decisions on the pace of To encourage the development of marginal petroleum sector development by making fields through the reduction of investment available areas for exploration, and granting requirementsby: rights to explore for, develop and produce hydrocarbons. In carrying out its duties, the - Public access to existing infrastructuresat MOM is assisted by the PEPA, the upstream nominal rates; regulatory agency. The agency manages the country's data bank, supervises oil companies' - Creating new investment opportunities activities in the country, prepares and conducts jointly or severally with private sector in licensingroundsand negotiatethe terms of PSAs upstream projects (PSA, gas, petroleum on behalf of the MOM. services) as well as downstream projects (transportation, refining); The State, through its national oil company, participates directly in the sector. A negotiable - Facilitating the transfer of technology by percentageinterest, carriedthrough exploration participating directly in petroleum and development, is generally reserved to operations through carried interests; the national oil company107under the most recent PSAs. - Encouraging the Yemenization of The sector policyis publiclydisclosed108and aims international companies operating in at diversifyingthe sources of revenues. The key the country by developing plans for actions envisaged by the government to the replacement of the expatriate accomplish the objectives of the sector policy workforce; and are summarized below: - Improving the.control of petroleum To increase proven reserves to balance the costs through the establishment of decline in existing fields; operating committees. lo' YOGC is a SOE that intervenes in different stages of the sector value chain through its six affiliates. In particular, Yemen Company(YC) holdsproductionrightsinblocks3253 andina numberofexplorationblocks; YGCisresponsiblefor the development and utilizationof the country's gas resources; YOC isresponsiblefor managinggovernmentparticipationin oil-producingJVs with internationalcompanies; YPC is responsible for the countrywide distribution and marketingof petroleumproducts (except LPG); ARC and MRCare the two government-ownedrefineries. Io8See PEPA's web site for more details at www.pepa.com.ye. REPUBLICOF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK Procedures for the Award of items that affect the take,l12 other award their Petroleum Rightslo9 acreage on the basis of the work program, in some other countries"everything is negotiable." In Yemen, the right to explore for and produce There is no model bidding system or strategy oil in specific areas is generally awarded to the for governmentsto adopt. Decision on the most contractorsthroughlicensingrounds. Unsolicited appropriate bidding system can be supported expressions of interest and direct award are by an understanding of general market also possible. conditionsaswell as of the relativeprospectivity Periodically, the PEPA publishes a list of open of the areas,on offer. Ultimately the resource blockswhich the government intendsto offer to allocation is efficient if it satisfies the national potentialinvestors. This mayincludeexploration policy objectives. blocks and producing blocks.' lo After receiving an expression of interest for open blocks and Intuitively, a government would maximize its relevantcompanyinformation(includingaudited share of benefitsby"letting the marketwork."'13 financial statements), potential investors are However, when almost all the parameters are granted accessto the relevanttechnical data.' '' negotiable, comparing alternative offerscan be A Memorandum of Understanding (MoU) a difficult exercise. Estimates of oil/gas prices, containing all relevant commercial terms is prospect sizes and recovery factors, success negotiated between the PEPA and the potential ratios, production and engineering solutions, investors. After signature, the parties have costs and investments, discount factors, and so approximatelytwo months to finalize the terms on, and so forth are necessaryto determine the of the PSA. discounted cash flow and expected monetary value associated with alternative proposals A "model" MoU highlightsall negotiable terms. (thatis, the likely value of government take and These are listed in Table 4.3. government participating interests). Even with To award, acreage-producing countries use good knowledge of the relevant domestic and differentsystems. Some countries haveadopted international markets, these estimates will rather rigid systems with very limited biddable inevitably involve a certain level of subjectivity. - lo9 The procedures for the award of rights and the government's role and authority are normally set forth in a country's petroleum law (complemented by regulations as appropriate). In the case of Yemen, information on awarding procedures and government authority has been collectedthrough websitesearch and interviewsof governmentofficials and industryoperators. Thetransparency of the bid evaluation procedure remains to be investigated. ' l oIn case of producing blocks, service contracts may be considered. 11' Data fees and other access condition may apply. 112 The division of profit between investor and government is called the "take." 113 Licensing rounds have contributed to increase competition among oil companies to the benefit of host governments. With new companies coming into the market and acreage being offered in areas that are perceived as more difficult, this has in many cases resulted in overbidding. By letting oil companies compete against each other, host governments are spared from the difficult task of determining "what the market can bear." But, as some governments have come to experience, the best bid on paper is not always a workable one. ANALYSIS O F THE KEY FEATURESOF PROPOSED LEGALAND FISCAL TERMS FOR THE EXPLORATION, DEVELOPMENT, AND PRODUCTION OF HYDROCARBONS Table 4.3: Model MoU: Biddable Tenns Parameter Bid Items Exploration Period Lengths and Number of Subperiods First Exploration Period Term Work Program Commitment Minimum Expenditure Relinquishmentof Obligations First Exploration Period Extension Term Work Program Commitment Financial Commitment Second Exploration Period Term Work Program Commitment Minimum Expenditure Relinquishmentof Obligations Second Exploration Term Period Extension Work Program Commitment Financial Commitment Royalties Royalty rates are linked to a sliding scale based on reaching daily production targets (oil, gas114) Bonuses (to be paid annually for Signature the duration of the contract) Commercial Discovery (oil, gas) Daily ProductionTargets (oil, gas) Training Institutional Social Development Bonus Research and Development Contribution Data Bank Development Contribution Cost Recovery Limit Expressed in percentage of net production Amortization Rates Maximum rates for Exploration, Developmentand Operating Expenditureset in the MoU Excess Cost Oil Percentageto be paid directly to the State Production Sharing Sliding scale linked to reaching daily production targets (oil, gas) Carried Interestthrough In percentage of total exploration and Exploration and Development production interest Duration of Production Phase Twenty years set as maximum duration in the MoU115 Duration of Production Phase Five years maximum duration. New contract terms to be Extension negotiated Fixed Tax 3% of exploration expenditure 'I4In the most recent version of the model MoU, the royalty rote for gas and LPG production is flat. Thismodel MoU is being used as basis for the negotiations between the 2006 licensing round's successfulbidders and the MOM, which are scheduledto start by mid-April 2007. "51n the most recent version of the model MoU, the duration of the production phase for gas is subject to discussion between the MOM and the investors during the negotiation of the relevant PSA. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Elements of the 2006 Model PSA in case of emergency that impact safety, the environment and the interestof the parties1l9 In this section, the 2006 Model PSA116is could be gathered under specific clauses. analyzed bothon itsown merits, and in relation This would improve the clarity and facilitate to industry good practice. The agreement was the oversight of the contract;120and evaluatedwith respectto itsclarity, transparency, comprehensiveness and attractiveness to The right to explore for andproducegas. Oil investors. The structure of the fiscal terms was and gas are quite different in terms of their evaluatedinterms of its respectto the principles exploration and development thresholds.12' of flexibility, neutralityand stabilitysummarized Gas discoveries are often noncommercial in Box 11,and itsconsistencywith the obiectives unless they contain a high percentage of of the government petroleum sector policy. liquids, they are close to an existing market, or they are very large. In addition, the cost of Overall, the 2006 Model PSA exhibits a good developing a gas field in some order of coverage and content and interpretation does magnitude greater than that of developing not presentparticular diffi~ulties."~To increase an oil field. Technical and commercialfactors its attractiveness to international investors and influence the lead time from exploration to to reflectthe most recenttrend in industry good development of a gas discovery that is practice, improvements could be considered in normally substantially longer than the lead the organization of its sectionst1l8and in the time for an oil discovery. The world average following areas: lead time from exploration to development The contractor's rights, obligations and of gas discoveries is approximately the principles underlying the conduct 10 years.lZ2For this reason, the duration of of operations, including contractors' the production rights in a gas discovery is authorization to act as deemed appropriate generally between 30 and 35 years.lZ3 - '16Apaper copy of the 2006 Model PSAwasprovided to the World Bank in the spring of 2006. A new model PSAis undergoing the final stages of preparation. Itsfinalization is expectedby mid-April 2007. Thenew model PSAis expectedto contain provisions that are specific to gas and LPG production. At the time of preparation of this report the new model PSA was not available. "'The language could be improved in some parts of the contract. In some cases, this is likely to be the product of imperfect translation from Arabic to English (for example, Articles 2.1.4, 9.1.1, 21). The following are examples of potential language improvement: (a)redundancies could be eliminated by using terms that are defined in the PSA (for example, because all activities that constitute "Development" are defined in Article 1.73, the last recital could be simplified); (b)inconsistenciescould be clarified (for example, Articles 20.1 and 20.2.4, Articles 25.7 and 25.4); (c) wording could be more accurate when important rights or important potential defaults are considered; (d) in the recitals, the contractor should represent that it has the financial resources, technical competence and professional skills necessary to carry out the Petroleum Operations; (e)Article 2.1.4 (a)should ensure that the relevant rights and obligations accrued prior to termination shall survive, and so on, and so forth. "BFor example, provisions that apply in different phases of exploration and development, general obligations of the contractor, general obligation of the government, and so on, and so forth could be grouped and cross-referencedas appropriate. Thiswould improve the overall clarity and reduce the likelihood that mistakes might occur in case of amendment to theseprovisions as such amendment would only need to be made once. This is regulated under Article 29.6. However, the protection of the environment is not specifically considered among those actions which the contractor may take in emergenciesand for which the relevant costs are allowed for cost recovery. In Annex F, accounting procedures, Article 2.13.2, emergency expenses to protect the environment appear to be allowed for cost recovery. To avoid discouraging the operators' responsiblebehavior, the wording should be clarified, and thesecosts should be allowed for cost recovery. '20Examplesin this direction could be found in the model PSA of several countries, including Angola, Gabon and Oman. 12'In some regions, development thresholds for gas can be between 5 and 15 times the size needed for an oil development. '"Daniel Johnston, 2003. '" Roughly 10years longer than the typical production phase for oil discovery. ANALYSIS OF THE KEY FEATURES OF PROPOSED LEGAL AND FISCALTERMS FOR THE EXPLORATION, DEVELOPMENT, AND PRODUCTION OF HYDROCARBONS Many countriesaretightening their policieswith the commercial arrangement: the State's share respect to gas. Because it is very difficult to in the GDA shall not be less than 60 percent, anticipate how large and rich in liquids a gas and the contractor shall bear all costs relatedto discovery might be, and which development the project which shall be cost recovered from option will be most suitable, many contracts the annual gas revenue. contain a very simple gas clause that provides for the parties- government and investors- to If nonassociated gas is discovered, similar negotiatethe gas developmentterms in case a provisions apply. Except that, if the contractor discovery is made. In some cases, general fiscal and the government do not reach agreement terms are set in the contract. This is normally on a gas development projectwithin six months the case in countries that have already from discovery, then the contractor shall developed a domestic market or have well relinquish the relevant portion of acreage to established export routes. the government without compensation. The contractor is, however, allowed to recover In Yemen, the State owns both associated and all costs incurredbyitas exploration expenditure nonassociatedgas. To date, the contractor does from cost oil. not have the right to produce gasIz4but, it is allowed to use associated gas in petroleum Comparedto othercountriesthataim at creating operation and for pressure maintenance, free a gas sector, the provisions of the 2006 Model of charge and subiect to the MOM'S approval PSAdo notprovideany particularencouragement (which approval shall not be unreasonably to potential investors. In addition, in the case of withheld). Ifthe MOMso requires, the contractor associated gas, the requirement for a minimum shall deliver associated gas to the State at the 60 percentgovernment-carriedinterestinthe gas point of separation. Costs associated with the development set forth in the 2006 Model PSA production and delivery to the MOM shall be may not be commercially viable. Given the paid by it to the c~ntractor.'~~Associated gas current lack of domestic market opportunities that is not used in petroleum operations or by andthe lackof infrastructure, a six-month period the State can be treated by the contractor in (the deadline set forth in the 2006 Model PSA) accordancewith good industrypractice (flaring for evaluating gas market opportunities and policy is not explicitly addressed in the 2006 negotiating the terms of a GDA may prove too Model PSA). short for both the contractor and the MOM. In order to attract investors and accelerate the The MOMhasthe rightto enter into GDA(s)with creation of a gas market, a more collaborative third partieslZ6for the export and sale of approach, flexible fiscal terms or other targeted associated gas and/or its delivery to the MOM incentives may need to be ~onsidered:'~' for domestic use, provided that the contractor shall be granted six months to discuss and Health, safety and environment protection. negotiatesuch agreement. The 2006 Model PSA This subject is regulated under Articles 11.6 sets some boundary conditions with respect to and 18.1. Although there is a general 12' Thenew model PSA is expectedtoaddressexploration,developmentand production rights for associated ond nonassociatedgas. lZ5 Often the contractor is ollowed to recover these costs as part of the cost oil. The Model PSA does not specifically allow for set-offs. lZ6 This may present some challenges if the gas contract between the State and third parties calls for delivery schedules and technical solutions that are not fully in line with the contractor's reservoir management. To this end, the Model PSA offers some degree of protection to the contractor by mandating thot the operations under the GDA shall not interfere with the contractor's petroleum operations. 12' Incentives are discussed in Chapter 5 of this report. REPUBLICOF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK requirementthat the contractor respects the use of privately-owned or occupied land or laws and regulations applicable in Yemen buildings are set out in Article 29.5. These with respectto environmental protectionand allow the contractor to directly negotiatewith safety as well as industry standards and the affected party on terms and conditions practice'28with respect to environmental not substantially more onerous than those matters, the environmental assessment, applicable to similar transactions in the impact assessment and mitigation plan are relevant area and resettlement plans. not made a condition for approval129of the If needed, compulsory sale of the relevant relevantfield development plans and for the asset may be ordered by the government grant of the relevant licenses and permits.130 after payment of reasonable compensation. The respect of international safety and labor No difference is made between temporary standards has not been specifically and long-term use; mandated.131The extent to which this might be considered part of "good industry Ownershipof data andconfidentialityshould practice" has been the subiect of debates be brought in line with international among industry experts. Sureties to cover standardsand practice. In particular, it is not potential environmental liabilities have not standard practice to deny the use, by the been addressed in the 2006 Model PSA (or contractor, of information acquired during in the accounting procedure annexed to it). theterm of the contract, when such useoccurs The accounting and cost recoverytreatment after the expiry of the contract and for the of environmental mitigation structures and contractor's internal purposes. In defining equipment could also be more clearly what constitutes confidential information, specified. The principlesfor land reclamation the use of the contractor's proprietary are not specified in the 2006 Model PSA; technology should be given adequate consideration. Disclosure to regulatory Landuse, right of access, compensationand agencies, security commissions, or stock resettlement. Land use and right of access exchanges is not uncommon in the sector. In to roads and facilities are regulated this case, confidentiality obligations need to under Articles 29.1, 29.3 and 29.4. be adjusted to accommodate these entities' The principles for compensation in case of operating procedures. Confidentiality and lZ8The contract refers to rules and regulations applicable in the international petroleum industry. Reference to standards and practice would be more appropriate. The authority far reviewing and approving environment impact assessment and mitigation plan is not specified in the 2006 Model PSA (however, this might be specified in the relevant environmental law). Countries have adopted different approaches: some utilize a central approach where all matters related to environment are regulated in the general environmental law, others have adopted a sectoral approach where each sectoral law includes provisions related to environmental protection. Whatever the approach, the best practice is toseparate the environmentalapproval processfrom the licensing function even when the environment impact assessment is required to be submitted to the Ministry of Petroleum as part of a drilling authorization or field development plan application. 130The foundation of appropriate environmental protection is to know the facts and options regarding alternative resource managementstrategies, alternative locations,operational and mitigation alternativesand implementation options. TheEnvironmental Assessment is the instrument that helps define such facts and options. Only then can appropriate choices be made regarding prevention and/or mitigation of the impad of petroleum activities. A minimum standard of good practice could be the introduction of the requirementto submit: (a)an EnvironmentImpactStudyin connection with any development plan; and (b)a decommissioning plan - including environment and safety considerations -upon cessation of exploitation activities. 13'Severalcountrieshave adopted either extensive regulations cross-referencedin the relevant PSA and/or have included the basic principles of in their PSAs.Angola's, Gabon's, Pakistan's, Qatar's PSAsset examples of different policies in setting the boundary conditions for proper health, safety and environment protection minimum standards. ANALYSISOF THE KEY FEATURESOF PROPOSEDLEGALAND FISCALTERMS FORTHE EXPLORATION,DEVELOPMENT, AND PRODUCTIONOF HYDROCARBONS disclosure rights and obligations are fairly interests are clearly aligned (although there standard terms in the industry. Example can are varying degrees of incentive depending be drawn from other countries' PSAs and/or on the choice of fiscal terms). The 2006 from industry standard confidentiality Model PSA's expenditureapprovalthresholds agreements. 132 In addition, provisions could afford greater freedom of operation requiring transparency on State revenues to the contractor, as other costs control and received from hydrocarbon activities in supervision mechanismsare provided for in accordance with internationally accepted the contract and in the cost recovery norms could be ~onsidered;'~~ mechanism.136This would reduce both the government's cost of supervision and the Cost control procedures. Host governments contractor's cost of compliance; havea clear interestinensuringthat the costs are kept as low as possible. Normally, Unitization. In case of discovery of contracts provide for various forms of hydrocarbons from a structure extending oversight and control mechanisms. across the boundary of adjacent contract Management committees, procurement areas, the State has the right to ensure that, procedures, budget approval and audits in the interest of economy, efficiency and are examples of these rne~hanisms.'~~ conservation of the resource, the common The thresholds for approval of expenditures deposit is developed as a single unit, on a are particularly important: low thresholds noncompetitive basis. Common practice is affect the efficiency of operation^.'^^ During to include in the law a provision giving the the exploration period, there is a clear competent authority the right to order the incentive for the contractor to keep costs affected contractors to develop such area down: if no discovery is made, exploration jointly under a unitization plan approved by expenditure will not be recovered. If a the competent authority. As Yemen does not discovery is made, the cost recovery have a petroleum law, the right of the MOM mechanism allows the contractor to recover to order unitization should be expressly its investment if sufficient revenue is provided for in the 2006 Model PSA; generated. If a cost recoverylimit isimposed, the incentive to control costs is even greater. Abandonment procedures and related Thus contractors' and host governments' liabilitieshavenotbeenspecificallyaddressed '"The wording used in theAngola's, Qatar's, Pakistan's model PSAs and the American Institute of Petroleum Negotiators (AIPN) standard confidentiality agreement are examplesof generally recognized industry practice. 133Countriesthat have adopted the disclosure standardsenvisaged by the ElTl have included specific wording in their legislation and/or in PSAs [Nigeria, S60 Tom6 and Principe, Timor-Leste,Mauritania). lY In addition, nonoperator partners also exercise their control over the operator's management of operations. '35Thresholdsof US$500,000 or US$1,000,000 are not uncommon. '36Asnormal in contractual agreementswheredirect participation of the government is involved, the 2006 Model PSAprovides for the establishmentof joint committees. Theexploration advisorycommitteeis tasked with reviewingthe work program and budget submitted by the operator and providing its advice, before work program and budgets are submitted to the MOM. Contracts related to the performance of the work program exceeding a threshold to be negotiated between the contractor and the MOM shall be approved by the MOM. Statement of expenditureshall be submitted to the MOM each quarter for review [this does not prejudicethe MOM'Sright of audit). During the development phase, control procedures are stricter.An operating committeeis set up to, inter alia, superviseimplementationof the developmentand production operation, review and approve the work programs and budgets. Theoperating committee availsitself of the assistanceof several subcommittees.Its internal procedures are annexed to the 2006 Model PSA. Service contractswhose value is higher than US$250,000 in case of competitive tender, or higher than US$50,000 in case of single source/controh that are not awarded to the lowest bidder shall be approved by the MOM. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK inthe 2006 Model PSA.'37This is particularly relatively short time frame granted to the important astitle to land passesimmediately contractorto evaluatethe discovery, this could to the MOM, and title to fixed and movable be particularly challenging, especially when assets is transferred automatically as they small accumulations are involved that are recovered. Although abandonment could be economically exploited as part of is a normal procedure under standard a group of fields, and when the appraisals oilfield operating practices, abandonment of such fields cannot be completed at the obligations are normally addressed in the same time;'39 relevantcontracts. The accountingtreatment of abandonment-relatedexpenses, including Assignment of rights and obligations is possible funds, would also need to regulated under Article 20. The ability to be specified; transfer all or part of their rights and obligations in a contract area is very Insurance and indemnification requirements important in the petroleum industry where and liabilities could be set out in a separate companiesnormallypartnerto decreasetheir clause. The 2006 Model PSAdoes not impose risks. Generally, transfers to affiliated minimum requirementfor insurance. In line companies do not require particular with industry practice and with generally formalities. Transfersto third partiesare more accepted contract principles, balance and complicated, as the host government needs equity should be sought in defining the to ensure that the assignee has the financial parties' liabilitiesand indemnities, especially (and technical if the operatorship is inthe caseof sole riskoperationscarried out transferred) ability to fulfill the requirement by YGC on behalf of the MOM; of the contract. Normally, the assignor is not required to guarantee the obligations of the The cases in which the MOM can conduct assignee, especiallywhenthe assignee is not sole risk operations in the contract area an affiliated company;140 and should be definedwith a view to minimizing disincentives to the contractor's group. For Assistance from the MOM and conflict of example, the 2006 Model PSA provides for interest. The privileges of the MOM'S the MOMto have the option to conduct sole personnel are detailed in Article 16. risk operations if the contractor fails to The provision of assistanceto the contractor declare commercialitywithin the time frame bythe MOMis mentioned in various parts of indicated in the ~ 0 n t r a c t . lGiven the ~ ~ the 2006 Model PSA. To improve clarity and I3'Annex D,which details the termsof the irrevocable letter of credit in favor of the MOM, makes reference to the obligation of the contractor to clean up work sites (it is not clear from the wording whether this refers to reclamation, abandonment, or both). However, no financial guorantee appears to be attached to such obligation. Therefore, it is unclear how the letter of credit could provide coverage. In line with international good practice, the use of a performance bond or abandonment fund specifically related to abandonment operations could be considered. 130Themaximum lead time for discoveryto declaration of commerciality is defined as the shorter between nine months and 30 days after the completion of the relevant appraisal wells. A 24-month lead time is not uncommon in the industry: seasonal factors, unforeseentechnical and engineering problems, among others, may affect the duration of appraisal. Especiallywhen cast recovery limits exist, the contractor will have an incentive tooccelerate the declaration of commerciality and start field development. In these cases, the government's concern that potentially commerciol fields are not going to be expeditiously developed by the contractor may not be entirely warranted. 139Angola'smodel PSA is o good example of alternative wording. I4OMore standard wording can be found, for example, in the model PSAof Angola, Pakistonand Qotor. Industry standard wording for assignmentof rights and obligations could also be considered. ANALYSIS OF THE KEY FEATURES OF PROPOSED LEGALAND FISCALTERMS FOR THE EXPLORATION, DEVELOPMENT, AND PRODUCTIONOF HYDROCARBONS in linewith good practice, the MOM'Sduties The fiscal terms set forth inthe Model MoU and and resp~nsibilities'~'and conflictof interest in the Model PSA include some degree of provision^'^^ could be grouped under a flexibility, but this may not be sufficient to specific Article and more clearly defined. accommodate a variety of possible exploration and development condition^.'^^ Production- Although many elements of the fiscal package based sliding scales provide a greater share of are negotiable, the Model MoU and the 2006 royalties and profit oil to governments at higher Model PSA provide the general structure of production rates. However, this type of the fiscal policy and some boundary arrangements is irresponsiveto price and cost conditions for setting the level of the variations, and does not accuratelycorrelateto relevant parameters. These are summarized the project's return on investment. In addition, in Table 4.4. Table 4.4: Fiscal Parameters of the 2006 Model PSA and 2005 Model MoUlU Bonuses Signature $ Declarationof Commerciality Oil $ Gas $ Production Oil Gas at Bopd $ at million scf/d $ 25,000 250 50,000 500 75,000 750 100,000 1,000 150,000 1,500 Royalty Oil Gas Bopd % millionscf/d % 0-25,000 3 0-250 3 25,000-50,000 5 250-500 5 50,000-75,000 6 500-750 6 75,000-100,000 8 750-1,000 8 > 100,000 10 > 1,000 10 Cost Recovew Limit ~. - % of Net Production RecoverableCosts Operating Expenditure 100% Exploration Expenditure 50% DevelopmentExpenditure 50% Nonrecoverable: Bonuses, training, interestfees and commissions on loans and guarantees See the Model PSA of Angola and Qatar as examples. '42Conflict of interest provisions are generally set forth in a country's petroleum law. Because Yemendoes not have a petroleum law, it would be advisable to clearly detail those situations that constitute conflid of interest as well as unlowful payments. ld3Thecriteria to be used by the government in ranking and evaluating the 33 bidding elements contained in the Model MoU and the relative importance of the bidding parameters are not explicitly mentioned. lU It is worth noting that in the Model MoU that is being used to negotiate the terms of award of the blocks included in the 2006 licensing round, the sliding scales used in the determination of royalties and profit-sharing for gas have been amended to refled a wider array of reservoir deliverability rates. See Chapter 5 for a discussion of the possible implications on contractor's and government's takes. REPUBLICOF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Bonuses Excess Cost Oil % Profit Oil Split Oil Gas Bopd Ministry Contractor million scf/d Ministry Contractor Participating Interest Oil Gas Carried through exploration and development % For development of associated gas, the State participation is 60% (full carry) Taxation Paid in lieu by the Ministry on behalf of the contractor Ring Fencing None Other Valuation of Crude Oil Arm-length market price FOB point of export Assignment of Interest 15%capital gain tax if cash payment is involved Employee Personal IncomeTax 3%of exploration expenditure for staff working on exploration activities 15%of actual salary for staff working on development related activities -- "excess cost oil" can be quite a difficult term to threshold~'~~mayincrease. To dealwith all these bid, especially when the potential investor is uncertainties, R-factor or returnon investment- evaluating a new play'45or when the contract based scales could offer a much more flexible area is located far from existing suitable instrumentasthey are able to adjust moreeasily infrastructure. The proposed structure of to a number of unknown circumstances thus terms may have several consequences: the providing for a more equitable'47and stable148 governmentmaymissout onthe potentialupside profit allocation arrangement. Since the of the project; the investors' expectations of real performance of a fiscal system is affected by costs and prices may influence its production many variables (size and distribution of decisions; exploration and development production in a given geological province, '45 TheModel PSA,Annex C, MinimumWorkProgram and Expenditure,requiresthat threeexplorationwellsbe drilled and evaluated in the basement.Although a discovery wasrecentlymade, it maystill be early daystojudge theprospectsfor such an unconventional and challenging new play. In similar cases, various governments (for example,Australia, Canada, New Zealand and the United States) have adopted targeted incentives that have allowed them to influence the contractor's investment decisions by partially compensating for increased exploration and/or development risk. 14* Prospects that might have otherwise been exploredor fields that might have otherwise been developedmay not get developed. 14' That is, taxation would be based on the contractor's ability to pay. 14% Becausethe fiscal burden changes in line with changesin project economics, the terms of the PSA would not need adjustment. ANALYSIS O F THE KEY FEATURESOF PROPOSED LEGAL AND FISCAL TERMS FOR THE EXPLORATION, DEVELOPMENT, AND PRODUCTION O F HYDROCARBONS technical parameters, economic variables, and provide an indication of the relativeimpact of a so on, and so forth), modeling of alternatives system. To gain a broader understanding of a would be necessaryto ensure that the chosen system and of how it comparesto other systems, system or systems will be flexible enough to it is necessaryto analyzethe system as a whole. respond to the most likely scenarios and will In addition, many elements of contracts and provide a result in line with the strategic concessionagreementsthat do not get captured objectives of the country's petroleum p01icy.l~~ in the fiscal parameters affect the efficiency of operations and the investor's return on Table 4.5 summarizes the investment.151 These are difficult to outlined in this paragraph. Therefore, comparison of licensing terms in Other Countries' Terms different countries or geological provinces is normally madewith referenceto the main fiscal Assessingthe impactof differentlegal and fiscal variables. Table 4.6 summarizes the key systems on investment decisions is not an easy elements of the petroleum fiscal systems for a task.150Eachelementtaken in isolationdoes not selected number of countries.152 Table 4.5: 2006 Model PSA: Suggested Improvements Topic Recommendations Contractor's Rights, Obligations and Clarity could be improved by gathering the topic the Principles Underlying the Conduct under a common set of clauses of Operations Right to Explore for and Produce Gas Incentives could be designed to attract investors: These may include the followinn: ~ o n ~ eduration of exploratbn and ; production periods Lower minimum percent government carried interest.inthe development of associated gas Longer evaluation period Flexiblefiscal terms Health, Safety and Environment Environmentalprotection should be strengthened. Protection In particular: Environmental assessment, impact assessment and mitigation plan should be made a condition for approval of the relevant field development plans and for the grant of the relevant licenses and permits The respect of international safety and labor standards should be specifically mandated '49Althoughnecessarilyasimplificationofreality, modelingwillalsobeusefulin definingthe boundaryconditionsofthe systemfor contractnegotiationpurposes. "Olt is important to note that the effect of many nontax componentsof a legal and fiscalsystem is difficult to measure as it very much depends on the complexity of the projed and on the ability of the investor to operate efficiently and effectively, in the particularenvironment. With regard to the tax components of a system, tax treaties can significantlyaffect an investor's fiscal obligations. Therefore, different investors may bear differenttax burdensdependingon their homecountry tax law as well as on their tax minimizationstrotegies. 15'Forexample: hiringrequirements, unusualprocurementlimitations,permittingleadtime, visa requirements, customsprocedures, trainingandlocalprocurementobligations, data access andmonagementfees, crude oil andgas valuation rules, nonrecoverable projedcosts, and so on, andso foth. Is2NOrankingis intendedor attempted. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Topic Recommendations Sureties to cover potential environmental liabilities should be addressed in the Model PSA The accounting and cost recoverytreatment of environmental mitigation structures and equipment should be more clearly specified The principlesfor land reclamation should be clearly defined Land Use, Rightof Access, The principles and basis for compensation could be Compensation and Resettlement more clearly specified with particular referenceto the difference between long-term and temporary land use. Ownership of Data and Confidentiality This should be brought in line with international standards and practice, with particular referenceto the following: The use by the contractor of information acquired during the term of the contract The definition of what constitutes confidential information The limitations imposed on disclosuresto regulatory agencies, security commission, or stock exchanges In addition, provisions related to the Extractive IndustryTransparency Initiative (EITI)could be included Cost Control Procedures The cost of supervision and the cost of compliance could be reduced and the efficiency of operations could be increased by introducing higher thresholds for approval of expenditures Unitization The right of the MOM to order unitization should be expressly provided for in the Model PSA Abandonment Abandonment procedures and related liabilities, and the accounting treatment of abandonment-related expenses, should be specifically addressed in the Model PSA Insurance and Indemnification Minimum requirementsand liabilities could be set out in a separate clause Sole Risk Operations These should be defined with a view to minimizing disincentives to the contractor's group Assignment In line with international practice, the assignor should not be required to guarantee the obligations of the assignee, especially when the assignee is not an affiliated company Assistance from the MOM and To improve clarity and in line with good practice, Conflict of Interest the MOM'S duties and responsibilitiesand conflict of interest provisions could be grouped under a specific Article and more clearly defined Fiscal Terms More flexibility could be introduced to accommodate different investment opportunities. The use of R-factor or return on investment-based scales could be considered ANALYSISOF THE KEY FEATURESOF PROPOSEDLEGALAND FISCALTERMS FORTHE EXPLORATION, DEVELOPMENT, AND PRODUCTIONOF HYDROCARBONS Table 4.6: Featuresof Petroleum Fiscal Regimes in Selected Countries Country Royalties Production-sharing Income Tax Resource Investment State Rate Rent Tax Incentives Equity Algeria 10-20% 50-85%(P) None None None 51% -- -- -- -- Angola 0% 50-9096M 50% None Yes (E) 20% Benin 12.5% 55% None None Yes (E,U) 15%(C) Brunei ... None 55% None Yes (A) 50% Cambodia 5-12.5% 40-65%M 30% None Yes (E) None Cameroon Negotiable None 57.50% None Yes (0) 50%(C) -- -- -- Chad None 40-65%(P) None Yes (E,I) None Congo B 15% 30-70%(V,P) 35% None Yes (0) 10-15% Cote d'lvoire None 60-90%M None None Yes(0) 10-12% Dubai 12.5-20% None 55-85% None None None Egypt, Arab Rep. of None 70-87%M 40.55% None yes (1) None Equatorial Guinea 10% 25-80%(P) 25% None Yes (E,H,I,O) 5-2596 --- - -- Gabon 10% 65-85%M None None Yes (E) 15%(C) Indonesia (post 1988/89) None 71.16% 48%(eff.) None Yes (A, I, Cr) 10% Malaysia 10% 50-70% None 40% Yes(A, E, U) 15% (C) Nigeria Offshore 4-8% 20-65% 50% None Yes (E,Cr) None Oman None 80% 55% None None None PNG 2% None 45% 20-2596(P) Yes (I, Cr) 22.5% (C) Qatar None 55-70%(V, P) None None None None South Africa 23% None 30% 40% Yes (O,U,I) 20% (C) Thailand 5-15%(P) None 50% None Yes (E) None Philippines None 60% 32% None Yes (E) None Tirnor Gap -ZOCA None 50-70%M 48%(eff.) None Yes (I, Cr) None Yemen 3-10% 70-80% None None Yes (E, U) None Adapted from Baunsgaard (2001) Sources: Barrows (7997) Coopers & Lybrand (79981, Pn'cewaterhouseCoopers (1999), Otto et a1 (20001, Johnston (2003), Web Sites of country sector ministries. Legends: (1) Fiscal terms linked to volume of production M, Years of production (J), Profitability indexes, R-Factor, ROR, Realized profitability (P). (2) lnvestment incentives: Tax holiday (H),Accelerated depreciation (A), Tax credit (Cr), Current expenses of exploration and/or development costs (E), Exemption of imports of equipment and capital goods (I), Unlimited loss carry forward (U), and other (0). (3) The maximum equity share that the government can opt for, if (C) on a carried basis. REPUBLICOF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK Conclusions elements considered by potential investors in comparing investment opportunities. Countries compete with each other to attract foreign investment to develop their natural To develop a fiscal system that is able to resources.To achievethis, they mustassesstheir allocate risks equitably, policy makers need positioninthe global marketplaceand evaluate to take into account the divergent interests of their particular situation, boundary conditions, companies and governments. Risks can be concerns and obiectives. substantially different for different proiects and countries and, over time, a fiscal regime Although not all countries have made the same that provides optimal outcomes under all legal and regulatory choices, nearly all have circumstances is not likely to be developed. established sector-specific legislation and Although this may justify a case by case regulation in line with their constitution and approach, this would hardly be efficient given with the rest of the country's body of laws. the usually large number of projects and the One advantage of this approach is its limited administrative capacity of the host transparency and its objectivity: by establishing government. It is, therefore, desirable to build the boundary conditions for the award of enough flexibility into a system to allow for petroleum rightsand defining the authority and automatic adjustments to unforeseen changes proceduresfor such award, systeminefficiencies and to minimize the need and cost of and the scope for discretional behavior are negotiations and/or renegotiations. greatly reduced. Finally, it is important to note that good legal Whether contractual or concessionary systems and fiscal design without complementary are used, the clarity and simplicityof the terms, institutional structures may still not achieve the the objectivity of the rules and of their desired goals. The design needs to be within enforcement, the neutrality, equity, efficiencyand the administrative and audit capacity of the stability of the fiscal terms are among the key relevant institutions. 5. Encouragingthe Development of Gas Reserves Introduction Given the high volatility of gas price compared to most commodities, possible risk mitigation The energy market is evidently respondingto the measuresaimed at preservingthe year-to-year changinggas supply conditions, and exploration consistencyingovernmentrevenuesare outlined activityisexpectedto pickup. However, the speed in the last part of this Chapter. andextentof that responseina particularcountry maybe constrainedby its specific circumstances. Barriersto the Development of Gas The identification of gas resources is not a Explorationand ProductionActivities sufficient condition to ensure a greater use of Although oil and gas are oftenfound inthe same gas: transmission infrastructure and regulatory reservoir, they are significantly different. Unlike framework often need to be developed well in oil, natural gas: (a) cannot be inexpensively advance of anticipated demand.153 stored in large quantities; (b)sophisticated and The development of a natural gas market is expensive infrastructure is required to deliver it particularlyimportantto GOYfor its potential to to the end users; (c) transportation costs, supportthe creation and growth of the domestic measuredonthe final priceto the customer, can industrial sector. In addition, revenuefrom gas be 10times higher than for oil; and (d)there is exports may contribute to partially offset the no world gas market,155 hence no world decline in government revenue from currently standard price such as WTI, Brent or D ~ b a i . ' ~ ~ producing oilfields. As a consequence: This Chapter analyzes the potential barriers to The lead time to development of a gas field the development of gas E&P activities, provides can be considerably long;157 an overview of the policiesthat have been used inother countriesto promote these activities and Investment in development and production explores their applicability in Yemen.'54 of gas usually cannot go ahead without a 153ASoutlined in Chapter 2, natural gas pricing is of critic01 importance in determining the size and shape of a country's internal gas market. When not left to the market, pricing should encourage: (a) gas consumption, by providing incentives for energy users toswikh to gas; and (b)gas produdion, by giving investors a fair and reasonoble return. In other words, gas pricing should ensure the viability of each link in the gas chain. I" The analysis assumes that the terms applicable to oil and gas exploration and development are those set forth in the 2006 Model PSA and the 2005 Model MoU provided by the authorities and presented in Chapter 4. Is5Approximately, 85percent of the gas consumed today in the world is produced locally. ls6Prices in the U.S. market are linked to the HH price and adjusted for distance and quality of supply. Prices in Asia and Europe are normally a fundion of oil prices, and have been historically higher than U.S. gas prices (with short-term exceptions). '"World average lead time from exploration to development is approximately 10years (D. Johnston, 2003). REPUBLIC O F YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK long-term commitment between producer infrastructure and the financial environment and buyer;15* and are commonly cited among the factors affecting gas exploration and development Small gas markets are difficult to develop, activities. and small gas discoveriesare normally hard Table 5.1 identifiessome of the factors that E&P to c~mmercialize.'~~ companies are likely to consider in evaluating In addition to the foregoing, the availability investment opportunities, the potential of skilled workers and specializedequipment, barriers to investment in Yemen and possible complex land access rights, the lack of options to address these barriers.160 Table 5.1: PotentisalBarriersto lnvestment in Gas E&P in Yemen E&PInvestment Barriersto Investment Possible Options Factors Prospectivity Access to quality and Audit existing reserves quantity of geotechnical Analyze available Geophysical and related and Geological (G&G) information data, acquire new data/reprocess existing data, prepare gas prospectivity report and increase promotional activity Favor/encourage data acquisition, processing, reprocessing and interpretation over wild cat drilling in evaluating bids/establishing work program obligations. Exploration and Relativelyhigh costs of Facilitate multiparty work Development Cosf exploration and programs to improve development may be due economies of scale to geographic isolation, complex geological structures, lack of economies of scale (and limited competition between service providers) lSBIn the gas industry, the developer of the reservoir and the end user of the gas are linked by a chain that connects the processing plant, the transportation network and the distribution network. Each link corresponds to a commercial relationship, and is dependent on every other link. Becausethe chain is vulnerable to disruptions, firm and long-term relationships are the norm "toke-or-pay" and/ or "ship-or-pay" clauses are generally used). Furthermore, risk management is a key element of projed feasibility analysis. For an interesting analysis of the impad of short-term trading on risk management see "Some Risks Related to the Short Term Trading of Natural Gas," Ahmed El Hachemi Mazighi, September 2004, Organization of the Petroleum Exporting Countries (OPEC). Is9Almost 50 percent of the total natural gas resource base (estimatedat 6,7 00 TcF)is in "sfranded" reserves, usuallylocated too far away from pipeline infrastrudure or population centersto make transporfation of the natural gas economical (International Energy Outlook, Energy Information Administration (EIA), 2005). The feasibilify of some of the optionspresented in Table5.7, with particular focus on upstream fiscal terms for gas, is discussed later in thisChapter. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES E&P Investment Barriers to Investment Possible Options Factors The 2006 Model PSA, Allow companiesto choose the Annex C, Minimum Work drilling location. If needed, offer Program and Expenditure, targeted incentivesto influence requires that three the contractor's investment exploration wells be drilled decisions by partially and evaluated in the compensating for increased basement exploration risk Predominance of small Provide targeted incentivesto and potentially resource accelerate project payback constrained permit holders Grant investment uplift carried interest Provide for zero royalty up to a certain value of production (gas-only) Encourage multifield gas development projects Size and Location No significant local market Form regional hubs for gas of Gas Market161 Potential demand located far market develo~ment from known reserves Favor switchinb to gas through targeted incentives (tax credits, favorable depreciation rates, and so on, and so forth) Establish pricing principles that correctly reflect the risk at every link of the gas chain Availability of, and Only one gas pipeline linking Encourage private and foreign Access to Infrastructure the Marib field to the LNG investmentin gas pipelines plant. The construction of a Establish regulations for Third national gas pipeline is being Party Access (TPA)162 evaluated Legal and Regulatory Both associated and Give the contractor the right to Environment nonassociated natural gas develop a gas discovery if it belongsto the State. deems it commercial. Key The 2006 Model PSA operational and fiscal principles establishes some general to be laid out in the 2006 16' Measures to oddress this barrier were outlined in Chapter 3. The European Gas Diredive, published in 1998, provides on example of TPAregulation. Its aim was to implement policies for a Europewidecompetitive market, wheresecurityof supply was and remoins a key concern, through common rules for transmission, distribution, supply ond storage TheDiredive requires the opening of transmission network and storage facilities to TPA. Countries may choose between either a system of "negotiated" TPAwith the publication of the main commercial conditions, or a system of "regulated" TPA, bosed on published tariff structures. For a comprehensive anolysis of the effect of TPA regulations on LNG facilities, see the proceedings of the 2005 LNG Issues workshop, http://www.energy.ca.gov/lng~docket/documents/index.html. It is important to underline that although the institutional structure should enable long-term competition between gas suppliers through open occess to onshore pipelines and terminals, this kind of competition cannot be effectively introduced until the market is sufficiently well established. In an emerging gas market, reducing investors' risk is essential. In thesecases, it may be appropriate to consider mechanisms that ensure competition while making use of economies of scale in the planning stage of a pipeline. One such mechanism could be to publicly announce the intention to build o pipeline and seek the participation of other players through a N o r by booking long-term copocity. If successfully implemented, this mechanism may leave only a small or no capacity left open for later TPA. REPUBLICOF YEMEN: A NATURAL GAS INCENTIVEFRAMEWORK E&P Investment Barriersto Investment Possible Options Factors principles, and provides for Model PSA an additional agreementto be entered into between the contractor and the State if a commercial discovery of natural gas is made. The contractor is required to bid commercial terms for natural gas No legal framework exists Introduce specific regulations for processing, transporting applicable to transportation, and distributing gas midstream and downstream operations Define principles for pricing of natural gas sales163 Government Government participation is Government full-carried minimum Participation carried through exploration mandatory participation in gas and development. production may impair project The percentage participation economics: establish a maximum is a biddable term, but a percentage optional participation minimum 60 percent State Carried participation limited to the participation is mandated exploration phase164 for the development of associated gas Fiscal Regime Royalties are calculated on Make royalties more respondent the basis of a sliding scale to the project economics, at least based on the reaching of by using a sliding scale based on certain daily production value of sales levels. Different thresholds apply to oil and gas. Thresholds and rates are fixed Cost recovery limit is Increasethe cost recovery limit for biddable. The recovery of gas. Cost gas is normally higher exploration and development than cost oil because of the higher expenses is limited to incidence of costs over revenues in 50 percent per annum starting the initial phase of a gas project on the date of initial Allow the deduction or partial commercial production or in deduction of interest on loans for the tax year in which the gas projects 163Tunisia'sexperienceoffers an exampleof how gas price policies can influence the level of E&P activities. In Tunisia,the gas price for local marketsales is fixed by decree.Until the end of 7 999,the gasprice wasindexedto 85 percent of the value of Mediterranean Heavy Sulfur Fuel Oil (HSFO)price. From 2000, the gas price has been indexed to 80 percent of the value of Mediterranean Light Sulfur Fuel Oil (LSFO). As a result, the price for sales of gas to the domestic market rose by approximately 78 percent. A study carried out by Wood Mackenzie to evaluate the impact of o number of incentives introduced by the 7999 hydrocarbon law, concluded that the change in the domestic market gas price policy was one of the key factors explaining the increased number of marginal fields that were subsequently developed. For more details see Taha Fezzani, Tunisia: Impact of the 1999 Hydrocarbon Law, MEES, volumeXLVI, No. 2, January 73, 2003. lM It is quite rare for a host government to be carried through development. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES E&P Investment Barriersto Investment Possible Options Factors relevant expenditure is incurred. Interest, fees and commissions on loans and guarantees are excluded from cost recovery Production-sharingis net of Link production-sharing to index taxes, which are paid by the of project profitability State in lieu. Profit oil is shared between the contractor and the State on the basis of a sliding scale linked to daily production. Different scales apply to oil and gas. The thresholds are fixed but the percentageshare is biddable Bonuses are a biddable term. Production bonuses could be They are payable on signature, linked to reaching target levels of declaration of commerciality cumulative production as and at reaching various daily opposed to daily production production targets for both oil and gas. The thresholds are fixed but the dollar amounts are biddable Other Several review committees Streamline approval procedures, and low thresholds for and introduce higher-expenditure approval of expenditure thresholds The 2006 Model PSA requires Define a reasonable lead time the contractor to notify the from discovery to start of MOM of a discovery of negotiation of the gas natural gas, and promptly project/development agreement meet to discuss whether an Extend the duration of the appraisal program is contractor's right to produce warranted. No maximum natural gas in line with other lead time from discovery to countries' practice declaration of commerciality is established, but the contractor is given six months from the date of the first meeting between the State and the contractor with respectto the possible development of the gas discovery to finalize a gas project agreement/gas development agreement. This period can be extended by mutual agreement between the parties. The 2005 Model MoU indicates that the duration of the contractor's production rights is the same for oil and gas REPUBLICOF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK Some of the potential barriers identified used to encourage the development of above are short-term in nature, and/or can marginal fields. They may also help in be addressed via initiatives that have a extendingthe life of existingfields when gas short term or temporary focus. Others will prices fall. In order to limit the losses to the require regulatory interventions and carry Treasury, royalty incentives are normally long-term effects. time-bound, or limited to a certain volume of produced gas, and/or a price level; Optionsto EncourageGas ExplorationActivities Drilling incentives. These can take the form of tax creditsfor wells drilledat certain depths, International Experience or within a certain period of time, or for Commonly Used Incentives horizontalwells, orwellsdrilled in particularly high risk plays or unconventional gas Some of the most commonly used measuresto (for example, coal seams and tight sands encourage gas E&P include the following: formations). Tax reliefsare normally capped to a certain volume of prod~ction,'~~and Royaltyincentives.Many producing countries apply for a limited period of time. They may have usedtheir royaltyregimeto send signals be suspended when gas prices rise beyond to the market. In particular, targeted or a level established in the tax regulation. blanket reductions in the royalty rates have This type of incentive aims at stimulating been used to encourage gas exp10ration.l~~ drilling activity in periods of low gas prices, Changes in the level and structure of and/or enablingthe drilling of high-costwells; royalties: (a) can easily be targeted in the gas sector -therefore pose little risk of wider Accelerated depreciation. This type of policyimplication; (b)arequickto implement; incentive allows for certain capital and (c) can materially improve project expenditure related to exploration and economics. However, this type of incentive developmentof naturalgasto bedepreciated has limited impact on the contractor's more rapidly for tax purposes. Accelerated upfront funding constraints, and rewards depreciation delays Government Take. It is success only. Royalties based on volumes, intended to accelerate the contractor's daily or cumulative, impose burdensthatvary investment payback, and to encourage inverselyto changes in the gas price. This is reinvestment; not the case with ad valorem royalties that vary directly with the price for any given Investmentuplifts. Upliftsallowthe contractor quantity level. Royalty incentives are often to recoveran additional percentageof capital '" For example, New Zealand reduced its ad valorem royalty from 5 percent to 7 percent for discoveries made between June 30, 2004 and December 37, 2009; the Outer Shelf Shallow Water Deep Gas Royalty Relief Act, 2003, introduced royalty incentivesfor theproduction of shallow water deep gas in the Gulf of Mexico; for several years thestates of Louisiana, Mississippi, Oklahoma and Texasoffered tax incentives, including ad valoremtax relief/reduction, to encourogegas production from marginal wells, high-cost wells, coal seams gas and other unconventional produdion, and so on, and so forth -with mixed degrees of success. InAustrolia, all gas production, including LPG, LNG and commercialgas/ethane, and all condensatesold separately from oil, were exempted from the poyment of excise under the Petroleum Excise (Prices)Act of 7 987. '66 For example, in 7977, the State of Louisiana launched an incentive program under which it offered 50 percent severance tax exemptionon the first 2 MMCF/d of gas produced from the discovery well in new fields for a period of 24 monthsfrom the start of production. Theprogrom has been undergoingregular updates and omendmentsond it is still ongoing; the Stateof Texasoffered 70 yeors full exemption commencing in September 7997 from payment of severoncetax on high-cost gas produced from wells spuddedbetweenMay 7989 and September 1996; in the sameperiod and untilJonuary2003, federoltax credit for gas produced from certain unconventional, high-cost formation was also offered - US$0.52/MMBTU for tight sands gas and US$0.8653/ MMBTU for coal seams gas. Canada offered tax incentives for deep wells. ENCOURAGINGTHE DEVELOPMENT OF GAS RESERVES costs through cost re~0very.l~~This type of than for oil.172When gas is produced in incentiveaimsto partially reducethe burden association with oil, in addition to the for proiectsthat havea long paybacktime,168 cost-recoverylimit, what can becost-recovered or are consideredhigh-ri~k.'~~Sometimesan should be carefully defined;'73 interest rate is applied to the host Tax losscarryforward. The contractor's share government-carried participation. Any of profit oil is usually subject to taxation. interest rate greater than zero will increase the projectNPVof the contractor, butthe rate Usually, tax losses incurred in a given fiscal year can be carried forward to succeeding should not exceed the level at which a fiscalyears. The carry-forward maybe limited contractor would have an incentive to to a certain number of years or unlimited. defer production; Unlimited or long carry-forward periods are Enhancedcost recovery limit. In most cases, particularly important for gas projects that PSAs have a limit to the amount of revenue have a long lead time from exploration the contractor may claim for cost-rec~very~~~to production; and but allow unrecovered costs to be carried forward to be recoveredinsucceedingyears. Relaxation of ring fencing. Usually, all costs Increasingthe cost-recovery limit provides associatedwith a given block or license must an incentive to the contractor to invest by be recoveredfrom revenuesgeneratedwithin accelerating project payback. In addition, that block - that is, the block is ring-fenced. in marginal fields, low-cost recovery limits However, some countries allow exploration can have a big impact.171 Cost-recovery costs to cross the fence.174The relaxation of limits are often higher for natural gas ring fencing can provide a strong financial For example, an uplift of 75 percent on capital expenditures of US$J00 million would allow the contractor to recover US$]75million. Typically, projeds that have a long lead time from exploration to production. In Australia, under the Petroleum Resource Rent Tax Assessment Act of 7 987, capital or operating costs directly relate to the petroleumproject, and are deductible in the year they are incurred.Expenditures includeexploration, development,operating and closing activities. Undeducted expendituresare compounded forward at a variety of set rates depending on the nature of those expenditures and the time that they are incurred prior to the granting of a production license. The legislation was substantially alteredin 7990toallowundeductedexplorationexpenditureincurredafter that datetobetransferredtaotherprojects.Simultaneously, the carry-forward rate of undeducted general projects expenditures was significantly reduced from the long-term bond rate plus 75 percentage points to the long-term bond rate plus 5 percentage points. In 2004, the government introduced a 750 percent incentive to assist exploration in nominated frontier areas (the initiative ceases in 2008). The regime was found to have been reasonably effectivein promoting exploration and development of oil and gas in marginal fields, and high-cost/high-risk areas. 170The cost-recovery limit is normally defined as a percentage of the revenue in a given fiscal year. The world average cost-recoverylimit is 63percent (D.Johnston, InternationalExplorationEconomics,Risk and ContractAnalysis, Penn WellCorporation, 2003). In some frontier areas, the cost-recovery limit may range from 70 to 90 percent. 171According to Mr. D.Johnston, cost-recovery limits of 50 percent or lower can have the same impact on NPV and IRR as a 5-10 percentage point decreasein contractor take. See Petroleum Fiscal Systemsand ProductionSharing, PennWell Books, 7994. '"See some PSAs in Malaysia, Oman and Trinidadand Tobago. In Nigeria, different tax rate apply for oil and gas: oil projects aresubject to 85 percent petroleum profit tax, while gas projects are subjectto 30 percent corporate income tax. Until recently, it was possible to deduct all expenditure related to associated gas against the tax liability for oil. In some cases, investorshad negotiated the right to consolidate the downstream plant consuming the gas as well. Even without the consolidation provision, the investors' post-tax economicswere better than the underlyingpretax returns for associated gas projects. For a detailed analysis, see Taxationand State Participation in Nigeria's Oil and Gas Sector, ESMAP, August 2004. 1741nNew Zealand, a 700percent deduction is given for exploration expenditurein the year in which it is incurred, development expenditure is allowed as a deduction over seven years from the date of expenditurefor offshore wells, and any losses arising are not ring-fenced either to permits, fields, or even the trade. That is, losses can be offset against any New Zealand income of the company or group of companies. Whenan exploratory well is converted to a production well, the expenditure that has previously been allowed on an incurred basisis clowed back, and then amortizedover the next seven years. However, no adjustmentis made to earlier years' tax assessments where the relief has already been allowed in full. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVEFWEWORK incentiveto the contractors, especiallythose considerable level of uncertainty exists with who have existing production or are in a respect to the prospectivity, and/or size and tax-paying position. The existence of a structure of the project. R-factor or rate of cost-recovery limit may enhance the return-based production-sharing, royalties importanceof thistype of incentive. However, and/or profittaxes are exampleof flexible fiscal the hostgovernmentmayend up subsidizing arrangement^.'^^ In addition, flexible fiscal unsuccessful exploration. Some countries systems limitthe needfor contract renegotiation. allow the consolidation of upstream, When incentives are provided, these should be transportation and processingactivities, and targeted to specific policy outcomes. Incentives an array of different arrangements is used aimed at encouraging upstreamgas exploration for LNG projects, which involve various and developmentshouldtake intoconsideration degrees of c~nsolidation.'~~ the whole gas supply chain so that they can be properly timed and the risk/reward can be Lessons Learned properly allocated along the chain. Many countries have used some form of ~ e s s m a nof ~~~i~~~ Encourage t to incentiveto foster gas E&P activities whether in G~~~ ~ yemen ~ in l ~ frontier acreage or in mature provinces. Their experience shows that the effectivenessof evalusting options to encourage more a specificform of incentivecannot be iudged in exploration activih/, we have been focusing on isolationfrom the rest of the terms applicable to those measures that respond to the following gas exploration and development activities, nor aims and design criteria: . can it be delinked from the supply and demand ~0nditions.l~~Some fiscal systems are more Materially improve the economics suited than the others to provide the flexibility and/or reduce risk for gas exploration that is needed to encourage investments that and/or havea long leadtimefor implementation(hence are more likely to be exposed to changing Involve low compliance and administration economic conditions), and/or when a costs; '" Generally speaking, there are three models for organizing LNG projects: (a) an integrated structure in which the sponsors' participate both in the upstream development and in the LNG plant, and sales of LNG are made by the project; (b) the sale of feed-gas by the upstream owner to the LNG plant, which, in turn, sells LNG; and (c) a tolling arrangement in which the upstream owner retains title to the gas up to the point of sale, and pays a fee to the owners of the LNG plant for the liquefaction of the plant and its delivery (basically the LNG plant operates as a cost center). All these structures have been used in some form in designing LNGprojects. Theintegrated structureavoids the definition of transfer price for feed gas. It is most suitable in cases where the feed comes from o single field, and all the sponsors hove a share in the upstream field (although it is possible to use this structure for multifield projects). TheRas Gasproject in Qatar is organized along theselines. Thesale from upstreamtotheplant is probably the most frequently usedsolution, especially when there is a significant degree of common ownership. TheAtlantic LNG is an example of this kind of arrangement. Tollingarrangements are rarely used. The LNG plants in Indonesia are organized along the lines of a tolling arrangement (seein particular the Bontang Plant): this typeof structure has helped creating competition for feed gas among different fields. Although the company that owns trains 2 and 3 of the Atlantic LNG also owns the gas and sells it to buyers, the plant is paid a fixed fee, making this structure basically equivalent to a pure tolling structure. Given the large number of possible arrangements that may exist to accommodate the specifics of each project, sponsors' group, lenders and offtokers, it is not surprising that LNG projects have a long gestation time. Clearly, each structure affects the risk and economics of the project, as well as the benefits that the host government may expect to receive. 176Thefederal incentives for the production of unconventional ond high-cost formations were offered in the United States during a period of oversupply in the market, when no increase in demand was expected. Because of this subsidy, unconventional gas could be sold for less than market value, thus displacing conventional gas that had to be shut in for lack of demand. Even some of the coal gas had to be shut in for lack of enough pipeline capacity to transport it. Some states, like Louisiana, where tight sands and coal seamswere not present, were more offected than theothers. SeeA.D. Koen, U.S. TaxCreditsSpurring CoalSeam. TightSands Boom amid Controversy, Oil and Gas Journal, October 14, 1991, p. 79. SeeAnnex 3, Box A3.2. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES Address market deficiencies; PSA or concession agreement. These may include: (i)the access to local gas market, Minimize distortionary effects; and domestic market obligations and pricing principles; (ii)the right to export a party's Are consistent with Yemen's macrofiscal entitlement, andto marketittothe highestvalue policy, andwith localdevelopmentobjectives. outlets; (iii)a sufficiently long minimum duration of the production rights; (iv) the terms of the These measures17acan be grouped under host government's participation; (v)the right of three categories: access to infrastructure for purposes of Measures which are needed to enable processingand transportinggas at a competitive tariff; and (vi)the key principles of taxation and gas exploration; production-sharing. Measureswhich economic impact cannot be In addition, the joint operating agreement practically quantified; and among the coventurersmaycontain basicterms Measures which economic impact can governing potential future sales of gas.lsO be estimated. The disposition of gas deserves particular consideration, especially when small gas Measures which are needed to enable accumulations are involved. Given the lack of gas exploration developed natural gas markets throughout the world, common stream disposition is the In drafting gas-related provisions in PSAs or preferred approach for international gas concession agreements, policy makers are ventures, where a single buyer under a confronted with the realitythat industrypractice long-term gas sales contract often solely varies considerably, and that gas projects may supportsthe initial development of a gas field. exhibit an unusually high degree of contractual Nonetheless, insomecases, separate marketing ~ornplexity.'~~For this reason, it is not unusual may need to be considered to avoid antitrust for contractual provisionsto defer the setting of and trade practice concerns i n some specific terms and conditions for the jurisdictions.lal Insome cases, ifthe government development and disposal of gas to special share of profit gas/royalty is paid in kind, this agreementsto be negotiatedbetweenthe parties mayhavea large impact on projectfeasibility.la2 in the event of a gas discovery. Nonetheless, some basic principles arising from accepted InYemen, the contractordoes not currently have international gas industrypracticesare normally the rightto explorefor and producegas, whether setforth in sector legislationand/or the relevant associated or nonassociated with oil, unless a '" Thesewere outlined in Table 5.1. '"It may be preferable for the contract toprovide for a general and flexible framework for subsequentgas disposal arrangements, instead of addressing thespecificity of all possible gas and infrastructure projects (forexample, gas pipelines, LNG, gas-to-liquids, CompressedNatural Gas (CNG), and so on, and so forth). lnOSeeAlPN Model Form 2005 for an example of joint and separate gas disposition provisions. 18'For example, the European Union (EU), the United Kingdom and Australia. '82In February 2003,the government of India came under pressure to review its decision to take profit gos in kind as part of the New Exploration Licensing Policy Round V (NELP-V), following strong opposition from potential investors. Investorsclaimed that if the clausewere to be implemented, it would be very difficult topredict what share of the gas the operator/producer would get from the field year, after year for marketing. Thus, it would be impossible to enter into long-term gas sales contracts. The government and the affected operators are still debating the subject. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK GDA, or a Gas ProjectAgreement (GPA)as the would needto be laid out, including procedures case may be, is entered into with the State. As a for obtaining the necessarypermitsand licenses, result, contractorsdo notactivelyexplorefor gas, evaluation of discoveries and declaration of and associatedgas is reinjected-afterstripping commerciality, preparation, submission and it from liquids if viable. Some government approval of development plans, domestic officials have suggested that discoveries of market obligations and pricing principles. nonassociated gas may not even be reported The accounting procedure annexed to the by the ~0ntractor.l~~The 2006 Model PSA lays 2006 Model PSAwould needto be amended to out some of the criteria that should inform the reflect rules applicable to associated and drafting of the GDA/GPA. In particular, if nonassociated gas. Service contracts and/or associated gas is to be developed, the 2006 amendments to existing PSAs could be Model PSA defines the time frame for considered in respect to the development and finalization of the relevant GDA, and provides production of known gas reserves. for a minimum percentage participation of the government - fully carried out by the Tran~portation,'~~processingand distributionof contractor. Similar provisions apply for gas would need to be regulated, preferably by nonassociated gas.la4 The requirement to law. In the meantime, the government should enter into negotiations everytime gas isfound make a clear, formal statement of its policy on in potentially economic quantities, may be natural gas, which should include the principles justified by the government's need to ensure upon which the different aspects of the industry that fiscal and nonfiscal obiectives are would be regulated, and which would set out adequately taken into ~0nsideration.l~~At the the government's long-term strategy for same time, the prospect of potentially long development of the industry.187The gas policy, negotiations and the uncertainty of their which should also be backed by a consensusof outcome are likely to discourage investors. stakeholders, including current operators, One possible solution could be to grant gas potential industrial users and customer groups, E&P rights to investors under the relevant should provide an initial level of comfort PSA and provide for flexible, progressive to investors. fiscal terms preferably R-factor or rate of return-based, so as to minimize distortions to Service contracts and/or amendments to the investment decisions, and to adapt to the existing PSA could be considered in respect to variety of potential project conditions. the development and production of known The key operational and fiscal principles gas reserves. la3If thecontrador fails to finalize the GDAwiththeStatewithinthesix-monthperiod set forth in the 2006 Model PSA,theStatehas the right to develop the field directly or in associationwith a third party. In this case, the contractor is obligated to relinquish the portion of acreagepertaining toa nonassociatedgas discoverywith no compensation-except for the possibility of cost-recovering exploration (and appraisal) expenses from cost oil (if applicable). Unless a GPA is entered into, a gas discovery and a dry well would be treated equally for the purpose of cost recovery. However, in case of a dry well, the contractor would not need to relinquish part of its acreage. I" Except thatArticle 27.4 specificolly provides far the financial terms and conditionsto be set out in the relevant GPA, which is to be entered into only after a commercial discovery. However, the financial terms for the produdion of both associated and nonassociatedgas are among the parameters which the potential contractor is asked to bid on in the 2005 Model MoU. To avoid misunderstandings, it may be worth clarifying the wording of the relevant clauses in the 2006 Model PSA. '=It remains to be clarified why the 2005 Model MoU provides for the contractor to bid commerciality and'produdion bonuses, and production-sharing for natural gas while the 2006 Model PSA does not grant the right to conduct such activities unless a GDA/GPAis entered into. In6 Especially at the beginning of sector development, producers should be given the right to build and operate high-pressure pipelines -directly, through or in associationwith third parties - to transport their gos. Theprinciples for TPAmay be set in the relevant regulation and referred to in the 2006 Model PSA (footnote 763). ln7See Chapter 3. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES Measureswhicheconomicimpactcannot and/or reprocessing existing data, and be practicallyquantified interpreting data over specific areas ahead of a licensing round. Industry consultations These include administrative measures aimed could help government officials to confirm at promoting the attractiveness of Yemen's E&P the location and the survey design and to investors, and improving the efficiency of parameters. Seismic contractors could be petroleumoperations. Inparticular, thefollowing contactedto exploretheir interestin carrying were considered: out a risk multiclient survey. Alternatively, funding could be provided under the State Improving the quality and quantity of budget, and the investmentcould be partially geotechnicaldata. Attracting new explorers, recovered through data licensing fees.190 and/or encouraging the increase in The information derived from the explorationactivitiesfrom existingcontractors interpretation of the data could be used to would require providing appropriate prepare promotional material, and could be information on Yemen's pr~spectivity,'~~and presented at promotional conferences. on its investment environment. Efforts have The business case for investing in Yemen already been made by PEPA, the MOMand should beclearly madeto ensurethat existing the Ministry of Finance in preparing explorers reinvest, and to attract new promotional material, including a web site investors. Data packages could be prepared containing information on doing business in and provided to interested investors ahead Yemen. A geotechnical database was of a licensing round. Deductibility of data created, and is being filled with information licensing fees for cost-recovery purposes provided by the contractor^.'^^ Some could be considered to provide further government officials have indicated that the incentive to successful applicants; lack of geophysical data in potentially prospective gas-prone areas has hindered Facilitating/coordinating multiparty work the government's promotional efforts. programs. Thefunction of leasingspecialized Geotechnical data have historically been equipment and employing technical acquiredfrom permitholderssubmitting data contractors is the responsibility of the as part of the compliance requirementsof the contractor who bears the associated risk. PSA. Indefiningwork programobligationsand However, the MOM/PEPA receives detailed evaluating bids, GOYcould putthe accent on work programs providing a descriptionof the data acquisition, processing, reprocessingand type of activities that the contractors intends interpretation. In addition, the government to carryout and the timing of these activities. could consider acquiring new seismic data, This information could be used by IB8Thegas reserves bose in Yemen hos been the object of speculation over the past years. At the end of 2005, gas reserves were estimated to be 76.9 Td, of which opproximotely 9 T d had been committed to the YLNG project. In 2007, the government launched a tender to assess the country's oil and gas reserves potential. PEPA also conducted an internal evaluation of the gas reserves potential in currentlyproducing blocks (Annex 2). IB9Thefunctionalitiesof thedata bank, and its workingprocedures, are not known otthisstage, that is, integrationond compatibility with generally used industry data management tools, occess modalities, integration with modeling ond interpretation tools. Thispaper ossumes that the data bonk is fully integrated with modeling and interpretation tools, ond that it provides for online access to potential investors and existing contractors. 190 Current averoge prices for onshore seismic acquisition and interpretation are approximately US$3,000/km for 2D ond US$9,500/SquareKilometer (km2)for 3D. Equipment mobilizotion feecould be reduced by coordinating with theseismic octivityof existing contractors. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK the authorities in a proactive manner. and cost control mechanisms, that is, Coordination of drilling and seismic management committees, procurement campaigns could be encouraged to reduce procedures, budget approval and audits. equipmentmobilizationcosts. Operatorscould Expenditure thresholds appear to be be allowed to share costs. Temporary particularly low compared to industry importation procedures could also be practice. This is likely to affect the efficiency optimized. Reducingcosts, and improvingthe of operations. Given the type of supervision efficiency of operations, is particularly and cost-recovery mechanisms currently importantfor the contractors, especiallyinthe provided for in the 2006 Model PSA, the current fiscal regime which is relatively government's cost of supervision and the insensitiveto project profitability;191 contractor's cost of compliance could be Allowing and encouraging multifield gas reducedshould greaterfreedom of operation development projects. Whenever feasible, be afforded to the contractor; and operators should be encouraged to jointly build or allow third party use of gathering, Developing a local gas market. The transport and processing facilities, so that establishmentof a legal, regulatoryand fiscal economiesof scale can be achieved and the framework that supports and encouragesthe benefit shared among the investor and the development of a local gas market will State. The development of multifield gas provide assuranceto upstreaminvestorsthat projectsshould also be strongly encouraged even the development ofsmall gas sothatsmallgasaccumulationsmaybecome accumulations may become commercially economical and flexibility of supplies and viable. Based on other countries' experience competition among producers may be in developing their gas sector, investment in enhanced. Whenever technicallyfeasible and local infrastructurewould need to be made economicallydesirable, the sale of gas from well in advance of potential demand: timing one block to another for use in operations and sequencing of investments is crucial. In could be encouraged with the objective of the meantime, the government would need reducing operating costs;192 to reassureinvestorsthat gas findings would Streamlining approval procedures, and be allowed to find the highestvalue market. introducing higher expenditure thresholds. If domestic market obligations are imposed As noted in Chapter 4, the 2006 Model on the producers, they would need to be PSA provides for various forms of oversight compensated at market price.193 19'As mentioned earlier, production-shoring and royalties ore determined the on the basis of daily production thresholds. Theseller's cost recoverywould be reduced by the value of the sale, while the buyer's cost recoverywould increase by the same omount. Gas otherwise reinjected would be used in operations instead of crude oil or fuel thus reducing the operating cost/bbl for fields that do not produce gas in sufficient quantities to support their operational needs, at the same time, creating economies of scale for fields that produce more gas than needed for their own operations. Similarly, GOYcould consider allowing interblock soles of gas for pressure maintenance -tax regulations or the PSA would be omended os appropriate. lD3As illustrated in Chapter 7 of this repod, there ore essentially two approaches to gas pricing: the cost-plus approach, and the market-based netback opprooch. In the cost-plus approach, gos is priced independently from alternative fuels. Thisencourages gas production, but does not take into accountits end use competitiveness.Furthermore, it does not encourageefficiency improvements. It could work in countries where gas resources are abundant and cheap to produce. The netback opprooch links gas prices more closely tocompeting fuels. For it towork, theprice of competing fuelsshouldbe undistorted,and free negotiations between the ployers olong the gas chain should be allowed. This approach would guarantee the competitiveness of gas ogoinst alternative fuels, and protect upstreamand midstream investment. If thisprinciple is applied, the rent- and the risk linked toprice movements in competing fuels -ispossed on to the producer, that is, theprofits gained by the processing, distribution, transmission and storage serviceswould not exceed the customary risk-adjusted profit on their investment and operation costs.However, the host governmentshould devise a fiscal package that encourages the upstream operators to reinvest the extra rent. International experience demonstrates that netback pricing is the best opprooch to gas market development, especially when gas reserves ore expensiveand not abundant. ENCOURAGINGTHE DEVELOPMENT OF GAS RESERVES Measures which economic impact can The fiscal parameters currently applicable in be estimated Yemen are detailed in Table 4.4.'99 The main features are summarized below for ease The fiscal regime could be used to convert the of reference: government's policy into economic signals to Royalty rates are determined on the basis of the market, and influence investment slidingscales basedon reachingcertaindaily d e ~ i s i 0 n s . lSeveral countries have used ~ ~ production levels. The rates at different favorable taxation of gas to support the thresholds of the sliding scale are the same development of the gas sector.19= for oil and for gas. However, the thresholds for gas are much higher than for Gas terms in any given country very much depend on the distance to market and/or on Cost-recoverylimits are the samefor oil and the ability of the domestic market to absorb the for gas;201 volumes that are being produced. For projects Profit oil split and bonuses are biddable. that are close to large markets, the fiscal terms Similar to the royalty, these parameters are for gas are rather similar to those applicable to linked to a sliding scale by which thresholds oil.196When gas markets are distant, the are defined on the basis of daily production Government Take is normally lower for gas targets (fixed in the 2005 Model MoU). than for 0i1.l~~ This is done either by simply Differentscales apply to oil and to gas; and defining a lower Government Take for gas, or by using self-adjustingprofit oil share, taxes Corporate taxes are paid in lieu bythe MOM and royalties.19* on behalf of the contractor. 19' Provided that the framework is clear, is not changed retroactively and does not discriminate between the actors. 195However, tax policy should complement, not substitute, sector reforms. For example, seeAlberta, Algeria, Argentina, the Netherlands, Norway, Pakistan, Thailand and the UnitedStotes Gulf of Mexico. lD7 For example, seeAustralia, Equatorial Guinea, Indonesia, Nigeria, Malaysia, the North Western Territoriesin Canada, Oman, Trinidad and Tobago, Qatar, Republica Bolivariana de Venezuela,and other countries. 198The use of R-Factor or rate of return-based systemswould automatically generate a lower Government Take if the profitability for gas is lower than the profitability for oil. 199It is worth noting that the most recent version of the Model MoU sets a minimum requirement in respect of all parameters - royalty rates, profit-sharing, cost-recovery limit and bonuses. Interested investors are required to match or better the minimum requirements. The use of a higher conversion factor results in lower royalties per Barrel of Oil Equivalent (BOE)for gas than for oil. 2m It is worth noting that currently, the State has the right to requestthe contractor to deliver associated gas not used in operations at the point of separation. All costs associated with the production and the delivery of gas are paid by the State to the contractor. If the contractor and the State enter into a GDA for the development of associated gas, all cost related to such development -including the construction and operation of the relevant facilities are cost-recovered from the annual gas revenue, - and theStatehas a minimum 60 percent fully carried participation. ThePSAdoes not specify how joint casts are allocated between oil and gas, however, the accounting procedure makes reference to generally accepted accounting principles. If no GDA/GPA is entered into between the State and the contractor, exploration and appraisal costs may be recovered from cost oil (if applicable) according to the cost recovery procedure set forth in the PSA. Associated and nonassociated gas are treated in a similar way, except that if nonassociated gas is discovered and a GPA is entered into between the State and the contractor, Article 27.3 paragraph 2 would appear to grant the contractor the right to recover all exploration and appraisal costs incurred by it as exploration expenditure from cost oil (or from the annual gas revenue if no oil production exists)without applying the cost recovery limitations set forth in Article 7. If this interpretation is correct, it may reflect an attempt to compensate the contractor for the extra risk taken when nonassociated gas is discovered, although the mitigating effect would only apply if oil is produced in the same contract area and if agreement is reached for its development under a GPA. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK Quantifying the impact on exploration activities costs, and the lifting costs are not publicly of the measures cited in Table 5.1, and available, although industry sources had determining the optimal package in terms of suggested that these might be higher than the scale and value, is a very difficult exercise for a regional average.203Furthermore, the value number of reasons: (a) the effect of some of currently unrecovered exploration and measurescan only be assessed in the medium development expenses is not known to the term; (b)some measuresmayprovideincentives authors, hence it was not possible to determine for activitiesthat might have occurred anyway; the effect on government revenue should the (c) the effect of fiscal measures on existing recoverability rate be increased, and its players and on new entrants is different; and application extended to expenses incurred by (d) the estimate of the overall macroeconomic the contractors in the past. Nevertheless, and effectis heavilyaffected bya number of factors, keepingin mindthe limitationsexpressedabove, including the timing and nature of future a simplifiedzo4economic model of a hypothetical discoveries. Insufficient knowledge of the petroleum project was developed for the sole country's prospectivitymakesit hardto anticipate purpose of illustrating the effect on project how manyviable gas prospectscould be drilled economics of alternative fiscal terms and their over any given period of Modeling of relative responsivenessto changes in economic alternativeoptions isfurther complicated bythe conditions.205The key parameters utilized are fact that the average finding and development listed in Table 5.2. 202In designing fiscal systems, the probability of success, the expeded average size of future discoveries and the overoge finding and lifting costs ore key data. The average finding casts, defined as the costs of adding proven reserves of oil and natural gas through exploration and development activities and the purchase of properties that might contain reserves, were estimated to be W 9 . 7 8/BOE worldwide, and US$6.76/BOE in theMiddle East. Theestimatedaverage pretax lifting costs for the sameperiod was US$4.23/BOE worldwide, and US$4.36/BOE in the Middle East (Performance Profile of Major Energy Producers, EIA, 2004). See also OMV starts oil production in Yemen, press statement released on December 27, 2006. In modeling the field economicsunder different contractual and fiscol systems, simplifying assumptionswere made. In particular: no distinctionwosmode between intangible and tangiblecosts; investmentcredits-normally cost-recoverable-were not considered; a deterministic approach was used to calculate production, costs and prices; abandonment provisions were not included. Where the participation of the national oil company was considered, its share of expenseswas carried by the contractors' group without applying any interest rate. Only two fields were modeled (respectively associated and nonassociated gas). Statistical or stochasticmethods could be applied to determine the possible value distribution of the project voriables in Yemen.Due to the lack of relevant data, this approach was not attempted in this report. 205TOstress test alternative fiscal policies, GOYwould need to carry out a similar type of onalysis using system parameters that are representativeof the universe of oil and E&P projects in Yemen. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES Table 5.2: Key Parameters EconomicModel of a HypotheticalPetroleum Projed - Oil and Associated Gas Nonassociated Gas Recoverable Reserveszo6 95.6 MBOE 1.1 Td Peak Production Ratezo7 17.9K BOE/d 223 MMCF/d Gas-to-Oil Ratio (GOR) 3,5 10208 NA Field Life 23 years 23 years Price US$30/bbl and US$4.5/MMCF US$4.5/MMCF Total Capital Costs (Capex) US554 million US$1,004 million Full Cycle Operating Costs (Opex) US$3.71/BOE (US$5.31/bbl US$0.25/MMCF and US$0.20/MMCF) Note: NA = Not available. Four alternative methods to calculate the oil split usedin daily productionand cumulative government share of profit - oil/gas were production-basedmodelswere the same, while modeled: daily production- Fiscal Model 1,209 thresholdsfor dailyproductionprofitoilsplitwere cumulative production - Fiscal Model 2, based on the 2005 Model MoU, and for R-Factor210 FiscalModel3, and rateof return2' - ' cumulative production profit oil split were -FiscalModel4.2'2Thresholdsandtriggerrates consistentwith those established for gas on an for R-Factorand rateof return-basedprofitsplit energy parity basis. A different cost-recovery were the same for oil, associated gas and limitwas appliedto oil (40percent), associated nonassociated gas. The trigger rates for profit gas (50 percent) and nonassociated gas m6Technical parameters (field size, probability of success, location, and so on, and so forth) were estimatedon the basis of the data contained in World Petroleum Assessment 2000, Assessment Unit 20040101, prepared by the U.S. Geological Survey. An abstract is shown in Annex 3. 207 When simulating the impad of variations in production levels, the same percentage was applied throughout the production horizon (no adjustment to the produdion rate to take into account facilities specifications and/or reservoir, managementneeds). The U.S. Geological Survey estimates that GOR values could vary between 2,000 and 6,000 in the Ma'rib-A1 Jawf/Shabwah/Masila basin, and between 1,000 and 3,000 in the RedSeoSalt basin.See World PetroleumAssessment 2000, USGS, Assessment Units 20,040,101, and 20,710,202. Average GOR for existing fields appears to vary between 3,500 and 4,200 (seeOil and Gas Directory at www.oilandgasdirectory.com/ogd/resgrod/Yemen.pdf). 209 Thethresholdsand triggers set forth in the Model MoU were used. TheR-Factor was calculated as the ratio between after-tax revenues and total project costs (capital expenditureand operating costs). Different countries use different definitions of R-Factor. Therefore, it may not be difficult to compare fiscal parameters among countries/contractsas their effect on project economics can be quite different. In rate of return-basedsystems, net annual cash flows are compounded at the target rate of return rate and carried forward until the cumulativeamount becomes positive. When the investor has recovered the initial investmentplus the target rate, the tax kicks in. Theoretically,the target rate of return should represent the minimum rate to encourageinvestment. 272 TOsimplify the analysis, wechose to keep the same basic structureof the currently applicable fiscal regime (2005 Model MoU). Therefore, all fiscal models are the same, except for the calculation of profit-sharing between the government and the contractor. - - It is imporfont to underlinethat, given the unavailabilityof thekey technical and economicdata applicable to oil and gas exploration and development in Yemen,the alternativefiscal modelsanalyzedin this Chapter5 were not designedto optimizethe fiscal system in Yemen, but merely to show how different fiscal systems respond to changesin economicand project conditions. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK (70 percent). The relative performance of for the design of a fiscal system. For all these fiscal models was assessed by allowing fiscal models analyzed in Chapter 4, a selected number of system parameters to variations inthe level of productionconsiderably change.213The results (measured in terms of impacted project economics (plus or minus break-even priceI2l4the NPV of the project's 4 0 to 6 5 percent of base case NPV for cash IRRI2l6Profitability Ratio (PR),217 production-based models, plus or minus 30 to Net PresentValue Per Barrel of Oil Equivalent 55 percent for R-Factor models, and plus or (NWIBOE),218operating leverageI2l9percentage minus 30to 50 percentfor rate of return-based GovernmentTake,220and Saving lndex(S1)221)are models).Similar resultswere obtained for price summarized in Table 5.3. Detailed calculations variations. A variation in the level of production are shown in Annex 5, Table A 5.1, Table A 5.2, or of prices resulted in large percentage Table A 5.3 and Table A 5.4. variations of the project's NPV because of the rigidity of capital investment. The higher the Our simplified analysis illustrates that the project's operating leverage, the larger the anticipated size and distribution of production impactof a variation in priceor production level. in a given geological province is a key element In our models, a variation in the level of 213Tosimplify the interpretation of the results only, one parameter at a time was allowed to change. A stress test was also carried out for all fiscal models by calculating the project's NPV at different discount rates resulting from decreasing the production level and price by 20 percent and increasing Capex and Opex by 20 percent. In reality, the likelihood, magnitude and timing of changes in technical and economic parameters have different effects on project economics, and on the overall performance of the system. 214The minimum level of gas price that causes the project's N W to become zero. 215It is worth noting that each government and each company has a unique risk-reward profile, and, hence, uses a specific discount rate. The choice of what discount factor to use is an important decision for companies evaluating projects since selecting a high rate may result in "missing" good investment opportunities, while selecting a low rate may expose the firm to unprofitable or risky investments. Host governments value money in the same way as companies do. However, their expected benefits should be discounted using the social discount rate, that is, a rate that reflects society's preferences for allocating the use of resources over time.A higher rate will attribute more weight to benefits to the current generation thon to future generations. Thecalculation of the parameters that are necessary to determine the social discount rate involves a certain degree of value judgment. In addition, countries may have considerably different social discount rates. This, of course, provides the scope for negotiating contract and fiscal terms. 216The IRR measures the relative attractiveness of a project. In general terms, project that present higher IRR should be preferred. Due to its limitations, the IRR is normally used in conjunction with other profitability indices. For an in-depth discussion of the IRR and of other commonly used financial measures of profitability, see Brealey, R.A. and S.C. Myers. 7997. Principles of Corporate Finance. McGraw-Hill, New Yark, NY. 217TheProfitability Ratio (PR)is used by companies to compareprojects around the world. ThePR is calculated as the ratio between the N W of the sum of the project's cash flow and total capital investedin the project to the NPV of the total capital invested in the project. It measures the profitability per dollar invested. 218Thisindicator allows companies to compare investmentsaround the world, irrespectively of the size of the project. 2'9 The operating leverage was calculated as the ratio of the NPV of the total cost to the NPV of gross revenue. Both flows were discounted at 70 percent. The higher the operating leverage, the more exposed the project profitability is likely to be to a fall in prices. Projectwith high operating leverages, all other project variable being equal, are relatively more exposedto the riskof losses under regressive fiscal regimes.See G. L. Kreizschmar, P. Moles, TheImpact of TaxShocks and Oil Price Volatility on Risk:A Study of North Sea Oilfield Projects,April 2006, W.P. 06.07, University of Edinburgh. 220 The Government Take (defined as the percentage of government's net cosh flow on total available cosh flow), and the StateTake (defined as the percentage of government's and NOC's cash flow to total available cash flow), were calculated on an undiscounted and on a discounted basis. To simplify the comparison with the contractor's take, all cash flows were discounted at 70 percent. In reality, the government's cash flow should be discounted at the social rate (footnote 7 79). This is likely to be lower than 70 percent, thus increasing the percentage Government Take. It is worth noting that most Government Toke statistics are calculated on an undiscounted basis. This needs to be taken into consideration in comparing the average Government Take in different countries. "l In designing fiscal systems, it is important to create an alignment between the contractors' interest and the host government's interest. In this context, creating incentivesfor cost-savingsis an important objective. TheSaving lndex (SI)is defined as the part of an additional one dollar in profit (arising from a one dollar saving in cost) that accrues to the contractor. It measures the degree to which the contractor will benefit from a reduction in costs (D.Johnston, International Exploration Economics, Risk and Contract Analysis,PennWe112003).In general terms, the contractor would always have an incentivetosave (especially during the exploration phase). However, fiscal systems that have a very low contractor's marginal take are more likely to create a lower incentive to saving. ENCOURAGINGTHE DEVELOPMENT OF GAS RESERVES Table 5.3: FiscalSystem Indices Oil Fiscal Fiscal Fiscal Fiscal Model 1 Model 2 Model 3 Model 4 Contractor's Cash Flow 119.7 116.5 121.3 128.4 (NPVlO%) Break-evenPrice 20.43 20.56 18.70 18.45 Project's IRR 18.4% 18.3% 20.1% 20.3% NPV (1O%)/BOE 2.03 1.98 2.06 2.18 Operating Leverage (%) 55.0% 55.0% 55.0% 55.0% Government Take (%) 47.5% 48.9% 46.8% 43.7% Saving Index (US$) 0.70 0.67 0.59 0.64 Associated Gas Fiscal Fiscal Fiscal Fiscal Model 1 Model 2 Model 3 Model 4 Contractor's Cash Flow 78.7 78.7 81.O 82.4 (NW10%) Break-even Price 3.21 3.21 3.03 3.00 Project's IRR 18.5% 18.5% 19.6% 19.7% NPV (1O%)/BOE 2.15 2.15 2.21 2.25 Operating Leverage (%) 60.9% 60.9% 60.9% 60.9% Government Take (%) 42.1% 42.1% 40.4% 39.4% Saving Index (US$) 0.82 0.75 0.68 0.70 NonassociatedGas Fiscal Fiscal Fiscal Fiscal Model 1 Model 2 Model 3 Model 4 Contractor's Cash Flow (NPV10%) Break-even Price 2.35 2.53 2.31 2.28 Project's IRR 22.7% 21.2% 21.6% 22.0% NPV (1O%)/BOE 2.88 2.28 2.21 2.43 Operating Leverage (%) 45.5% 45.5% 45.5% 45.5% Government Take (%) 52.5% 48.2% 49.8% 44.7% Saving Index (US$) 0.61 0.62 0.55 0.62 REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK production had the lowesteffect onthe project's of different levels of cost recovery limit for the NPV for nonassociated gas (51.8 percent four fiscal systems modeled in this Chapter. operating leverage),while associated gas (60.9 percent operating leverage) was affected the The choiceof trigger ratesor thresholds is a key most. This is a very important consideration in issuefor all fiscal models. It isquite unlikelythat the design of a fiscal system as market prices a particular set of triggers or thresholds would and geologicalconditionscan beestimatedonly be able to optimize the GovernmentJake under with a high degree of uncertainty. Therefore, all possible scenarios. For example, if the companies undertaking capital-intensive and thresholds for triggering higher profit oil/gas complex projects, or risk-adverse or smaller splits are too wide, the system may notefficiently companies' would logically preferfiscal systems capture the economic upside of a project. that provide a cushion in case of adverse This can be seen in Fiscal Model 1: the daily conditions. When project financing is productionthresholdsnecessarytotriggera higher involved, a fiscal system that is less sensitive profitoil/gas split infavor of the governmentwere to changes in project economics will increase never reached, and the percentage profit oil/gas the perceptionof risk, and ultimatelythe average split remained the same for the entire life of the cost of capital and the exploration and fields modeled in our example.224Therewere no development thresholds. significant differencesbetweenR-Factorand rate of return-basedprofit split respectivelyinthe first Since capital expenditure mainly occurs in the 10 years of production for nonassociated gas, initial phase of a project, variations in its level and in the first 14 years of production for have a large impact on project economics,222 associatedgas and oil. This was due to the fact especially when a cost-recovery limit is that the first three thresholds of the R-Factor- imposed223and/or the State's participating based model closely matched the variation in interest is on concessional terms. the project's IRR. Figure A5.1 and A5.2, A5.3 and A5.5 in Like Yemen, the majority of existing PSAs uses Annex 5 show the effect on project profitability sliding scales based on cumulative production 222 In Yemen, an exploration tax, calculated as 3 percent of exploration Capex, applies. It is meant to substitutepersonal income taxes for the personnel of the contractor carrying out activities contemplated in the relevant PSA. The exploration tax emphasizes the effect of an increase in Capex. In other words, the tax increases the operating leverage of a project. In general terms, higher cost-recoverylimits allow the contractor to achieve payback of its investment foster. However, when sliding scales ore used to determine the percentage of profit oil (or the tax rate), in some cases, higher cost recovery limits may lower the contractor's full cycle discountedcash flow. Thiswould depend on severalfactors including the discount rate, the level of saturation of the system, the operating leverage, and the steepness of the sliding scale vis-b-vis the changes in the project's IRR. 224 Under the terms of the most recent Model MoU applicable to PSAs to be negotiated for blocks awarded under the 2006 licensing round, the thresholds for gas production have been significantly changed compared to the terms set forth in the 2006 Model MoU. Under the new terms, royalties and production-sharing would be calculated on the basis of the following sliding scale: X M G a S s p m Millim d / d Mllim d / d Minishy Cmtmdor 0-25 0-25 -- 2550 25-50 -- 50-75 50-75 -- 75-125 75-125 -- >I25 125-250 -- >250 Depending on the triggers set by the MOM as minimum requirement- which may be different for different basins-the use of much lower thresholds is likely to increasethe Government Take. On the other hand, the new terms should improve the flexibility of the fiscal regime compared to the terms applicable under the 2005 Model MoU. However, as earlier, fiscal systems that use daily production thresholds are less sensitive to changes in project economics than systems that use cumulative production, R-Factor, or rate of return-based thresholds. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES levels, or daily production levels. In some uncertainty is low, especially if used in cases, different thresholds and trigger rates conjunction with price indices. apply depending on the water depth, or the well depth, and so on, and so forth. In some R-factor and the rate of return-based models PSAs the production-based profit oil/gas split havea lower break-even price(Table5.4), which is further linked to the level of oil prices makes them more attractive to the contractors and/or the R - F a ~ t o r Sliding . ~ ~ ~ scale terms and less riskycandidates for project financing. introduce flexibility in fiscal systems. This theoretically allows small and large fields to The impact on project economics of the be developed on equitable terms. In reality, government's participation through the NOC the neutrality of the system largely depends deserves special consideration. As highlighted on how the thresholds are defined, and how in Chapter 4, if concessional conditions apply closely they relate to the profitability of the to the government back-in interest- that is, if underlying project. the government does not pay itsway in, or pays it only partially - this would have implications FiguresA5.1, A5.3 and A5.5 inAnnex 5 show on the contractor's NW.Furthermore, because, the sensitivity of Government Take and project undera PSA, the contractor isallowed to recover profitability to changes in prices for the expenses (itsshare andthe carried)with a limited fiscal systems modeled in this paper. The or unlimited carry-forward, this may resultinan Government Take is very regressive when the implied borrowing ratefor the hostgovernment profit oil/gas is shared on the basis of daily or that is higher than its marginal borrowing rate. cumulative production levels. In general terms, In addition, unrecovered expenses affect the profit oil/gas splits based on production levels calculationof R-Factorand rateof return, which, are less neutral to investment decisions than inturn, may affectthe level of GovernmentTake R-Factorand rate of return-based splits, as the when profit oil split is determined on the percentage split remains the same even if basis of target R-Factor or rate of return levels. important changesin projecteconomicsshould Therefore, when a carried interest is involved, On the other hand, these systems are the decisionto exercisethe back-inoption, and easiertoadminister and may prove reasonably the consequent use of public resources, needsto efficient in sharing the rent between the beevaluatedinlightoftheoverallmacroeconomic contractor and the government when project objectives and resource allocation priorities of Table 5.4: Break-evenPrice Fiscal Fiscal Fiscal Fiscal Model 1 Model 2 Model 3 Model4 Oil 20.43 20.56 18.70 18.45 Associated Gas 3.21 3.21 3.03 3.00 Nonassociated 2.35 2.53 2.31 2.28 225Approximately, 25 percent of PSA around the world use R-Factor or rate of return-based systems. 226Mothernotically, it is always possible to design thresholds and triggers of a sliding scale based on production levels that match the changes in project economics.Since this can only be done at the end of the life of any given project and is bound to be different for each project, the use of rate of return and R-Factor triggers is likely to be more efficient at shoring the project's upsides and downsides between the contractor and the host government. REPUBLIC OF YEMEN: A NATURALGAS INCENTIVEFRAMEWORK the government. Annex 5, Table A 5.4 shows particular project. Because of their flexibility, the effecton projectprofitability of a 30 percent these types of arrangement are more likely to participation of the NOC carried through encourage the development of marginal fields, exploration and and of complex projects with a long lead time for implementation. Due to the high level of uncertainty that characterizesgas Eðe governmentis unlikely Depending on its overall fiscal policyneeds, the to succeed in the design of a fiscal system that government may seek different levels of suits all projectsunder all possiblecircumstances front-loading at different point of time. In order (both endogenous and exogenous). In this to achieve its objectives while maintaining a case, the best approach would be to allow a reasonable level of investment incentives, the certain degree of flexibility in the key fiscal government would need to seek a trade off parameters so that the system can adapt itself between regressive features (royalties, to changes in circumstances, by automatically cost-recovery limits, exploration tax) and capturing a reasonable amount of benefits progressive features (rate of return, R-Factor- when project economics improve and based taxes or production-sharing). Although lowering the Government Take when project progressive regimes are most successful in economics worsen. optimizing the Government Take under varying economicconditions, they mayenhance revenue The examples shown in this Chapter illustrate volatility.Various risk managementtools existto that, in order to capture a suitableshare of profit smooth revenuevolatility, the costs and benefits oil, the government needs to make reasonable of which needto be carefully considered. These assumptionson the size and profile of a typical tools are outlined inthe subsequentparagraphs. project, as well as to determine the typical variability in key project parameters. This would Evenwhen a flexible fiscal regime is established allow it to determinea representativedistribution for gas exploration and development activities, of R-factors, or ratesof return, or other parameters the government would still need to regularly chosen as thresholds, and to set appropriate assessitsperformance, andto adjustthe relevant floors and ceilings for such thresholds. Sliding parametersas needed so that the fiscal regime scale profit oil/gas split, especially if linked to applicable to future projects reflects changes in the return on investment, lower the project- market conditions, government policy and specific risk by introducingflexibility inthe fiscal geological and country risks.228In addition, package to suit the actual profitability of the complex or integrated gas developmentproject "'The NOC participation was modeled with respect to the 7Tcf nonassociated gas project. The percentage participation would have to be halved in the case of nonassociated gas for the project IRR to remain above 15percent. It is important to note that the IRR is one of the porameters used by oil companies to rank their investment opportunities. Companies set a target rate(s) that reflectstheproject risk and the investor's corporate profile. All other things being equal, investmentopportunitieswith an IRR below the target rate are not likely to be considered. Although target rates are unique to each company, a 75 percent target rate would not be uncommon. An interesting exampleof comparative onalysis of the competitivenessof Alaska compared to six other long-distance exporting countries was recently carried out by Pedrovan Meurs. Thestudy aimed at determining whether the proposed Alaska Gas Pipeline would be competitive under the applicable tax regime, or whether the incentives proposed under the Stranded Gas legislation would be necessary. The study found that the project would be competitive with other long-distance exporters to the lower 48 market only if the PPT was coupled with the incentive proposed in the Stranded Gas legislation. Among the seven jurisdictions analyzed in the study, Oman exhibited the most regressive fiscal regime, while Australia's fiscal regime was very progressive at high price levels. If the terms applicable in Australia were applied to the proposed Alaska Gas Pipeline project at US$4.5/MMCF, the Government Takewould have been 56 percent. ThelowestGovernment Take,39 percent, would be obtained by applying the terms applicable in Oman. See Pedro van Meurs, Gas lnternationol Comparison, Appendix S, December 2006, http://www.revenue.state.ak.us/gasline/ Gas lnternotional comparison. ENCOURAGINGTHE DEVELOPMENT OF GAS RESERVES may warrant the negotiation of special countries with developed gas markets, has arrangementswhich may includeupstream and encouraged the growth of spot markets,232 midstream activities.229 thus increasing price volatility. Gas PriceVolatilityand RiskMitigation For gas exporters, one significant impact of World trade in natural gas is divided among the changing environment has been the major regional markets dominated by pipeline development of a short-term LNG market. infrastructures that provide the means of Although long-term LNGcontractsare not likely transporting the gas from producers to to disappear, importers are seeking increased customers and a single worldwide market for flexibility and better contract terms.233Box 5.1 LNG. The United States is the largest pipeline summarizesthe keydifferencesinpricestructure gas market. for the main LNG markets. Natural gas is among the most price-volatile Gaspricevolatilityaffectsall marketparticipants: commodities.Natural gas is particularlysubject producers, gatherers, processors, transporters, to wide price swings as demand responds to storage operators, users and governments. changing weather conditions. Inventoriesare of There are several steps that market participants limited help in damping price spikes.230 and regulators can take to mitigate price The infrastructurethat is needed to deliver the volatility. These include: contracting for firm gasto end usersisexpensive. Gastransportation transportation and storage; switching to costs are several orders of magnitude higher lower-costalternatefuels; usingfinancial hedges than oil transportation costs. Furthermore, the to create price certainty; contracting under transportation system is relatively inflexible: long-term fixed price agreements; and making shipping low-costsuppliesto areaswhere prices available timely and reliable information are high can be very difficult becauseof limited regarding supply, demand, and storage levels. capabilityon the physical networks connecting As market participants are exposed to customers to supplier^.^^' The foregoing factors different types of risk, and exhibit different can cause pricesto soar inareaswhere demand levels of risk tolerance, their approach to risk increasessuddenly. Inaddition, the deregulation management and their mitigation strategies process that has been undergoing in many is likely to be considerably different. "9 See footnote 7 76. 230Althoughnatural gas storage offers an effective way to hedge volume risk and fix a price, storage has significant costsand risks associated with it. In addition, operability factors are important. For conventional oil ond gas storage reservoirs, deliverability is dependent on the amount of gas in storage. Thegreater the amount of gas in storage, the greater the pressure of the reservoir and the greater the deliverability. Thishas implications in termsof the time needed to reach the necessarypressure, and the withdrawal rate. Salt domes do not have the same limitations: by allowing more flexible withdrawals rate they can provide more effective protection against price volatility. However, the bulk of existing storage capacity is made up of conventional reservoirs.According to a study carried out by Mercer Management Consultant in June 2006, the price of storage facilities has increased considerably in the UnitedStates, and severalnew multicyclestorage projects are being proposed by LDC, pipeline operators and gas producers. 23' Location arbitrage does not work as well for gas as it does for oil. Sincegos is essentially a network industry, customerscannot buy gas "off the system." In addition, arbitrary price differences in transmission charges -that is, not based on marginal cost - between and ocross markets are not infrequent. In a competitive market, the price differences due to transportation should be eliminated by arbitrage. This is not the case for natural gas. 232 Traditionally, natural gas contracts were long-term contracts between integrated natural gas companies and users, with fixed prices, reduced supply and price risks and little flexibility. The importance of these contracts has been reduced as a result of the liberalization of the industry. Spat markets have emerged generally in areas with concentration of buyers and sellers as pipeline interconnections located close to large-consuming regions, or major terminals of gas-producing countries. Spot markets allow for greater flexibility to balance supply and demand so as to swiftly read to changing market conditions. 233 According to the Groupe International des lrnportatuers de Gaz Liquefib (GIIGNL), contracts covering the sale of nearly 30Million Tons(Mt)per year toAsian countrieswill come up for renewal over the next decade. It is expected that greater flexibility, especially with regard to the destination clause, more attractive pricing structuresand free on board (fob)pricing will become more and more frequent. Box 5.1: Price Strudure in the Main LNG Markets Gas PriceVolatility and from a transient one: oil and gas prices have Government Revenue been knownto be mean-reverting, butthe mean they revertto may not be the same over time. If Countriesthat derive a considerable portion of the price increases substantially, a government their revenue from exploiting nonrenewable may be under pressureto increase itsspending, resources such as hydrocarbons, typically face but it may be difficult to do it efficiently. two problems: the revenue stream is uncertain and volatile; and it does not lastforever. Volatile To helpdealwiththeseproblems, some countries and uncertainfiscal revenuemakes it difficult to have established resource revenue funds. plan expenditure and to efficiently use public A resource fund could be structured to resources. Inorder to ensurefiscalsustainability, specifically deal with price volatility, that is, the when revenue falls sharply and unexpectedly, fund would accumulate during period of often governments respond with expenditure high commodity prices. The resources so cuts. This can be expensive, inefficient and accumulated would be used to offset revenue politically unpopular. In addition, it is not easy fluctuation in periods of low commodity to distinguish, ex ante, a permanent price shock prices. This type of fund is known as 234EIA Energy Outlook 2006. 235Being a price-taker, LNG is priced with referenceto the competing fuel. 236Since LNG importersin the Pacific Basin-Japan, Korea and Taiwan-had little to no domesticgas production, and no pipeline sources for natural gas imports, starting in the 80s, LNG trade increasedvery rapidly in these countries-comparedtoEurope and the United States - as they sought alternatives to oil. Security of supply was a more important consideration than price. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES Contingent Stabilization Fund (CSF).237In order although the use of fiscal prices may allow the to provide a meaningfulinsuranceagainst price governmentto reducerevenuevolatility, itis likely volatility, the CSF would need to be able to to have a distortive effect on investment accumulate sufficient liquidity.238Countries decisions.242 experience with CSFs has been mixed.239In general terms, a CSF can contribute to insulate Alternatively, a producing country could transfer government expenditure from price shocks. the risk of price shocks to those better able to However, its effectiveness depends on the bear it. There are various ways of doing this: government's overall fiscal discipline. If the State is a party to a gas sales and Instead of creating a CSF, a government could purchase agreement, floors and ceilings borrow abroad to weather temporary shocks or could be established in the pricing to adjustto permanentpriceshocks. In practice, mechanism.243These provisionsare designed the government may not have easy access to to providea minimum sales pricetotheseller. foreign capital markets on reasonable terms, In exchange for this protection, the buyer is especially in period of low commodity prices, ensured a maximum purchase price. and repaying the debt when the situation Alternatively, a less risk adverse seller may reverses may be difficult. preferto negotiatea lowerfloor, and maintain the possibility to benefit from a rise in price. Another way of dealingwith pricevolatility could Indexation and periodic renegotiation of the be to set fiscal prices for the purpose of pricefloor and ceiling are usuallyprovidedfor calculating royalties, production-sharing and in this type of agreements; and corporatetaxes. Thefiscal pricecould be defined as a fixed value over a certain period of time, Futuresand optionsmarketsprovidethe seller or it could be indexed to an international (buyer)the abilityto either put a floor (ceiling) commodity price indexZ4Oor a portfolio of on pricesor buy an insuranceagainstfalling indicesz4' It is important to underline that (rising) prices. These contracts are called 237Sincenatural resourcesore nonrenewable, their production straddles severalyears into the future, and the production rate tends to decline over the life of a field, a revenue fund may be created to set aside revenue for periods of lower revenue, because the price of the resourcehas fallen, or the production rate has lowered, or the resourcehas been fully produced. Stabilization funds aim at reducingthe impact of volatilerevenueon government expenditure,whilesaving funds aim atstoring wealth for futuregenerations. A resource fund con, of course, combine both elements, and accumulation and withdrawal rules con be designed to suit the objective of the fund and the particular needs and situation of a country. For simplicity, in this report we refer to o particular type of resourcefunds, the CSF. However, our conclusions apply to resource funds in general. 238 This, of course, would depend on the expected level of revenue in relation to the spending needs of the country. 239 Extensive literature exists on resource revenue funds and their effectivenessin various countries. For more details, see Fiscal Policy Formulation and Implementation in Oil Producing Countries, Davis, Ossowsky,Fedelino, IMF 2003,and Experiencewith Oil Funds: Institutional and Financial Aspects, Bacon and Tordo, ESMAP, Report No. 327/06. 240 For example, in the case of gas, the fiscal price could be indexed to the overage daily closing spot of HH NYMD( over a set period of time preceding the calculation of the royalty and tax revenue. "' For example, the fiscal price could be indexed to a basket of gas prices established as the overage of the spot price in key export markets over o set period of time weighted on the bosis of volumes of export. 242 Even if a government should define the fiscal price on the bosis of o bosket of international gas prices, it is unlikely that this would match each contractor's soles price. Thus, the fiscal price would likely create on additional basis risk, which may affect the risk profile of the project (hencethe cost of capitol), and which would need to be taken into account by the contractor in the design of its risk mitigation strategy. 243Project finance lenders often require collars to be established in order to reduce commercial risk. Collors may be established in soles agreementsor through the use of derivatives. Using derivatives may provide more flexibility to the parties as it would allow themto odjust their risk protection strotegy at changing market conditions-although this wouldrequire more active risk management techniques and morket expertise. REPUBLIC OF YEMEN. A NATURAL GAS INCENTIVE FRAMEWORK derivatives.244Derivatives may be traded in risk and complexities, and entail a certain exchanges or Over-The-Counter (OTC).245 level of implementation costs. Box 5.2 Although they mitigate price volatility, these outlines the main features of the basic type instruments present different degrees of of derivatives contracts. Box 5.2: Key Elementsof the Main DerivativesContracts 2u Derivatives owe their name to the f a d that they derive their value from an underlying asset. These contracts do not confer ownership rights on the underlying asset. For example, a call option on BP stock gives its holder the right to buy a specific quantity of BP's share at a specified price (the "strike price"). The option does not represent an ownership interest in BP (the "underlying asset"). Although derivatives have been used for long time in the financial sector, their use in the energy sector is relatively new, and has been favored by market deregulation. 2u The instruments are essentially the same, but the two markets differ in their transparency (the OTC energy market is not nearly as transparent as the OTC foreign exchange market), flexibility (contracts terms are not standardized as they are on exchanges), and cost. (In the OTC market, the counterpart is not a regulated exchange: transactions ore entered into with a trader or financial institution, who in turn hedges the position in the market, or between parties with opposite hedging needs, for exomple, a gas producer and a utility compony. Becausecontract performance is not guaranteed by an exchange, the risk that a party may default needs to be factored into the OTC contract. Therefore the transaction fees for the same transaction may differ greatly depending on the creditworthiness of the porties. In addition, because the terms of the contract are not standard, legal work is required, depending on the complexity of the trade.) Nevertheless,producers tend toprefer the OTC market sinceproducts can be structured to more closely replicate their project/market activity and needs. Furthermore, as OTC transactions are not publicly observed, a market participant is able to execute large volumetrades discretely, thus reducing thepotential for triggering an adverse movement of price that undermines the participont's own position. 246Future~controcts are available for only a few commodities/delivery locations, and for a relatively short time into the future. For longer duration ond/or specific needs, OTC contracts may be used. 247 Thesellerof the futures is asked to moke a good-faith deposit with his broker, and a margins account is opened. Thefirst deposit on the margin account is called initial margin, and is normally a fixed amount per contrad. During the period of validity of the contract, the futuresprice will change in response to new informatian about the demand and supply of the underlying commodity. If the new price is higher than the contract price, the seller poys the difference into its margin account. If the new price is lower than the contrad price, the broker pays the difference into the seller's (buyer's) margins account. This procedure is called "marking to market." It is done every day and may be done several times during the day. Brokers close out parties unable to poy (make their margin calls) by selling their clients' futures contracts. Usually, the initial margin is enough to cover a defaulting party's losses. If not, the broker covers the loss. If the broker cannot, the exchange does. The margin procedure applies to both the seller and the buyer of a futures contract. Information on the use of and experience with market-sensitive information, especially when commodity risk markets by governments largetransactions are involved, as it is often the (and/or State-owned companies) is scarce.254 case when the traded commodity is oil or gas. In This is partly due to the confidentiality and addition, the gas derivatives have only recently the unwillingness of producers to reveal been introduced in stock exchanges,255and Sincethe buyer of the futurescontroct con olwoys demand delivery ond the seller con olwoys insist on delivering, of moturity the futures price and the spot morket price for thot commodity will hove to be the some. 249Speculotor~routinely buy ond sell futurescontrocts in onticipotion of price changes. Intuitively, forword controcts ore less liquid thon futures controct. 250Americ~noptions allow the buyer to exercise its right either to buy or sell of any time until the option expires. Europeon options con be exercised only at moturity. Whereas the holder of a futures/forword controct hos on obligation to perform - that is, the holder is committed to o price in advance -on option gives its holder o right to choose whether or not to perform. 25'AS with futures controcts, speculatorsolso buy ond sell options in onticipotion of morket prices chonging. '"Theprice of on option depends upon its strike price (thepurchose or sole price of the commodity in the controct), the price of the underlying commodity (the current futuresprice for the specific month the option covers), the time of expirotion, the interest rotes and the volatility. 253Since OTCtronsodions ore not publicly observed, o morketporticipont is oble to executelarge volumetrades discretely,thereby reducing the potential for on odverse movement of price thot undermines the porticipont's own position. Furthermore, because controcts ore not guoronteed by the exchonge, the risk of default of o porty to the controct is higher 254Thereis o general consensusomong morket participants thot developing country producers, and especially gas producers, hove so for mode limited recourse to oil ond gas risk markets to insure ogoinst price volotility. 255GOSfutures ond options were introduced in stock exchonges only 75 yeors ago. In addition, the more liquid segment of the futures morket is the neor term. Therefore,o government thot wishes to lock in o price for the budget period (72months) ond does not hove the copocity, or is unwilling to toke the risk of octively trading in futures ond/or options, would need to use the OTC morket. Informotion on tronsoctions conducted in the OTC morket is not publicly ovoiloble. 107 REPUBLIC OF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK long-termcontractswithembeddedpriceformulae legislature would have to pass a law that are still very much the norm. Frequently cited authorized and spelled out the program's reasons for the relatively low use of hedging by parameters. This may be politically difficult governments in producing countries are listed to achieve; below: The personnel and cost implications of Policy makers might be reluctant to take the designing, implementing and monitoring a political risks associated with it. If the State hedging program may be significant. lostsignificant sums as a resultof its hedging Expertise is required to understand the risk program, or if prices increased significantly structure, identify appropriate risk and the State had sacrificed that upside to management instruments, implement and reduce the volatility in its resource revenue, supervisethe program. Although the design the conventional wisdom is that public and implementation of a hedging program criticism would be harsh;256 may be subcontracted, the government would still need to develop sufficient A hedging program costs money: margins internal capacity to monitor the program need to be deposited with a stock exchange and communicate its results to the iffutures are used; options requireimmediate relevant stakeholders. Adequate reporting payments; and OTC traders may require and accounting procedures would also credit guarantees. Governmentswith a poor be required; and258 credit standing may find their access to certain hedging instruments constrained The basis risk of the particular commodity or expensive; may be too high,259and it may not be significantly reduced by using exchange Some aspects of a hedging program would traded contracts. require specific appropriations for any fees or commissionsor initial margins associated Notwithstanding the foregoing, governments with the program;257 appear to bemaking increaseduseof derivatives to protect their hydrocarbon revenue. Several Before the State could initiate a commodity oil- and gas-producing States have legislation, hedging program, it is quitepossiblethatthe administration guidelines and procedures 256See A. Kuprianov, Derivatives debacles: Case studies of large losses in derivatives markets, pp. 605-637R.J. Schwarfz, W.S. Clifford, in Derivatives Handbook: Risk Management and Control, John Willey & Sons, Inc. 257For example, if the State were required to put up large amounts from time to time to cover margin requirements in a futures-based program, budget appropriations would need to be granted. 258Accounting and reporting standards have been developed, although with particular reference to companies ond stock exchange regulation. 259The basis risk describes the lack of correlation that may exist between the price of a derivative contract and the price of the commodity that is being hedged. Tothe extent that theseprices move independently, the hedger faces a risk that the change in the value of the commodity may not be entirely offset by the change in the value of the derivative position. Thus, the hedge may not be a perfect one. A basis risk moy occur because of quality differential between the commodity linked to the derivative contract and the commodity being hedged, for example, the Brent IPE futures and the Doba blend, or the WTI NYMM and the Lloyd blend. Thisis not unusual for heavy acidic crudes. In the case of natural gos, the basis risk is greatly linked to location-forexample, the cost of transporting the gas from one location (the HH if derivatives quoted on the NYMEXare used) to another. The use of price formulae in contracts may also introduce a basis risk: this is, for example, the case when using long-run moving average of spot prices. Thebasis risk may have a timing dimension: although spot and futures prices for the same commodity are closely related a change in the spot price does not necessarily translate in the same change in futures price. This is because the same piece of information may affect current supply/demand and future supply/demand in a different way. A variety of basis contracts are available in OTCmarketsto hedge locational, product and even temporal differences between exchange-traded standard contracts and the particular circumstances of contract users. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES permitting the institution of hedging programs suitable hedging strategy. For example, if the to protect their energy revenues,260 and marketisin backwardation, andthe government State-owned utility companies - particularly in expects that it will continue to be so over the Europe and in the United States - are hedging period, and that price volatility will be increasinglymaking use of derivative contracts low, it could adopt a strategy of simple to hedge against gas price volatility. forward sales selling futures and closing out its position with a reverse transaction before In order to design the proper risk the expiry date.263 management plan, the government would need to clearly define its objectives, that is, The relationship between the price of the hedge what results it expectsto obtain from hedging instrument and the price of the underlying and the time frame for such results.261For commoditywould needto becarefully analyzed example, a government that derives a large inorder to determinethe optimal hedge ratio.264 portion of its fiscal revenue from gas, may wish to limit the risk of revenue volatility by The relativecost of thevarious hedgeinstruments securing a fixed price for the entire budget also plays a relevant role in designing the year in order to support its expenditure plan, strategy. Since the gains and losses in futures or it may wish to limit the risk that the contracts are settled daily, a strategy of trading price may fall below a certain minimum in futures may involve large transfers of cash to level over a longer period of time for the and from the broker. The number of transfers purpose of ensuring the medium- or long- could be reduced by structuring an OTC swap term fiscal sustainability. to suit the government's liquidity profile. Alternatively, the government might use a The market outlook (contango, flat or straight option strategy which does not involve ba~kwardation),2~~the levelof pricevolatilityand the paymentof margins,265but the buyer of the the government's expectationwith respectto the option pays the premium u p f r ~ n tThe ~ . ~ ~level direction of future price movements, are of funding that is available to the government important elements to determine the most to set up a risk management program, and the - - 260 The experience of the state of Texas in designing its hedging program and related institutional set-up could offer a valuable reference guide to governments that are looking at ways to protect their revenue from commodity price volatility. Among the national oil companies, Statoil has adopted a comprehensive approach to enterprisewide risk management strategies. PDVESA (the national oil company of RepublicaBolivariana de Venezuela),Pemex (thenational oil company of Mexico) and Petrobras (the national oil company of Brazil), also have active hedging programs. For a discussionofpotential hedging objedives, SeeC.Ellsworth, E. N. KrapelsandS. H. Cho, Natural GasHedging: Benchmarking Price Protection Strategies,Risk Books, 7 999. 262Themarket is in contango whennear-termprices are lower than prices for the monthsfurther in the future, and is in backwardation when near-term prices are higher than future prices. 263 Thegovernment could sell a 72-month strip, that is, a futures contract covering a period of 72 months, and close out its position gradually according to the pattern of the gas revenuebeing hedged. Alternatively, the government could adopt a rollover strategy, that is, sell futures and close out the position monthly. 2Mlnorder for the hedge to be successful, the futures price and the underlying spot prices should behave similarly, even though a basis risk will naturally exist. Econometric models are used to determine the optimal hedge ratio, that is, the ratio of derivatives contracfs to buy or sell for each unit of the underlying asset on which the hedger bears a price risk. Sincespot and futures returns are characterized by time-varying distributions, optimal hedge ratios should be time-varying. For a more in-depth discussion, See R.J. Schwadz, W.S. Clifford Jr (Eds.), Derivatives Handbook: Risk Management and Control,John Willey & Sons, Inc, 1997. 265 Futures-style options exist where the premium is not paid upfront and a daily adjusted margin is required. 266 The upfront cost is likely to be more than a hedging program using futures, but an options-based program would allow the government to retain any additional revenue if gos prices move higher than the hedged level. Furthermore,the cost of the premium can be totally or partially eliminated by using a combination of put-and-call options (for example, selling a put and buying a call option). REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK procedure and constraints for accessing such It is important to note that the setting up of a funding, will ultimately determine the type of risk management program through the use of instrumentsthat the government will be able to derivatives contract is not alternative to the use to hedge its risk exposure, and the overall establishmentof a CSF.Onthe contrary, the two organization of the program. instrumentscan be c~mplementary:~~~because derivatives can be usedto reducepricevolatility, The implementation infrastructure is very the need to recur to withdrawals from the CSF important. For any risk management program when actual price level fall in relation to their to perform effectively, a system of checks and target level, would also be reduced. This would balances would need to be designed. Trades, permitthe CSFto build its reservesmoresteadily financial transactions and exposures should be and to invest in less liquid instruments thus clearly recorded to permit the evaluation of increasingthe return on assets. performance of the system and to promote accountability. Ideally, a risk management Annex 6 illustratessimple examples of hedging committee would be tasked with the design of strategies using exchange-traded and OTC the hedge policy on the basis of relevant derivative contracts from the point of view of a economic and price information and of the government of a gas-producing country. tolerated level of risk exposure. The committee would also establish the hedging guidelines Conclusions (budget, time horizon for hedging, and The gas reserves base in Yemen has been the authorizations) to be followed by a hedge object of speculation over the past years. At the committee, tasked with the implementation of end of 2005, proven gas reserves were the hedge policy, either directly or supervising external hedgers. Audit and financial control estimatedto be 16.9 Td, of which approximately 9 Tcf had been committed to the YLNG project, should be independent, that is, not part of the and the rest has been earmarked for domestic committee's structure. The risk management consumption. policy should be presented to the national assembly together with the relevant budget The development of a natural gas market is documents, as well as postexecution particularly important to GOYfor its potentialto assessments. This type of structure would supportthe creation and growth of the domestic enhance transparency and acco~ntability.~~~ industrial sector. In addition, revenue from gas exports may contribute to partially offset the Before implementing a particular strategy, it is decline in government revenue from currently good practice to set up a virtual hedging producing oilfields. program where different hedging strategies would be exploredfor a suitably long period of Little data are available on the potential size of timeto determinetheir effectiveness, the relative probableand possiblereserves, and onthe likely costs and ease of implementation. 267For examples of alternative implementation arrangements, See S. Claessens and P. Varangis, Hedging Crude Oil Imports in Developing Countries, The World Bank, WPS 775, August 7997, or M. Lindahl and D.J. Weinmann, Hedging Oil Revenues: Texas and Alaska, presented at the International Association for Energy Economics in July 7995. 268Anillustrationof how the use of derivotivescan complement the use of CSF is given in S.S. Claessens and P. Varangis, Oil Price Instability, Hedging and an Oil Stabilization Fund, the Cose of Venezuela, The World Bank, WPS 7290, April 7994. ENCOURAGINGTHE DEVELOPMENTOF GAS RESERVES cost of development. The available data would project level. The use of fiscal systems basedon seem to indicate a relatively low chance of profitability indices (R-Factorand rate of return- finding large oil and gas fields, and a relatively based systems)was suggested as they are more high chance that development cost could be likely to capture the variability among projects. higher than the regional average. This does not A study on the likely field size, location, mean that gas reserves would not be found in probability of success, reservoir performance, Yemen, or that it would not be economic to finding and development cost, and other develop them. O n the other hand, it does relevanttechnical parameterswould needto be suggestthat measuresmay need to be taken to carried out in order to design fiscal system's encourage their development. In order to parameters that are appropriate for Yemen. design appropriate measures, GOY would first need to identify if barriers to investment Risk-rewardprofilesvaryfrom investorto investor exist, and what their nature is. In this report, and, overtime, fiscal modelsthat limitthe upside we identified a number of potential barriers for the investor but cushion the downsides, may to investment, and possible options were be moresuitedto promotea newor geologically suggested to overcome them. risky province, or to attract small investors during times of high volatility in the market. In The use of fiscal policyto attract foreign capital the latter case though, the host government and expertise was also discussed. Because of needs to consider the macrofiscal impact of the high risk and considerable investment this strategy, including the need for utilizing involved in gas exploration and development, risk management tools. thefiscalsystemwould needto take into account the divergent interests of investors and GOY.In Countriesthat derive a considerable portion of particular, the fiscal system would need to be their revenue from exploiting nonrenewable able to allocate risks equitably. As risks can be resources, such as hydrocarbons, typically face substantiallydifferentfor different projectsand, two problems: the revenue stream is uncertain overtime, itwould bedesirableto build enough and volatile, and it does not lastforever. Volatile flexibility into a system to allow for unforeseen and uncertainfiscal revenue makesit difficult to changes, and to minimize the need and cost of plan expenditure, and to efficiently use public negotiations and/or renegotiations. Ideally, resources. Despitecareful planning, exogenous the system should be able to capture the forcescan still cause actual revenueto fall below "economic rent" when project conditions are its budgeted level. Facedwith a revenueshortfall, favorable, and, at the same time, provide governments may have to cut expenditure or some early revenue. Although it istheoretically use debt to finance the shortfall, as increasing possible for the government to obtain the nonoil/gas revenue may not be feasible in the same economic benefit by combining short term. alternative fiscal instruments, in practice, fiscal instruments respond differently to changes in Depending onthe referencemarket, oil and gas project variables. As it is not possible to prices show a high degree of correlation. anticipate exactly how each project will The higher the correlation between oil and gas perform, the government will need to design pricesat the basisof Goy's revenuestream, the a fiscal system that is likely to accommodate less effective the use of a commodity the majority of the projects or conditions. In diversification strategy for mitigating price other words, the system should aim at volatility, that is, by adding gas to its revenue optimizing fiscal revenue at the country level stream, GOY may not be able to substantially as opposed to optimizing fiscal revenueat the reduce the volatility of its revenue stream. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK To insulate revenuefrom unexpected pricefalls, Thefinancial, legaland institutionalimplications different risk managementinstrumentscould be of setting up a risk management program vary considered, ranging from the creation of CSFs, according to the type of instrument used. to the use of market-based risk management Commodity hedging programs may requirethe instruments. Some instrumentsare more suited passing of legislation to authorize the program to manageshort-termpricevolatility, while others and establish the boundary conditions for its provide a more effective protection against implementation. Stabilizationfunds also require long-term price volatility. In particular, the use specific legislation regulating the objectives, the of market-basedrisk management instruments rulesfor accumulationintoandwithdrawal from (derivatives) could be more suited to stabilize the fund, and its governance structure. GOY'S revenue in the short term, while a stabilization fund could be created to manage No risk management program is without risk. the remaining interperiod volatility or more The objective of the program, its governance general risks related to the management of and the principles to be used to define its nonrenewable resource revenue. success, would need to be clearly specified at the outset and communicated to the Expertise is required to understand the risk parliament and the civil society. The political structure, identifyappropriate risk management implications of implementing and managing instruments and implement and supervisea risk the outcome of these programs should not management program. The design and be underestimated. implementation of a hedging program may be subcontracted, but the government would still Finally, before implementing a particular risk need to develop sufficient internal capacity to management program, it is good practice to monitor the program and communicate its set up a virtual program where different risk results to the relevant stakeholders. Similar management and hedging strategies would be considerations apply to the design and explored for a suitably long period of time to management of investment strategies for a determine their effectiveness, the relative costs stabilization fund. and ease of implementation. Annex 1 Government and State Revenue from Gas Sales Table A1.I :Revenue Generatedfrom Gas Sales to the Power Sector 4 Year OCGT Gar Price Gos Rice G m Price Gmrs Price Gor Price Gar Rice Gor Pim Gar Price Gas Rice TDfolGas Gus Plonf Quonfity (MMBTUJ Quontity (MMBTU) Quo* (MMBTU) Q u a n ~(MMBTU) Qwdity (MMBTU) Qwntity (MMBTU) Quontity ( W ) Quo* (MWU) Quonfity (MMBTU) Quohty Gwernrnent (Mw) (MMBTUl (-1 ( M T U l WBTUJ W W l ( M w l ( W N l (MMBTU1 IMMBTV) (hMBTU) k n u e (US$Million) 2008 360 20.7 0.7 20.7 14.5 -- - - Total 2,555 435.5 437.8 391.7 88.5 121.0 599.0 101.4 72.0 33.2 2,279.9 4,268.7 Note. Th~srevenuestream 1smkulotedbosedon the assumption that all gos to the power sedor is corningfmm GOY, or the ownerof the currentproven gas reserver In Block 18 It 1s further assumedthot all plants are OCGTplonts Source Authors' estimate EZ8'LZ 9EE'EL 065'8 8E.95 SSS'Z lolo1 6'60E'Z 6'8SO'L L'SP9 L'PE9 6'06Z P'LL L P'LPL 8'P9 S'6E P9'E 8ZOZ 7 E.6EZ1Z 8'6ZO'L S'OE9 E'S 19 O'E8Z Z'EL L O'LEL O'E9 9'8s P9'E LZOZ 6.0L L'Z S'LOO'L 9319 5'965 Z'SLZ Z'69 L 8'ZEL E' 19 L'LE P9'E 9ZOZ Z'SO L'Z EVL6 Z'L09 S.8LS L'L9Z Z'S9 L 8'8Z 1 9'65 8'9E P9.E SZOZ P'OPO'Z 6'996 O'L8S 9'09s L'S9Z E'L9L 6'PZ L Z.6S 6'SE P9'E PZOZ S'LL6' L 0'9E6 L'ELS P'EPS Z'LSZ S'LSL O'LZL E'LS L'SE P9'E EZOZ 8.916'1 E'906 9'655 L'9ZS 0'6PZ 8'ES L E'L L L S'SS Z'PE P9'E ZZOZ P'9S8'L 6'SL8 Z'9PS 1'01s L'OPZ 1'0s L 9'E L L 9'ES P'EE P9'E LZOZ L'L6L'L E'SE8 L'EES O'P6P S'6ZZ S'9PL 0'0 L L L'LS 9'ZE P9'E P9 OZOZ 8'L69'L Z'88L P'LOS S'8LP L'ZZZ O'EPL 9'90 L S'6P 8' LE SS'E SZ L 6 LOZ S'89SiL L'PZL P'OLP P'S9t 6'P LZ 9'6E L L'EO L 6'LP L'LE LE'E 09 L 8LOZ E'9SE' L 9'0P9 Z'LZP 9'LEP 6'EOZ O'PE L 1'96 P'SP 6'6Z PL'E L LOZ 8'ESZ'L P'66S L'POP 0'66E L'06L 9'8Z L 6'88 S'ZP 9.87. PL'E 008 9LOZ OV9L L'9LE Z'PSZ S' L8E 8'L8 L 6'9Z L 0 3 8 8'LP E'8Z OO'Z 0 s L SLOZ PLOZ 9.LZ9 E'SZE Z'SEZ P'LPE 8.181 P'LEL P'LL S'OP E'6Z 6L' L 96 ELOZ P'EPS L'SOE L'LZZ 6'8ZE 0 3 8 L P'LEL Z'EL Z'LP 9.0s S9' L OOP ZLOZ L'8EE 6'90Z E'P9 1 8'ZLE 1.161 L'LSL L'69 9'ZP 8'EE 80' L L LOZ S'SZE E'9LZ 9.18 L 9'00E 8'66 L L'89 L O'L9 S'PP 9'LE 80' L OOP OLOZ L'9PL P'LLL 0'96 0'986 E'L LZ Z'L8L L'E9 P'8P L' LP LS'O 600Z O'LPL Z'8ZL L'SOL O'SLZ 6'6PZ O'SOZ Z'L9 L'SS L'SP LS'O 09E 800Z as03 q 6 ! ~ as03 asog as03 M O ~ a s q q 6 ! ~ as03 asog as03 mol as03 q 6 ! ~ as03 asog as03 mol Table 81.3: Government and State Revenuefrom LNG Export Low Price Scenario - GovernmentTake StateTake Year HH JCC Gross Total Royalty Bonuses Fixed Profit FTP AOE/07 WB/ELA Quantity Project Tax Share Advance (MMBTU) Revenue Source:Authors' estimate. Table A1.4: Government and State Revenue from LNG Export Base Price Scenario - 2- z 6 GovernmentTake StateTake 4 Year HH Royalty Bonuses Fixed Profit AOE/07 WB/EIA Tax Share Advance 2010 711 391 - 2011 6 71 39 4 349 1,3846 ----- 2014 669 378 349 1,4030 -- -" 2015 673 38 7 349 -- 2016 698 39 3 349 2017 738 408 349 -- - 2018 740 42.0 349 2019 745 43 3 349 2020 772 442 349 -- - -- -- ---- -- --- 2023 858 495 349 ---- 2024 898 51 2 349 2026 9.37 54 6 349 2,0676 ---- --"- - 2028 1009 577 349 2,218 8 1775 1 1 0 27 972 1 -" *---- Source. Authors' estimate. Table A1.5: Government and State Revenuefrom LNG Export High Price Scenario - GovernmentTake StateTake Year HH Pjct Ups.Fee Pension . A , , 2009 7.97 46.7 275 2011 7.77 43.3 349 2012 7.44 43.9 349 1,543.7 ,,,*,., 2015 7.84 50.7 349 - -,w*" ,a, 2016 8.19 52.7 349 ..., ----,---,-,,,?,,,,A,,,,." 2017 8.59 54.8 349 -.+-.++.--..A..-,,.--..... 2018 8.47 57.1 2025 10.86 71.4 349 2,397.0 2026 11.45 73.7 349 2,522.8 201.8 1.O 2.6 1,094.4 2028 12.45 78.4 349 2,734.8 218.8 1.O 2.7 1,233.2 Annex 2 Gas-In-Place Gas-In-Place (GIP), April 2007 Trillion Cubic Feet (Tcf) Block Proven Proven + Proven + Probable+ (1p) Probable (2P) Possible (3P) Block-18 Marib 14.79 18.65 18.65 Block-5 Jannah 1.28 1.28 1.28 -- Block-S1 Damis 0.61 0.86 1.13 Block-9 Malik 0.23 0.43 0.89 Block-10 East Shabwah 0.45 0.63 1.09 Block-14 Masilah 0.21 0.27 0.33 Block-43 S. Hawareem 0.03 0.04 0.07 Block-32 Hawareem 0.01 0.02 0.03 Block-51 EastAl Hair 0.05 0.16 0.36 Block-S2 Uqlah 0.55 1.17 3.19 Block-53 East Saar 0.01 0.01 0.02 Total 18.22 23.53 27.04 - Note: Informationprovide by PEPA, April 2007. Annex 3 Tax and Nontax nstruments Box A3.1: Royalties ANNEX 3: TAX AND NONTAX INSTRUMENTS BoxA3.2: Taxes on Income: Ringcfencing, Corporate IncomeTax, Resource Rent Tax REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVEFRAMEWORK ANNEX 3: TAX AND NOMAX INSTRUMENTS Box A3.3: Import and Export Duties, Value Added Tax, Surface Fees, Bonuses REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Box A3.4: Government Participation .(I!o po3~ opasnasoy4 uoy~s!soq $uaJajj!p uo~uaLuu~a~o6aq4 punJ O ~ D J ~ U O ~ j ay4 uaanyaq4!lds aq04 l!o po3ssa3xaay4 of ap!noJd S ~ D J ~ Ualuos) ~uaLuu~ano6ay404Xpa~!psao6~!opo3ssa3xayqnday ~ D J V O ~ 'IJD!JXS ay4 u! punfdA63 u! 'alduroxa ~ o'alnJ ay4 04 suo!4da~xaam aJayl .SJD~Xsno!na~dw o ~Janopa!JJo>y s o paJano3aJunpuo j j ~ punf +so3+uaLuuopunqD'#!ydn Jualupanu! dupuau!j uo JsaJaJu!'a3uoMollo uo!qaldap pun ~0!4~!3a~dap's4so3 lo~do3pasuadxa 'sJso3 Bu!f~~adosapnpu! A J ~ A O PO3J'~DWJON 'S$U~LU~~UDJJD ~ ~ lOflPDJfUO3 04alqo~!lddoAl~oLuLu034da3uo3 DS! h a ~ 0 34SO3,,, a ~ REPUBLICOF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Box A3.6: Profit Oil Split ANNEX 3. TAXAND NONTAX INSTRUMENTS Box A3.7: Foreign Exchange Controls, Environmental Taxes and Bonds, Other PerformanceBonds and local Content Obligations REPUBLIC O F YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Annex 4 Undiscovered Fields Area covered by the survey: Ma. Rib Al Jawf, Shabwah and Masila Basins Source:World Petroleum Assessment 2000, USGS. REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Average Ratiosfor UndiscoveredFields, to Assess Coproducts (uncertaintyof fixed but unknown values) P Oil Fields Minimum Median Maximum Gas/Oil Ratio (cfg/bo) 2000 4000 6000 NGL/Gas Ratio (bngl/mmcfg) 30 60 90 Gas Fields: Minimum Median Maximum Liquids/Gas Ratio (bngl/mmcfg) 22 44 66 Oil/Gas Ratio (bo/mmcfg) SelectedAncillary Data for Undiscovered Fields (variations in the properties of undiscoveredfields) Oilfields Minimum Median Maximum API Gravity (degrees) 19 36 45 Sulfur Content of Oil % Drilling Depth (m) 750 2,500 4,000 Depth (rn)of Water (if applicable) V-12, 19, 2.3, 25, 26 V-2-26 ppm Ni-6, 7, 1.3, 5.0, 11 Ni-6-11 ppm Gas Fields Minimum Median Maximum InertGas Content (%) Co, Content (%) Hydrogen-SulfideContent (%) Drilling Depth (m) 750 3,000 5,000 Depth (m) of Water (if applicable) 0 0 100 Source: World PetroleumAssessment2000, USGS. Ma'Rib-Al Jawf/Shabwah/Masila, AU 20040101 UndiscoveredField-size Distribution 25-1 4 - 4 8-<16 16-32 32-<64 64-( 1$ w!ll!ou( 1$ W!ll!ou( 1$ W!ll!Ou( nup!s%( 4 10065 LZS% LP0% LOW LZS% IBO% ) 01065( lO0% lZS% lSO% 1010%1 10065 LZS% LSO% ----""---"--- ----- --- -- 6 "*"----""*" - * - - " ~e llwlr)~1991( ZOPE ZE 09 ZS 8L N Z059 ZE ZL ZS6L L8LO ZL Z9 ZE 6 L8PS Z089 ZE SS F *" Y --m---- Saurpw+tar . .--m---mm------- dJOPnP'OU +ZW 1LLE LLZL 98Z ZZZ% PZ9% 198E 10LE 9P6 ZZ I % PSS% 1996 LLZ8 LE6 ZPE% P90% LLS6 LLLZ LSL ZPI % VEL% --- 3 - t W 919 ZL9 151( l t P % 58069 91'9 ZL9 15'1( LP'P% 58069 LEP EP9 L 6 19065 s0064 8OE E60 1OL L9E% PSE% 8 - -- - ---- -- u ** dll>a +zO% 1609 LZEP L98 ZE I % PL P% L89L LZL L LSS ZEL% PZL% LLI 0 1195 LLE ZP8% PLS% 7 - 1850 LZP9 81 6 ZP6% VEL% ZO% P9Z 6 5 )IP~( LEP% 9PS% PPZ 8E )155( LEE% 99I% 9CL Z9E 0 8 1SI% 51I% LOO &OP EP ISP% C9Z% ----- 3od= +ZW 890 ESS L L LSZ% SSE% 8Z8 EEL 0 9 LSL% SLO% 68Z 5OL L9L L9L% P60% 1056 550 Z00 LLO% PSO% . --- -Z0% LSZ 6 698 91 P ZE L% PZ 065 LP6 L 6LO 9OP ZE 065 PEZ% LPO L 655 9EP ZSO% P98% LP6E 1009 99 Z ZP6% PSE% - - od= +ZO% 1059 591 ZZ9 LLP% SOO% LOZS 5PP ZL9 LL'P% SL'S% 1LEE 9LS ESL l6E% P9Z% LLLO 96'E E9Z L6'E% PP9% --- - ""-" -- - - 7 - -ZO% 1EES L8P P09 16P% tSP% lEOZ 1 9 5 E65 L6&% P98% LZLE 8OE P98 Z06% PL6% LE6Z 8L9 SLS ZLZ% VEL% --- dlOsdi'+ NOW d/Odll+ ~ Nh014 dlOsdI'+ dWSdl'+ 0 >lCldJo ZS E W E% 0 > 3ld'" 50 E W E% M4 > 1 L 065 NOI >S% 1065 ----" --- ------- ZS >OIdJO 50 tS% S% 50 > 3/dJO> 150 PS% S% I>%&> L'S EO% S%>QI> LS% E W -- -- -- -------- 50 > a dO' LS 90% 9% LSO > 31dlO > ZSO 9065 9% LS>MJ> Z PS% LS% > NOI >ZS% PS% LS > aldlo LW LS% 8% ZSO.3/ddJO > EOO LS% 8% Z > M4> Z 5 90% ZS%> aoB> E5% 90% -- ""-"--- m----- LW>O/dJO 60% LO% EW > 31dlo 60% L0% Z S > M4> E LS% ES% > NOI> PS% LS% --- ---- " P E >%14 6 W PS% > NOI 6065 ANNEX 5: FISCAL MODELSSIMULATION FigureA5.1: GovernmentTake and Proied'o IRR at Different C/R levels Oil - Oil GovernmentTake and ProjectIRR at DifferentCost RecoveryLimit FiscalModel 1 0.7 l r 160 Cost RecoveryLimit Oil GovernmentToke and ProjectIRR at DifferentCost RecoveryLimit FiscalModel2 inn 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 Cost Recovery Limit REPUBLIC OFYEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Oil GovernmentTake and Project IRRat DifferentCost RecoveryLimit FiscalModel3 Cost Recovery Limit Oil GovernmentTake and ProjectIRR at DifferentCost RecoveryLimit FiscalModel4 Cost Recovery Limit ANNEX 5: FISCAL MODELSSIMULATION FigureA5.2: GovernmentTake and Proiect's IRR at Different Price Levels- Oil Oil GovernmentTakeand Project IRR at DifferentPriceLevels , 0.7 r 0.45 Price(US$/bbl) Oil GovernmentTake and ProjedIRR at DifferentPriceLevels FiscalModel2 Price(US$/bbl) REPUBLICOF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK Oil GovernmentTake and ProjectIRRat DifferentPrice Levels FiscalModel3 25 30 35 40 45 50 55 60 Price(US$/bbl) Oil GovernmentTake and ProjectIRR at DifferentPrice Levels FiscalModel4 lDqleV;I*Z:qsopo+a~p D S dro!ap 4 zZ M ~ D I wopal NO' I/O!I ~ ! ~ J O I wopal NO' Z/O!I ~!SSDI WOPPNO' E/O!I ~ ! S ~ Q I WP~I NO' V/O!I 5 )V dropnp!ouSqD~!u6qosop ou: a~!4 d'OP"'~ou 3nwnlog~a dwpnalou a-jorlor 808 5 2LL 011 lUAaSlOJ,S t a ? goC' lUMSlOJ,S 18a BOC' IUA~SWJ,S I= goC' lUAJSqJ,S 188 30nI' N M 11'8 NdA 1038 NdA lDY8 N M )IQY~ 8 1$ W!II!OU( nu~!sa( lnupfsa( 1$ W!II!OU( 1$w!II!~~( 1$ WEI!OU( LOO% LZS% LSO% LOO% IZS% LSO% )QLo%I LOO% IZS% ISW lQ10%l LOO% IZS% LSO% # - 5Y d ~ 0 ~ " P 1 0 u ~ W 3 d ( ZOL IuAaW',' L6 P9 ZZ 1 8 S% PZ I % L8 L PS'8 ZZ E 1 8 S% PZ I % 8 I 0 P 6 0 ZL L 16 9% POP% 8ZS SO L ZL 9 16 L % E6P% ""----- 9 . . . - --- " "- " 3 dJ"a )E/WW3d( P S ------ ------- --- 3od= )0Wllliou( EOO N O W - z -- - " od1" $ / ~ 3 4 l O'ZO - - du31a'Wbl )$/W33( EEL ES9 E 6 P EZL ES9 E 6 P EOE EE9 E L P EOO EEP ELL -- - -- P --7 Seusl+bA$rar 14oP +ZO% LZ8E 8 9 E S S L ZE9% E9P% l Z 8 E 8 9 E SSL ZE9% E9P% LZOZ BEZ 5 S 9 ZP9% POP% l Z O P 8 2 5 SPS ZPE% POC% -- ------ -ZO% ZL L P L ]LZ Z( LE O% 9OS% Z L L P L ]IZZ( LEO% 9OS% E L Z P i 9 LL'S LPE% PL'O% PO'Z LP6 )Z 6( LPS% PZ L% dJ"a iZO% LEOL 8 8 E S L E ZE6% E9Z% LEOL 8 8 E SLE ZE6% E9Z% LL8O 8 1 $ SPE ZPS% PEP% l Z Z E 8PL SS6 ZPS% POF% --- *-- - 7 -ZO% ZSO l 6 )LPO( LZ L% 9Z8% ZSO L 6 ) I P ~ ( LZL% 9Z8% E P L 10'8 190I LPO% P8E% ELS L Z L )PL( I P PP I % -------- -- ......... 3od= +ZO% PE9 LEP 1 ~ 9 ( LP0% SSZ% PE9 LEP 1 ~ 9 ( LPO% SSZ% SSO ZPL Z L LSE% PES% SLL ZSS E Z ISP% P I P % m"*-- -ZO% l l Z S L L I S I Z ZP6% ESS% LLZS LL L S I Z ZP6% ESS% LOL L LL E P 8 S ZS9% t L L% LOL 9 LL 0 P 8 Z ZSS% PL 864 P -ZO% 81'1 P L 8 ZPO 18'869 PL 9% 81.1 P L 8 ZP'O .18869 PL 9% 8E 0 SL'S Z8S L6'8% POC% 8 P P SZP Z6'L L6'6% E6&' % d/O dl'l ~ q*4 d l O sdl!+ wdI4 d/~ d l a 0 d/)ES~IP -"" - - - -v " 0 2 ald'O > ZSO ZS% E% 0 > 3/d'O > Z8O ZS% E% Bd> I I@? L 9 8 > 0OS LO% - - ----- " - ZSO > ald'O > S")"M ES% S% -" -- Z8O > DdJo > 850 -7-- - ES% S% L> L'S EO% S > 8 0 8 > LS E0% -- "V s00 > aIdJO > LSO SO% 9% 850 > 31dlO >LPOO SO% 9% L ' S > M J > Z PS% LS> 10a> zs tS% ----. m * - LSO > aldlo > 1000 9S% 8% LPOO > >/d>I L)M lo 9S% I/!S=> ZS % Z> 90% -----7 ZF> dal> ES 9 W ------ - " LO% Z S > M 4 > E - LOW > a/dJ" 77 7 *- 8S% 1069 LLOO > >/dlO 8S% LS% ES> 103 > PS LS% - - - --- --- - NO+~3xdlo~p~toou d a ~ ts1aDohaAap osd o po$+qa >os+~a>o.,aL011 REPUBLICOF YEMEN: A NATURALGAS INCENTIVE FRAMEWORK FigureA5.3: GovernmentTake and Project's IRR at Different C/R Levels Associated Gas - NonassociatedGas GovernmentTake and ProjectIRR at DifferentCost RecoveryLimit FiscalModel 1 Cost RecoveryLimit NonassociatedGas GovernmentTake and ProjectIRR at Different Cost RecoveryLimit FiscalModel2 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cost RecoveryLimit 142 ANNM 5: FISCAL MODELS SIMULATION NonassociatedGas GovernmentTake and ProjectIRR at DifferentCost RecoveryLimit FiscalModel3 0.6 1 r 470 Cost Recovery Limit NonassociatedGas GovernmentTake and ProjectIRR at DifferentCost RecoveryLimit FiscalModel4 Cost Recovery Limit REPUBLIC O F YFMFN. A NATI IRA1 GAS INCFNTIVF FRAMFWORK Figure w.4: Government Take and Project's IRR at Different Price Levels Associated Gas - NonassociatedGas GovernmentTake and ProjectIRRat DifferentPriceLevels FiscalModel 1 Price(US$/MMCF) Non-associatedGas GovernmentTake and ProjectIRRat DifferentPriceLevels FiscalModel2 2.5 3.5 4.5 5.5 6.5 7 5 8.5 9.5 Price(US$/MMCF) ANNEX 5:FISCAL MODELS SIMULATION NonassociatedGas Government Take and ProjectIRRat Different Price Levels FiscalModel3 Price(US$/MMCF) NonassociatedGas GovernmentTake and ProjectIRRat Different PriceLevels FiscalModel4 2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5 Price(US$/MMCF) Note: The combined effect of royolties, cost recovery limit ond exploration tox may produce o Government Toke obove 700 percent. In these cases, the grophs show o Government Toke of 707 percent. Table A5.3: NonassociatedGas Project A P FiscalModd No. 1/0il FiscalModel No. 2/0il FiscolModel No. 3/0il Fiscal Model No. 4/0il (X Production-sharing bosed on: Doily Produdion Cumulative Production R-Factor Rate of Return Nonarsociated Gas Investor'sN W IRR Govt Investor's N W IRR Govt. Investor's NPV IRR Govt. Investor'sNW IRR Govt. (5 Mill~on) Toke (S M~ll~on) Toke ($ M~ll~on) Toke (5 Millson) Toke (@10%) 10.0% 12 5% 15.0% @lo% 10.0% 12.5% 15.5% @ 10.0% 10% 12.5% 15.5% @ 10% 10.0% 12.5% 15.0% -- - -------- - -- -+- --"+ Produd~on(MMCF)1,096 Investor's 558.2 364.3 2269 227% 34.5% 441.7 280.6 165.2 21.2% 48.2% 428.2 277.0 428.2 21.6% 49.8% 471.1 305.9 186.9 22.0% 44.7% Price ($/MMCF) 4.5 --- -- + Copex($ Mill~on)1,004 NOC's - . - Opex ($/MMCF) 0.25 --- -pp-M- Price L~mit($/MMCF) 2.35 2.70 3.08 2.53 2.91 3.32 2.31 2.70 3.10 2.28 2 63 3.02 Sensitivities: --- p e p - - - Prod. +20% 767.4 5278 355.5 265% 331% 599.3 406.9 267.4 24.7% 47.8% 558.5 386.4 259.4 25.2% 51.3% 606.4 414.1 274.6 251% 47.2% -20% 339.3 192.8 89.9 18.3% 39.2% 275.5 146.9 56.6 17.2% 50.6% 275.3 152.2 64.6 17.6% 50.6% 301.5 170.2 77.1 18.0% 45.9% - *-- - -- A""" --4 Price +20% --- 787.0 543.0 367.4 26.8% 32.3% 640.9 437.7 290.6 25.2% 44.9% 567.6 393.6 265.1 25.4% 51.2% 6117 418.8 278.6 25.2% 47.4% "- -" " ""- " ---a a -20% 3276 1839 830 180% 396% 243.3 1238 39.7 166% 55.1% 2701 147.6 605 174% 502% 3000 1686 754 17.9% 44.7% - "- em" Copex +20% 451 3 2660 135.5 19 1% 380% 341 8 187.9 79 1 17.6% 53 1% 373 7 217 2 105.4 18.5% 48 7% 393.8 229 7 113 1 18 7% 45.9% - -- - - - - - - - ---- *- Opex +20% 546 6 3 22 5% 34 7% 431.8 273.1 159 3 21.0% 484% 420 9 270.8 162.1 21.4% 49.7% 4605 2976 1803 21 8% 450% -20% 569.7 373 1 232 8 22.9% 34.3% 451.5 288.2 171.1 21.4% 48.0% 432.6 281.2 171.1 21.8% 50.1% 481.8 314.1 193.4 22 2% 44.5% - -+* --+------- Corp Tax In L~eu C/R Limd 70% Corp Tm In Lieu C/R Llmit 70% Corp Tox In Lieu C/R Limit 70% Corp Tax In Lieu C/RL~mit 70% h p l Tax 3% NOC 0 0% Expl Tox 3% NOC 0% h p l Tax 3% Royalty 3.0% Expl.Tax 3% Royalty 3.0% NOC 0% NOC 0% -+- - ---- *A P/O Split Royoliy P/O Spl~t Royolty P/O Spl~f P/G Spl~t --- - - * - - - -- - A A"* 0 c D/Pro c 250 25% 3% 0 < C/Pro < 280 25% 3% WF c 1 10% RoR c 5% 10% -- - -- - - -- - -- - 250 c D/Pro c -- 500 35% 5% 280 c C/Pro c 850 35% 5% 30% m v , --*-- 500 c D/Pro c 750 50% 6% 850 c C/Pro c 1400 50% 6% 1 5 c WF < 2 45% 15c RoRc 25% 45% - - ---- * + - - -" *---" 750 c D/Pro c 1000 65% 8% 1400 < CIPro c 1700 65% 8% 2c R/F c 2.5 60% 25s RoR c 35% 60% -- -- - " -- "- ---- " - A "- A "A --"A" " " 10% 1700 c C/Pro 85% 10% 2 . 5 ~WF < 3 75% 35c RoR c 45% 75% -"-- - --- 3 c WF 90% 45 c RoR 90% - -- - StressTest N W (10) (32.1) N W (15) (126 1) NW (lo) (4.9) NW (15) (145.0) N W (10) (38.4) NW (15) (1170) NW(1O) (54 1) NW (15) (109.8) -- - -- -- -a ma -"< , P ANNEX 5: FISCALMODELSSIMULATION Figure M.5: GovernmentTake and P r o i d s IRR at DifferentC/R Levels - NonassociatedGas Associated Gas GovernmentTake and ProjectIRR at DifferentCost Recovery Limit FiscalModel 1 Cost RecoveryLimit AssociatedGas GovernmentTake and ProjectIRR at DifferentCost RecoveryLimit FiscalModel 2 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 Cost RecoveryLimit REPUBLIC OF YEMEN:A NATURAL GAS INCENTIVEFRAMEWORK AssociatedGas GovernmentTake and ProjedIRRat DifferentCost Recovery Limit FiscalModel3 0.1 0 2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 Cost Recovery Limit AssociatedGas GovernmentTake and Project IRR at DifferentCost Recovery Limit FiscalModel4 Cost RecoveryLimit Figure A5.6: Government Take and Project's IRR at Different Price Levels - NonassociatedGas AssociatedGas GovernmentTake and ProjectIRR at DifferentPrice Levels FiscalModel 1 1.2 1 r 0.5 Price(US$/MMCF) AssociatedGas -, GovernmentTake and ProjectIRR at DifferentPrice Levels FiscalModel2 1.2 r 0.5 2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5 Price(US$/MMCF) REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK AssociatedGas GovernmentTake and Project IRR at Different Price Levels FiscalModel3 1.2 0.5 0.45 1.O 0.40 0.35 rr -z 2 0.8 f a m + 0.30 0 c a m f E 0.6 0.25 2 g E C f ' 0.20 0.4 (3 0.15 0.10 0.2 0.05 0 0 Price(US$/MMCF) AssociatedGas GovernmentTake and ProiectIRR at Different Price Levels ~iscaiModel4 Price (US$/MMCF) Note: The combined effect of royalties, cost recovery limit and exploration tax may produce a Government Toke above 700percent. In thesecases, thegraphsshow a GovernmentTakeof 101percent. 3 J!s'DI WoPal 2 NO' L/O!I ~ ! S ~ D W O P ~ I NO' Z/O!I I J!s>OI WOPOI NO' E/O!I J!S>OI WOPP NO' P/O!I - Y 3 P "m"-mr dJOP"V!OU )WW3b1'069 luAWoJ,s E9P'E Z09'S LOLC L6'Z% S6P% 5978 LP8 0 9P L LLF% 98'6% ZS9 LP9 9L L80% LOO% Z89 L 199 E 80'S 18 S% 99'P% s dJ!= )$/WW3b P'S 3 -- -- 30QddJJxx)1$$/'WWW!II3OJU(( LO'OS ' ' ZP N O J $ ZLL8 LSL'L 118'8 LL96 LEZ9 LOO'S LLZ LEL LOO L8S'L LE6'S L09'E 6 Z9S ELO ES8 Z'8L E'ES E 8L Z'99 &'LE E'LZ 6 E'OP E' - - " -- dJOP' +ZO% P6S'E EZE'L Z00S ZZS% S9'8% ELL'L ZE6'L LE8'6 ZO'8% 9L'L% ESO'O ZZSY LEP'L ZL'O% 96S% E8ES ZPS'O LPP'8 ZL'L% 99Y% -ZO% L88S 8 L L L'Z E% 9C% PE8 P69 )191( LPE% LPZ% LPPL SPP ) 6 ~ ( LP9% LPL% 19EO 9LO )OL( lS'O% LO8% +"A " " .L-S"' " . " .9. - - - ~L -------- --- d u a +ZO% ~06.c 206.0 zZ 8% S9C% P09'6 ,790,8 .7- LSS'E ZL'E% 9SW% ES9'P ZEO'L LE8E ZL.Z% 96.E% EEL P ZPB'P , , P P LPL'L ZL'z% 99 L% -" EE'Z )~8.1( LE'L% LL'L% LPO'8 s0'6 )LZ'9( LP'P% LP'O% L9L'L 95'9 )z'z( LP'6% LOC% -----"- -" --------- " -- * -"- " ------------ -""77 ---< " " -ZO% PELS 289'9 18Z'E ZE'P% SS8% EP9'L ZZS'P LEL'L ZL6% 9P'S% E09'L ZOZO LZP8 ZL6% 98'9% EL9'0 ZOS'P lZP'8 Zl'L% 9L'L% - ---- ---- "-"" "---- Odax +ZO% EE%l Z00C LOZ'E L6W% S6'9% ZSL% LPZY 90'P lL'9% 96.Z% ZSO'8 LPLL 9E'O LL'8% LO'L% ZL8S 190'P LS'8 L8'E% 99'L% - P - Z W ESPS ZLZ 8 LLZ'L L6'P% S6'L% ZLL'8 LSE'P 98'6 LL'6% 98 L% ZS6C LP6C 96'9 18 L% LO L% Z6E'L L LZ'E 8S'Z L8'9% 99C% ---"" " ----m -. 0 > a/dJO > ZSO ZS% E% 0 > 3/dJO > Z8O ZS% E% lh4 > L LO% 808 S% LO% -- ZSO > l(/dJO > -00 - s ES% S% Z80>3/dJO--- 8S0> ES% S% L'S ---- EO% ---S > 808 > 1S% E W ---- -- --- - ----- s00 > a/d'.Q > LSO "" " " """- * SO% 9% 850>3/dJO> LPOO SO% 963 L ' S > l h J > Z PS% LS> 8ON> ZS% PS% """ -- -- -- -- LSO > a/d" > L 000 9S% 8% LP00 > 3/dJO > " -L"LOO 9S% " ---- --8% Z> lhJ > Z.S 90% ZS > YO8 > ES% 90% Annex 6 Hedging with Derivatives: Examples and Strategies ThisAnnex containsexampleof simple hedging government did not know what the actual strategies that the government of a price of gas will be. Hence, itsfiscal revenue gas-producing country may consider in order is exposedto the risk that unforeseenshocks to make its revenue stream more stable, and to may cause the spot price of gas to fall below protect it from unexpected price swings. The the budgeted price. To protect its revenue government could hedge its royalty and from the risk of an unforeseen pricefall, the production tax revenue because these revenue government could decide to sell a series of streams are directly tied to gas prices. It is futures contractswith deliveriesmatchingthe important to note that the use of futures and pattern of the fiscal revenue to be hedged. options does not oblige the hedgerto deliver or The governmentwould not needto hold the take possession of the underlying asset as the contracts until expiry (otherwise, it would be position can be reversed before the expiry of obliged to deliverthe correspondingquantity the futures contract. of gas): each contract would be terminated through a reverse transaction in the futures Hedgingwithfutures. Futurescontractcan market (buyingfutures beforeeachcontract's be used to lock into the prices available in expiry date). The graph below shows the the futures market. For example, the payoff to the government for selling a government may have prepared its budget futures contract. based on the expectation that the price of gas would haveaveraged US$7.5O/MMBTU One possible strategy could be to sell, four in 2006. At the time of budget preparation months ahead, futures contracts in a quantity (for example, in September 2005), the equivalent to the monthly revenue to be FigureA6.1: Payoff for Selfing a Futures Contract REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK andbuyfuturescontracts inthe same effectiveness of the strategy and/or to limit the monthlyquantity one month ahead of the expiry losses.The governmentwould incur losseswhen date of each futures contract sold. Had the the market moves against its position. Because government applied this strategy in 2006, it futures contracts are marked-to-market each would have obtained an average gain in the day, cashtransfers to and from the brokerwould futuresmarketof US$1.24 MMBTU, whichwould take Inaddition, the governmentwould have increased the average gas price for the have to pay the margins for each contract it year from US$7.07 MMBTU (the unhedged or bought and sold. Hence, to executethisstrategy, spot price)to US$8.31 MMBTU.271The result of the government would need to secure enough this strategy is representedin the graph below. liquidityto face itsobligations toward the broker. Specific budget appropriations may be needed The success of this type of strategy depends on to honor these obligations. the relationshipbetweenfutures and cash prices, the market outlook and the timing of the hedge Hedgingwith options.Whereasthe holder (forexample, the resultof the strategy illustrated of a futures contract has an obligation to above would have to be different if hedging is perform (that is, the holder is committed to done 12 months ahead instead of each a price inadvance), an option givesitsholder quarter272).Triggersfor sellingand buyingfutures the rightto choosewhether or notto perform. could also be established to improve the In our example, instead of committing in FigureA6.2: Selling Futures Four MonthAhead 11.5, - - Spot Price Hedged Price Sources: NYMEX, the Energy Information Administration and the World Bank TreasuryDepartment. 270Because futures contract are based on MMBTU of gas, the government will have to determine how many MMBTU it will have to hedge to protect its anticipated revenue. In other words, it would need to determine the hedge ratio (seebelow). To be noted that the hedge ratio can be calculated also with respect to cash revenue from royalties, production-sharing and corporatetaxes, that is, the government can hedge its revenue stream whether or not it has access to the physical commodity. It is important to note that producing companies are quite likely to have a hedging program. The objectives and success of the program, and accounting treatment of gains/losses arising from the program may affect the level of tax revenue of the host government (Statoil Steers the Coursein Risk Waters Group Ltd, 2000). 27'In the example, spot and futures prices are quoted with reference to the last trading day of each month. To simplify, we have assumed that the actual price that the government receives each month correspondsto the spot price on the last trading day of the month. Although, in reality, this may not be the case -the hedge is not perfect-the profit generated in the futures market would contribute to compensatethe loss in actual revenue compared to the budgeted revenue. 272The more liquid segment of the market is the near term, one to four months into the future. Hence, it could be difficult for a government who needed to hedge large quantities of gas to do so further out into the future. 273However, the government could choose to trade futures in the OTC market, and structure the transaction to provide for less frequent settlement -for example, monthly instead of daily -or settle on a price average instead of the daily closing price, etc. 154 ANNEX 6 : HEDGING WITH DERIVATIVES: EXAMPLESAND STRATEGIES September 2005 to a price in January 2006 hedge at US$1 below futures prices, thus (four months in advance), the government ensuring that it would at most lose could have bought put options and locked US$1/MMBTU (plus the cost of the options) intothefutures price, butwaited untilJanuary from what the futures market predicts it 2006 to decide whether or not to enter into should earn, while still maintainingfull upside the contract. In other words, with futures, the price potential; government locksin a price, with optionsthe government pays a fee to guarantee a ' Determine a minimum gas price to minimumprice, while retainingthe possibility protect with a hedge and P ~whatever the Y of receiving a higher price. Options are C O S ~of options for that strike price. traded for a number of strike prices below For example, the strike rice could be set to and abovethe marketvalue of the underlying correspondtothe minimum gas price below futures contract.274Thefurtherawaythestrike which the government's ability to finance price is from the trading price, the lower the essential expenditure Programs would cost of the option (the premium) because be compromised; there is less likelihood that the option will be Budget the amount the government would exercised. The further out in time, the more be willing to pay for an insurance policy an option at any given strike price costs and select the strike price that would because of increased price uncertainty and exhaust this amount. The government the longer period of time the option holder could follow this approach to maximize the is protected from adverse price movements. level of protectionwithin the limit of existing Options-based hedging strategies the financial constraints; and government could implement include: Purchase put options at strike pricesat some Purchase put options at strike pricesat some level below the futures price for each month level belowthe futures pricefor each month. and sell call options at a strike prices For example, the government could elect to Figure86.3:Payofffor Buyinga Put Option FigureA6.4: Payoff for Buying a Zero-cost Collar Unhedged Position 274TheNYMEXoffers a total of at least 8 7 strike prices in the first three nearby months and a total of at least 67 strikeprices for four months and beyond behveen in-the-money (above the price of the underlying futures) and out-of-the money (below the price of the underlying futures) strike prices. The increments vary for nearby (US$O.OS/MMBTU) and far out (US$0.25/MMBTU) months. Options are also traded in the OTC market, where the contract terms can be customized to beffer suit the needs of the parties. 155 REPUBLIC OF YEMEN: A NATURAL GAS INCENTIVE FRAMEWORK corresponding to the fee that exactly offsets option was higher than the spot price, it would the fee it must pay for the put option.275This have obtained an average yearly price - net of strategy is called a "zero-cost The the cost of the premium - approximately the governmentwould notincurthe out-of-pocket same as the spot price (unhedged price). cost of the premium, butwith the saleof a call A graphical representation of this strategy is option it would sacrifice the upside revenue shown below: potential from higher prices. The put strike Hedging with swaps. As for all OTC price would, however, provide guaranteed contracts, commodity swaps can be minimum revenue. customized to suit the specific needs of the The graphs above below show the payoffto the participants. For example, should the government for selling a put option, and for government seekto achievethe averagegas entering into a zero-cost collar. price for a given month using exchange- basedfuturescontracts, itwould needto settle As for the futures strategy, the governmentwould contracts daily throughout the month to have to determinethe timing of the hedge and receivethe monthly average price. The terms the amount to be hedged. For example, if the of an OTC swapcontract, onthe other hand, government had decided to hedge its 2006 could be explicitly based on the monthly expected monthly revenue stream two months average price, simplifying program ahead by buying options for a strike price of management. Alternatively, an OTC US$1.O/MMBTU lower (US$1OTM-Out of The swap contract could be written to average Money - Put) than the market value of the the price over several months, thus, underlyingfutures contract(2" near bycontract), smoothing government revenue, or to it would have exercisedits option inAugust and settle less frequently - monthly instead of September only, when the strike price of the daily - thus reducing overhead costs. FigureA6.5: Buying Out-of-the-money Options Two MonthsAhead 9.0 8.5 8.0 7.5 7.0 6.5 6.0 5.5 Jon Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 1- - - Futures (2nd NbY) Spot Price Hedged Price I Sources:Nymex, the Energy Information Administration, and the World Bank TreasuryDepartment. '''For any put option strike, price with a fee establishing a seller's floor, there is a call option strike price with an identical fee establishing a purchaser's ceiling. 276Put-and-call options can, of course, be combined to generate more complex hedges, at zero or near-zero cost. ANNEX 6 : HEDGINGWITH DERIVATIVES: EXAMPLESAND STRATEGIES FigureA6.6: Payoff for Selling a Swap The payoff for selling a swap is shown in for gas during the entire budget year would the graph below. be US$6.50/MMBTUt no matter what the spot price turns out to be. For this insurance, the As mentionedabove, the partiescan customize government would give up the possibility of the terms of a swap to fit their specific needs. benefiting from an increase in price above For example, the government may enter into a US$6.50/MMBTU. A graphical representation fixed-for-floatingswapwith a financial institution, of this strategy is shown below. on the basisof which atthe endof each calendar month the governmentwould pay the financial In our example, the minimum gas price that institution if the spot price is higher than the government secured turned out to be US$6.50/MMBTUt and would receive below the actual market price in seven over payment from the financial institution in the the 12 months the hedge was in place. The opposite case. The value of such payments government secured a fixed price of US$6.50/ would correspond to the difference between MMBTU for each month. Had it not entered spot price and reference price multiplied by into the swap, it would have obtained an the notional amount of the contract (that is, average price of US$7.07/MMBTU over the the volume to be hedged). With this strategy, year, but it would have experienced ample the government would ensure that the price variations in price across the year. FigureA6.7: Settingthe Pricewith a Fixed-for-floating 9.0 8.5 8.0 7.5 Unhedged Position 7.0 6.5 6.0 5.5 - -Fixed NatGas Spot Price Sources: NYMm the Energy Information Administration and the World Bank Treasury Department.