principles and applications - documents & reports - all...

V-eOV5ZO

Energy Sector Management Assistance Progamme

Principles and ApplicationsReport No. 152/93

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

JOINT WNDP / WORLD BANKENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP)

PURPOSE

The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) waslaunched in 1983 to complement the Energy Assessment Programme, established three yearsearlier. ESMAP's original purpose was to implement key recommendations of the EnergyAssessment reports and ensure that proposed investments in the energy sector represented the mostefficient use of scarce domestic and external resources. In 1990, an international Commissionaddressed 1ZSMAP's role for the 1990s and, noting the vital role of adequate and affordable energyin economic growth, concluded that the Programme should intensify its efforts to assist developingcountries to manage their energy sectors more effectively. The Commission also recommendedthat ESMAP concentrate on making long-term efforts in a smaller mnmber of countries. TheCommission's report was endorsed at ESMAP's November 1990 Annual Meeting and promptedan extensive reorganization and reorientation of the Programme. Today, ESMAP is conductingEnergy Assessments, performing preinvestment and prefeasibility work, and providing institutionaland policy advice in selected developing countries. Through these efforts, ESMAP aims to assistgovernments, donors, and potential investors in identifying, funding, and implementingeconomically and environmentally sound energy strategies.

GOVERNANCE AND OPERATIONS

ESMAP is governod by a Consultative Group (ESMAP CO), composed of representatives of theUNDP and World Bank, the governments and institutions providing financial support, andrepresentatives of the recipients of ESMAP's assistance. The ESMAP CG is chaired by the WorldBank's Vice President, Finance and Private Sector Development, and advised by a TechnicalAdvisory Group (TAG) of independent energy experts that reviews the Programme's strategicagenda, its work program, and other issues. ESMAP is staffed by a cadre of engineers, energyplanners and economists from the Industry and Energy Department of the World Bank. TheDirector of this Department is also the Lmnager of ESMAP, responsible for administering heProgramme.

FUNDING

ESMAP is a cooperative effort supported by the World Bank, UNDP and other United Nationsagencies, the European Community, Organization of American States (OAS), Latin AmericanEnergy Organization (OLADE), and countries including Australia, Belgium, Canada, Denmark,Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway,Portugal, Sweden, Switzerland, the United Kingdom, and the United States.

FURTUER INFORMATION

Fo. further information or copies of completed ESMAP reports, contact:

ESMAPclo Industry and Energy Department

The World Bank1818 H Street N.W.

Washington, D.C. 20433U.S.A.

LONG-TERM GAS CONTRACTS

PRINCIPLES AND APPLICATIONS

JANUARY 1993

A RPORT PREPARED BY THE OPSRATIONS DIVISION OF

T JOIT UNDP/WORLD BANK

ENERGY SECTOR MANAGEMET ASSISTANCE PROGRAMM

(ESMAP)

This document has been prepared as part of ESMAP's effort to disseminate information of potentialinterest to technical and policy personnel in developing countries. The paper embodiec the views of itsauthor and does not necessarily reflect the official position of ESMAP, the UNDP, or the World Bank

CONTENTS

PREFACE ............... ............................ ix

ACRONYMS AND ABBRE ATAIONS .......................... x

1. INTRODUCTION .......................................... 1

2. MAIN FEATURES OF THE O1L AND GAS CHAINS ............ 5rhe Oil Chain ........... .. 6The Gas Chain ............... .... 8Comparison between the Oil and Gas Chains .................. .. 8Resulting Issues for a Policy to Promote Gas ................. 10

3. PRODUCTION-SHARING AGREMENS ..... .............. 13Present Situation ........................................ 13Requirements for a Domestic Gas Industry ................... 13

Gas Provisions in Production-Sharing Agreements .......... 14Elements to be Addressed by a Policy Favoring Gas ......... 15Production Facilities (Offshore or Onshore) .............. 16

Promoting an ndigenous Gas Market ...................... 16Delimitations between Distibution and Production Spheres ... .. 16The Role of a Trading and Transport Company .... ........ 17Pricing Policy .............. .................... 17Environmental mpacts and Safety . ................... 19

4. REGULATION OF THE GAS CHAIN . ................... .. 21Man Models ........................................... 21

Model I .......................................... 21Model 2 .......................................... 21Model 3 .......................................... 21

Implications for the Contracts to be Concluded ................. 25

S. A BASIS FOR LONG-TERM GAS CONTRACTS, PART I ......... 27Some Basic Considmeions ...................... .. ..... . 30Knowing the Iartners of the DJd ........................ . 35ElandlingtheContrac ......... ............................... 38AscertningCommonInterestsOutsidetheDeal ............... 41

iii

6. A BASSq FOR LONG-TERM GAS CONTRACT'S, PART II ........ 43Commercial versus Technical Elements of the Deal .............. 43Commercial Elements of the Deal ........ ................. 43

Delimitation of Spheres ................... ........ 43Obligation to Invest in a Project ........ ............. 45Quantity and Quality ....... . ................ . ... 46

Provisions for Dealing with Quantity and Quality Issues inthe Contract ............... ...... 47

Possible Degrees of Commitment ... ............. 52ProfUe of Commitment .......... ............ 53Instruments for Flexibility in Gas Contracts .......... 56Technicalities of Handling the Gas Flow ............ 66Quality Specification 4 * ........................ . 67

Pricing Provisions in General ....................... 68Pricing Provisions in Detail ............................. 74

Cost-plus Approach ........................ 74Market Replacement Value/Netback Approach ........ 75Information ..................... 89Technicalities ............................ 89

7. WHAT IS DIFFERENT FOR GAS-TO-POWER PLANTS? ......... 91Basic Features of Gas-to-Power Plants ...................... 91Contractual Consequences ..... * . ............................ . 93

Who are the Partners to the Contact? ..... ............. 93Rules for Handling the Contract ................... . 93Commercial Elements of the Deal ................ ..... 94

Delineation of Sphes ........... . .......... . 94Project Investment. ......... ***...........*..* 44... 94

Prose * .................. * ..............*.* 94Quantity-related Aspects . ......... ..... .......* . 94Quality-related Aspects . ..... ............... . 96

Pricing ...... ... . . ... *.............................. 97Gas Pricing Based on Cost-plus Considerations ............ 97Gas Pricing based on Netback Considerations ............. 97Conclusions on Pricing . .... ...................... * 101

8. WHAT IS DIFFERENT FOR GAS CONTRACTS WITH UTLiTS? 105Specific Features of Utilities . .......................... * * * * * * 105SpecificIssuesinCon actsbetwee UtilitiesandaPipeline ........ 107

WhoArethePartners? ............ * . 107

iv

How Should the Contract Be Handled? ................ 107What Are the Commercial Elements of the Deal? .. ........ 107

Delineation of Spheres ............. ......... 107Investment Obligations t...................... 108Quantity Commitments ... .................. 108Sharing of Risks ....... .................. 109Incentive Scheme ... .............. ......... 109Q11aity .. .................................. 109Pricing .. ...................... ....... 109Information ... ................... .. ..... . 109

Relations Outside the Deal ........................ 109

9. GAS IN DEVELOPING COUNTRIUES ................ ...... 111Wbat Is Different for Developing Countries? ................. 111

Location ................................... Il.... 1Economic Situation ..... ........................... 112Political Situation ....... ...................... 112

Consequences for Gas Con Ct r ................ ...... .. 113Who Are the Partners? .... ................... ....... 113How Should the Contract Be Handled? ... .............. . 113

Applicable Law ....................... .. . 113.irbitration ................................... 113Changed Circumstances . .............. . .. . .. . 113Interference of Government ........... .. ...... 114

Commercial lements of the Deal ..... .............. 114Quantity . .................................. 114Price .. .................................. 114Currency . .......... . ............ 115

Relations Outside the Deal ............ ... 115Concluding Remarks ... ............................ . 115

APP X ........................... 117

v

LIST OF TABLES

TABLE 1. Possible nfluences on the ormulation of a Gas Deal ....... . 2TABLE 2. Basic Characteristics of Gas Relevant to Contracts .......... STABLE 3. Oil Chain versus Gas Chain: Main Characteristics .......... 9TABLE 4. Main Groups of Elements in a Gas Contract .............. 31TABLE 5. Some Negotiating Principles of a Gas Sales Agreement . ...... 32TABLE 6. Who Are the Partners cf the Deal? ........... 37TABLE 7. How to Handle the Conta ct ............. 39TABLE 8. Possible Relations Outside the Deal .... 42TABLE 9. Commercial versus Technical Elements of the Deal 44TABLE 10. Main Types of Risk-sharing between Reservoir Management and

arketing ................... 49TABLE 11. Negotiation of the Price Provisions ................... 69TABLE 12. Issues nfluencing the Pricing Provisions ................ 70TABLE 13. Main Mements of Pricing ..................... . 85TABLE 14. Elements of a Price Reopener .............. 88TABLE 15. Scheme for Netback Pricing Approach for Gas to Power ..... 102

LIST OF FIGURES

FIGURE 1. The Oil Chain ................................. . . .. 7FIGURE 2. The Gas Chain ... .............. . 11FIGURE 3a. Model 1: Government Control of Gas Downstream of

Production .......................... 22FIGURE 3b. Mocel 2: Transportation of Gas as a Regulated Service ....... 23FIGURE 3c. Model 3: Transporter Acts as Trader; Demarcation Possible .... 24FIGURE 4. Balance of Commitments in Long-Term Gas Contracts ....... 33FIGURE 5. Typical Phases or Profile of a Long-term Gas Sales Contrac .... 54FIGURE 6a. Seasonal Flexibility with Daily Capacity Equal to

Average Annual Capacity ................ 59FIGURE 6b. Seasonal Flexibility with Daily Capacity Greater than

Average Annual Capacty .............. . 60FIGURE 7a. Replacement Value of Gas versus Competing Fuel/Netback..... 76FIGURE 7b. Sharing of the Market Value: Netback Case .... 79FIGURE 7c. Sharing of the Market Value: Cost-plus Case .... 80

vi

FIGURE 7d. Sharing of the Market Value: Mixed Case (Between Netback alidCost-plus) ......................................... 82

FIGURE 7e. Sharing of Good Times and Bad Times: Coincidence of Profitand Loss Zones . ......... .................. . 83

FIGURE 7f. Sharing of Good Times and Bad Times: Inequity of Profit andLoss Zones ........... ........................ a4

FIGURE &a. Netback Gas CC versus Coal/Steam: Investment and Annuity ... 98FIGURE 8b. Netback Gas CC versus Coal/Steam: Cents per kWh ......... 99FIGURE 8c. Netback Gas CC versus Coal/Steam: Cents per kWh with Gasoil

and HFO ........... .................... . 00

vii

PREFACE

Many developing countries have not yet exploited their natural gas reserves at-or evennear-their full potential. Bringing new reserves of this efficient and environmentallybenign fuel onstream requires the development of markets for gas at prices that arecompetitive with other energy sources and that give suppliers reasonable returns.Moreover, establishing a sound gas industry requires a carefully defined institutional andregulatory framework and appropriate financing.

The negotiation of contracts between suppliers and buyers of gas is one of the firstand most important steps in planning and implementing a gas project. This report, aimedat energy and financial decisionmakers in developing countries, sets out the prevailingtypes of contractual arrangements for gas and seeks to convey some insight into theirvariety and nuances. The report also provides a framework for negotiating long-tenn gascontracts in national and international settings among both developing and developedcountries. The parties to such contracts, who may have particular interest in this report,include the buyers and sellers of natural gas, governments, financing institutions, andregulators.

The report was prepared by Mr. Ralf Dickel, Energy Economist in the OperationsDivisica of ESMAP, 1991-92, and is based mainly on the experience of the Europeancountries, where international gas trade has accelerated markedly during the last threedecades.

ix

ACRONYMS AND ABBREVIATIONS

CAPEX capital expendituresCC combined cycleCGCC coal gasification combined cycleCIS Confederation of Independent StatesCNG compressed natural gasDCF discounted cash flowESMAP Energy Sector Management Assistance Programmeacv gross calorific valueHFO heavy fuel oilkWh mowatt iftoursLNG liquefied natural gasLPG liquefied petroleum gasNCV net calorific valueNGL natural gas liquidsNPV net present valueOPEX operational expendituPSC production-sharing contactorUNDP United Nations Development Programme

x

1. INTRODUCTION

1.1 Natural gas contracts vary considerably from country to country and from caseto case because of the large variety of possible aanngements between sellers and buyers(see Table 1). It may well be impossible to design a standard gas contract that coversall vossible cases.' For this reason, a detailed understanding of thevariety and nuancesof possible contractual arrangements regarding natural gas is essential for all countriesproducing or consuming gas.

1.2 The basic philosophy of an agreement is to reflect the balance of commercialinterest of the contract partners. The most fruitful approach for gas is to show how theinterests derived from the properties of gas and the gas industry can be reflected incontract provisions. Two main aspects of gas contracts can be differentiated here: (a)technicalities linked to quality, metering, and so on; and (b) commercial elements linkedto capacities and money.2

1.3 Systematic insight into the elements of gas contracts is not easy to come by,unfortunately. Although a few publications discuss some of the technical aspects of gascontracts, little publicity is given to the commercial elements of large gas contractsbecause, unless a country's regulatory environment provides otherwise, the details of gasdeal. are most often kept confidential. Most Continental European gas contracts, andmost liquefied natural gzs (LNG) contracts, are kept confidential, for example. Thepurpose of this paper, therefore. is to illuminate the geral character of both the techni-cal and commercial elements of natural gas deals and to analyze and discuss ways tobalance the interests of the parties to the deal. This basic approach can then form thebasis on which a fair balance can be fixed by contract on a long-term basis.

14 Gas essentially has a special relation to oil that reflects both its similarities anddifferences. On the one hand, gas is often discovered and produced by the same industryin connection with oil or at least in the same process, using the same tools. The end user

1. A set of standard conracts may be reasonable whe eircumn are msiilar-for examle, whenmany selers or buyers, respectively, aply smilar conditions to one contract partner. Typical examplsare sndard gas sales conacts for housholds or for a spcfic class of commeria consum. However,conbac tat m eminently reasonable under crtain cirotances may not be applicable at all in odersiuations.

2. In this paper, the tem conma is used to describe an agreement tat has been fixed in writing.Agrene is used in the sen of an ug between two pries, inde d of the way it isfonnaized. Deal is used to characterize a possblo baan of inlerest bwn two paties, whelher agreedor not.

2 Long-Term Gas Contracs

can always substitute gas with an oil product. Yet on the other, the user cannotsubstitute oil with gas in all its applications, especially in vehicles. In effect, betweenthe wellhead and the end user, gas has a totally different nature from oil3

TABLE 1. Possible Infl:Jences on the Formulakon of a Gas Deal

Seller (Producer) Buyer

0 Gas-to-oil ratio a Market structure, number ofcompetitors

* Size/productivity e Market structure, sector mix

* Quality * Status of the gas market

a Offshore/Onshore * Climate in the region supplied

a Distance to the market * Geography of the region supplied

* Pipeline/LNG * Free capacity in infrastructure

* Seller's position o Number of existing suppliers inthe field

* Field's priority in seller's v Number of potential suppliersportfolio

* Number of potential buyers * Growth of demand

T lumber of competing suppliers * Competing energies

Note: Assum.ag at least two alternatives for each item listed there are 1,024 combinations on the seller's sideand 1,024 combinations on the buyer's side, resulting in over 1 million combinations of both sides. Possiblepolitical and legal parameters (tax regime, rogulatory frame, applicable law) have not even been taken intoaccount. Hence, a standard contract can hardly cover all possible constellations.

1.5 The paper begins by comparing gas and the gas industry with oil and the oilindustry. The two fields are obviously related, but they have differences that may beboth distinctive and instructive. For example, oil-product contracts are relativeiystraightforward because oil can be tded by individual buyers on a case-by-case basis.

3. In a sense, gas seems more like a service than a commodity. However, compared with a service,for which there may be no altemadve, gas may be substitued by oil products, and this substittion mayextend even to the specific devices for using the product.

Introduaion 3

Oil is also relatively easy to store, and the participants in an oil deal have someflexibility in that they do not need to be linked for the lifetime of the investment. Gas,in contrast, is neither easy to store nor to transport, and it is tightly linked to facilitieswith defined capacities all the way from the wellhead to the customer.4

1.6 The initial consideration in gas contracts is usually given to explorationspecificaly for gas, as in a production-sharing agreement or a license agreement; gasfirst must be made available before it can be traded. One contract partner of suchagreements is automaticaUy the state, in which the interest in possible subsoil mineralsis vested. Because most current production-sharing or license agreements address oil andapply to gas only in a restricted context, only limited know-how is available. However,some aspects of current gas-specific production-sharing or license agreements can beelucidated, and the paper attempts to describe a preliminary framework for gasexploration contracts.

1.7 The paper's central focus is on the elements of long-term gas contracts and themain commercial motivations for them. The concentration is on long-term pipelinecontracts because these seem most relevant for developing countries. LNG is a specialcase, which mainly involves exports to industrialized countries. Spot deals, whichpresuppose a highly developed gas industry, typically with spare capacity in the gassystem, usually do not apply to developing countries. Similarly, gas transport servicesoffered by gas producers are not typical for developing countries and are only brieflytouched upon. The paper does describe examples of regulatory frameworks, which areextremely important to the strucure of the industry.

1.8 The insights presented here are derived largely from the author's experience innegotiating major long-term gas agreements between large buyers and sellers inContinental Europe. The European situation seems more comparable to that ofdeveloping countries than that of the United States, for example, if only because the U.S.gas market is so much larger than that of all other countries except the Confederation ofIndependent States (CIS). The details presented here thus may relieve policymakers indeveloping countries of some need to retrace paths already broken in Europe. Inaddition, however, the paper seeks, insofar as possible, to emphasize issues that may benew or especially important to developing countries.

4. Natural gas liquiJs (NGLs) are a ind of halfway product between gas and oil. On the one hand,tike oil, they are liquid at normal atmosphefic pressure and can be easily tasported and stored, wheas,on the other, they are similar in chemical and combustion properties to gas. NOL contacts are not treatedhere, however, this paper istead deals wi the economc and cmmea consequences denved from, andspecific to, the properties of naual gas.

4 Long-Teim Gas Contracts

1.9 The paper lists points that negotiators may have to address in long-term gascontracts and presents and discusses possible solutions. The lists of problems andsolutions, together with the table of contents, constitute a kdnd of checklist fornegotiators. It should be noted, however, that the nature of the subject makes it virtuallyimpossible for the lists to be exhaustive, and some problems and potential solutions maynot be mentioned at all.

1.10 A further problem with prescribing any sort of packaged approach to gas contractnegotiations is that regulation of gas markets in Anglo-Saxon countries has becomeincreasingly complex over time. This should signal a warning with regard to"pernanently applicable truths" in the gas business:

In general, no person and no guide can liberte anyone representng a pc.4ty ina gas deal ftrom the responsibility of attending conscientiously to the specificinterests of that party in the negodating process or frm the responvibility offinding compromises ha both represent the interest of the party being representedand are acceptable to the other party.

2. MAIN FEATURES OF THE OIL AND GAS CHAINS

2.1 The basic issues for all important commercial decisions in the gas business areshown in Table 2. When comparing gas and oil it is important to remember that gas isalmost exclusively linked to transportation by pipelines and that it entails a high fixedinvestment for transportation and distribution that cannot be changed easily or at all onceit has been made. In addition, although oil can be marketed at almost any time in almostany place, gas is limited to specific places and periods of consumption. Gas cansubstitute for oil (or coal) in many but not all cases; on the other hand, gas can almostalways be substituted by other products. Perhaps most distinctively, in almost everycase, gas is ecologically attractive; it is also economically attractive to develop incountries with a negative balance of payments because it may displace importd oil orcoal and lead to profitable investment, thereby improving the balance of payments.

TABLE 2. Basic Chamcteitcs of Gas Relevant to Contracts

1. Gas has relatively low energy density but high volatility. Consequence: gas must beuansported by pipelines (LNG, compressed natural gas [CNGJ are exceptions).

2. Energy transportation costs for gas (by large pipeline or high-voltage cables; basis,West Europe) are as follows:

* aGas is more expensive than oil by a factor of five to ten.

* Electricity is more expensive than gas by factor of about ten.

3. Gas transportation has large economies of scale in the planning stage.

4. The share of transportation/distribution costs to the gas end user in overall supplycosts is large to very large.

5. Storage costs of natural gas are high and are economic only for large volumes.

6. Environmental and efficiency advantages can be realized in burning gas, comparedwith oil products and coal. Gas has particularly high superiority in efficiency inpower generation.

7. Nevertheless, gas can always be substituted by other fuels at costs that may be highbut not prohibitive.

5

6 Long-Tenm Gas Contracts_

2.2 In developing countries-several of which have considerable volumes of as-yetundeveloped and unexplored resources-it is worth considering what can be done tomake gas as attractive as oil for international investors, and to give the necessaryconfidence to the banks, in order to accelerate the development of proven gas reservesas well as exploration specifically for gas.

2.3 Recognition of the value and potential of gas in its own right is particularlyimportant becaus.. gas sometimes has been regarded as an annoying by-product of theproduction of oil, and some production-sharing or licensing contracts dealing with oil donot even address issues that may arise for associated gas.

The Oil Chain

2.4 For oil, a production-sharing agreement deals with the sharing of the income andthe risks from oil production. The next step, the marketing of oil, need not be addressedin a production-sharing agreement because oil is easily transportable and therefore canalways be marketed somewhere at the price set by the international oil market, paid inhard currency. The marketing of oil from a production-sharing agreement does notnormally involve quantity risks (outside production risks) but is only linked to risks ofprice movements. The chain between investment and the realization of the price of theproduct in a worldwide accepted currency is short (see Figure 1). Even if explorationfor oil is a risky business, most risks can be fairly well assessed by internationalinvestors. The international investor in the energy sector, be it for risk capital or forequity as well as for international financing, will compare chances and risks in aninternational context. These risks are determined mainly by the economics of oil and,to a lesser extent, coal projects, both being goods that are easy to trade.

2.5 After some treatment, oil can be immediately traded internationally via transportby tankers. Tankers are interchangeable and in principle are not technically or physicallylinked to a specific production site (although some restrictions may emerge in practicebecause of the size of the vessel, its loading techniques, and so on). Oil markets alsoare flexible enough technically so that sellers can switch customers easily. Hence,differences in trading and transportation costs are minor, compared with the value of theproduct to the customer. Furthermore, demand for oil is high and growing, and the priceelasticity (for falling prices) is high enough to ensure that there is no volume problem inoil marketing. The price risk remains, of course.

Main Fea"sres of Oil and Gas Chabw 7

Transport / Trading /Financing Exploration Production refining consumption

IX

I 00il product market

II $$ $ .4-s s

i -_____-_____ 0 0+u -joilO*Treat- -i0-*0-0-00*

~~~ ~ment

Pro-duc-tion

Risk _ Findcapital Dry

Oil--* Financing -* delivery 4 - Money flowing back

FIGURE 1. The Oil Chain

8 Long-Term Gas Contracts s'

The Gas Chain

2.6 Contrary to the marketing of oil, the marketing of gas requires investment in along-term marketing infrastructure consisting mainly of a trunkline system to link the gasdelivery points with the main markets, such as large-scale udlization facilities (e.g.,power and ferilizer plants). Also, the transmission and distribution grids that arerequired to market the gas in urban or industrial concentrations to a large number ofsmall or medium-size industral and commercial customers require large amounts oflong-term fixed capital. In contrast to oil, gas requires storage facilities to support gasdeliveries and to provide peak shaving that cannot be provided economically by thecustomer except through fuel-switching methods. In general, then, gas storage isprovided upstream of the point of consumption.

2.7 For gas, the marketing process is fundamentally different from oil. First, the gasproducer must worry about a much longer chain (see Figure 2), in which each successivelink is connected by physically fixed investments. Any of the links can become a bot-deneck (i.e., unless additional investment is made) that will detemine the capacity toprovide and to acquire gas. Gas also differs in that if any point in the chain experiencesan interruption, all links down the line will experience gas supply problems, and all linksupstream will experience cash problems. Furthermore, at the end of the marketingchain, gas must compete with substitute fuels. This pressure puts a cap on prices theconsumer will be prepared to pay for gas. Thus, even if bottlenecks in the supply chainmade gas scarce, the resulting price increases would be limited, and, with them, theincentives to alleviate the bottlenecks. Finally, the price and the income at the end ofthe gas chain must compete with international energy pnces. Income from gas sales isnot necessarily in hard currency, however, and this may leave the producer with asubstantial exchange risk.

Comparison between the Oil and Gas Chains

2.8 The main characteristics of the oil chain and the gas chain are summarized inTable 3. Compared with gas, oil is traded internationally, and payment is normally madein internationally accepted currency-that is, directly or indirecdy in U.S. dollars. Afterproduction and treatment, the oil is exchanged against an equivalent amount ofinternationally accepted currency. The oil producer is thus not unduly affected by whathappens downstream of the delivery point. General changes in the market will bereflected in the market price, and all producers will be affected in the same way on the

Main Features of Oil and Gas Cins 9

marketing side. If one customer is affected, the producer's loss is limited because heis not physically linked to the customer and is therefore free to find another customer.

TABLE 3. 0Oi Chain venus Gas Chain: Main Characedsdecs

Oil Chain

* Short chain* Loose chain* Interruptions in the chain relatively easy to compensate* Built-in market mechanisms due to esdy tradable good

Risk pauem:

Oil producer is free to sell oil where he likes; question is price;there is reserve risk, price risk, but no marketing risk.

Gas Chain

- Long chain

* Firm chain

* Physically fixed links from wellhead to burner tip; when gas is used to generateelectricity, links are fixed even further down to the electric plug

0 Interruptions: no gas downstream/no money upstream (compensation onlyby fuel switching or high-cost backup)

* Higher investment in the chain, higher bank involvement

* No automatically built-in market mechanism, but fixed capacities

Risk pattern:

Gas producer is bound to the customers down the pipeline and vice versaQuestion is how to make the gas risk similar to the oil risk.

10 Long-Term Gas Contracts

2.9 The oil producer also does not have to worry unduly about the downstreambottlenecks because the consequence of a bottleneck is more likely a price increase ratherthan a volume reduction. For gas, downstream bottlenecks are a major concern.

2.10 Figure 2 shows another fundamental difference between gas and oil: For oilprojects, the investor or banker does not have to worry about the investment on theconsumer's side; for gas, on the other hand, the financier may be involved on both sides.

Resulting lssues for a Policy to Promote Gas

2.11 In the production sphere, the economic advantages of oil are mainly linked to itshigh energy density at normal temperature and pressure, resulting in cheaper treatment,transport, and storage in comparison with gas. Some relief for gas-specific difficultieson the production side may be built into production-sharing agreements, mainly withregard to the transportation of the product on its way to the market, thereby helping topromote a transportation infrastructure for other gas projects as well.

2.12 The economics of oil and gas production facilities largely depend on theproductivity of the wells in terms of energy flow, independent of whether the product isgas or oil. An incentive structure may therefore be similar for oil and gas for marginalfinds, for example.

2.13 The delineation between the production sphere and the marketing sphere,however, is not so easy for gas. Where production is offshore, the offshoretransportation merely collects gas and should therefore be considered as part of theproduction sphere. Onshore, the intersection between the production sphere and themarketing sphere will depend more on the given facts of a specific country.

2.14 Specific incentives for gas production and exploration in the production-shadingagreement could consist primarily of easing the investment in gas transportation. Thiscould be done by some extra up-front production credit tr ext depreciation forinvestment linked to gas transport. For the investor, this would result in reducing thecost difference of bringing gas instead of oil to the market. It would also reduce the costdifference of transportation between different gas fields caused by their relative distancesfrom the market.

Main Featurs of Oil and Gas Chains 11

§~~~~~~~~rip, I WsidlyO Ustuan

ftwid -ERnUu Pdg to fapket Wnuil Unim" b-Mon fl.whi Dbbfk:o

FIGURE 2. The Gas W Ch

lftk~~~~~~~~~~~~~~~~~

- Dn0' f ~~Penvelee"un o n t _Fwken

FIlGURE 2. ne Goa8 Gain

12 Long-Tenm Gao Contracs

2.15 Given a certain price level for a competing fuel, a gas industry of a ceJtainsize-including production, marketing, and consumption-will prove economicallyviable. Assume that for such a size, the avoided expenditure for the replaced oil is, onaverage, equal to the costs of the gas chain-consisting of exploration, production,marketing, and consumption. In that case, the gas industry may be sustainable at thesame level by reinvesting the income, except for interest on debt and a reasonable rateof return on equity. The underlying assumption is that enough gas is already proved, ormay be proved, at the costs so far experienced.

2.16 If this is the case, it may be attractive for a country to choose gas instead of oil(or coal) for two reas-ns. First, the opportunity costs of domestic consumption of oil(or coal) are iOO percent payable in foreign currency. For gas, only the part of the gas-related investment that was financed by the country on the international finance marketis repayable in foreign currency (e.g., interest and the repayment of the loan in U.S.dollars). Second, the country is not exposed to the risk of rising oil prices. On the otherhand, it could benefit from falling oil prices. In addition, depending on the financingconditions, the country may be linked to the risks of changing interest rates.

2.17 If the average costs of the gas chain are below the expenditure for the energyreplaced, the extra revenue beyond cost coverage (including cost of capital) may betransferred outside the gas chain or may be reinvested in the growth of the gas chain.

2.18 The question of reinvesting the revenue into the gas industry is, however, relevantin any case. For gas chains in countries with a developing gas industry, the issue ofwell-balanced growth of aU links of the chain is of great importance, and they face a realchallenge in making the marketing of gas attractive by creating a gas chain with awell-balanced growth.

2.19 The physical difference between oil and gas makes the creation of incentives forgas much more difficult than for oil. It is possible, however, to compensate for thisdifference without dire-t intervention in the gas industry but nonetheless exposing the gaschain to the productive forces of market mechanisms. The main means to achieve thisare through some gas-specific incentives in production-sharing agreements (see item 3)and through a regulatory framework for the structure of the gas chain; adequate for thespecifics of the country concerned (item 4); and through stable commercial relationsbetween the links of the gas chain through long-term contracts negotiated between theparties concerned who are fully responsible for their contractual commitments (item 5).

3. PRODUCTION-SHARING AGREEMENTS

Present Situation

3.1 The domestic use of gas, if any, in most developing countries is restricted to alimited number of projects-mainly production of fertlizers and generation of power.So far, use of gas in general industry is relatively insignificant. Using gas for heatingpurposes is irrelevant for most developing countries, for climatic reasons. Notsurprisingly, until recently, no policies were designed to give specific incentives for theproduction-sharing contractors (PSCs) to develop gas on its own merits (except for someLNG export schemes) or to explore for gas, nor was there any active large-scaledevelopment of domestic gas markets.

3.2 Gas-specific issues are today addressed only in a limited way in theproduction-sharing agreements. The marketing of gas is mostly rued by the exclusiveright of a national oil company to buy and sell atl gas. In most cases, there is no clearlydefined organization equipped with the adequate manpower, funding, and authority tomanage the development of a domestic gas market or the buildup of a gas grid.

Requirements for a Domestic Gas Industry

3.3 Compared with oil, the marketing of gas requires a much higher specificinvestment in the transport and trading infrastructure. Unlike oil, gas requires apermanent link between the production site and the place of consumption. The marketingof gas is therefore largely dependent on geographical factors such as the location of thesources of gas and the main consumption areas relative to each other and to the gastransportation infrastructure, if it already exists.

3.4 Development of an indigenous gas market requires long-term supply contracts fhatwill be honored. To make the development of gas for the domestic market as attractiveto the PSCs as oil, an active domestic gas policy calls for incentives to remove thedisadvantages of gas relative to oil stemming from the specific higher investment fortransportation of gas and to aim at creating a reliable market outlet.

3.5 The main objectives of an indigenous gas market involve, first, giving incentivesto the PSCs to build a gas-producing and gas-collecting infrastructure from the point of

13

14 Long-Tenn Gas Contat

production to the delivery point; and, second, putting into place a gas-marketing strategy.This latter should include the following elements:

* An outline for the development of onshore gas transportation systems in placeswhere sufficient gas consumption potentdal exists

* Creation of a dedicated organization to deal with all questions of gas marketing(i.e., transport and trading) of the domestic gas

* Definition of a pricing policy.

3.6 Even if the direct revenue for the government from a gas project might be lowerthan from a comparable oil project, such an incentive scheme may be of interest for thefollowing reasons:

The gas development would most likely be an additional development thatotherwise might not have bappened; attacive oil finds will continue to bedeveloped.

The oil consumption replaced by gas will result in savings or additional sales ofcrude oil or oil products, thereby improving the balance of payments. As aresult, the economic benefits for the country are large.

* The economies of scale associated with preinvesting in larger-diameter pipelinesmay benefit the country.

3.7 Some of the objectives can be achieved by including specific rules in theproduction-sharing agreements. Others must be dealt with outside the production-sharingagreements in the marketing sphere and by appropriate contracts.

Gas ProWvsons in Poducdion-Shardng Agreements

3.8 So far, only a few gas-specific provisions have been incorporated intoproduction-sharing agreements, and only some of them favor active gas development orexploration for gas. The existing production-sharing agreements therefore do not seemto make gas development parficularly attractive vis-A-vis oil.

Producion-Sharing Agreements 15

Elements to be Addressed by a Policy Favorng Gas

3.9 Increased use of gas displaces other fuels, and the economic benefits to thecountry are often larger than the direct financial benefits. Thus, although many gasprojects benefit a country as a whole, they still need promotion to overcome financialconstraints when viewed from the standpoint of the investor. Overall, if a policyfavoring gas is to be developed, the following elements should be addressed in detail:

Reduction of the flaring of gas. Often, the flaring of gas is not restricted by anyban or limitation. Although a total ban on gas flaring might have an unacceptableimpact on oil production, reduction of flaring should be encouraged in view ofthe waste of this natural resource and in view of CQ emissions. A penalty forflaring gas, for example, could be an intermediate step toward a ban. Such apenalty should be proportional to the amount of energy flared after deduction ofthe quantity of gas flared for safety reasons. The penalty per energy unit shouldtake into account the potential value of the gas to the end user. A penalty is alsojustified in terms of the promotion of the gas infrastructure, which would makethe marketing of gas more attractive.

* Promotion of gas production and transportation infrastructure, if applicable.Relatively large economies of scale can be achieved in the planning phase of atransportatior. system. Although increasing the diameter of a pipeline usuallycauses a cost increase of less than the ratio of the diameters, the potential capacityis increased by more than the square of the ratio of the diameters. On the otherhand, measures taken after the construction of the pipeline (e.g., extracompression or looping of a pipeline) tend to increase overall costs by apercentage greater than that of the capacity added. Overdimensioning of apipeline is therefore an investment in the future use of the extra capacity socreated. This is advisable if there is additional demand for gas delivery capacityat the end of the pipeline and if there is a potential to satisfy it either byincreasing the production capacity of existing facilities or by tying in newproduction facilities.

* Facilitating gas transportation to shore. Contrary to oil, where-because ofoffshore loading-the distance to shore may not be decisive for the commercialviability of a project, this factor is decisive for gas projects, in view of the largeshare of gas transportation costs in the overall cost of a gas project. The burdenof transporting the gas to shore therefore should be alleviated in theproduction-sharing agreements. This might be done by an extra investment credit

16 Long-Tem Gas Contracs

for the investment into offshore gas transportation facilities. This would give anincentive for the development of offshore fields and at the same time reduce therelative cost disadvantages of gas fields that are more distant from shore. It wouldalso facilitate investment in larger-diameter pipelines. Providing additional gasdelivery capacity to the market would be accelerated. This scheme would alsogive incentives to explore for gas in more remote areas offshore.

e Indigenous marketing. Promotion of indigenous gas marketing can be encouragedby defining a clear organiational framework and developing a transportinfrastructure.

* Defining pricing, revenue, and subsiy policies. Pricing policy, distribution ofrevenue, and phasing out of subsidies for the end user and for the producer aUneed to be defined within the context of promoting gas production and use.

* Impact on envirounent and stfety issues. Assessment of environmental and safetyissues usually has a positive effect in promoting production of gas.

Poducion Facties (Offshore or Onshore)

3.10 Most of the finds near potential gas markets are smaU or medium in size.Although this must not necessarily entail high specific production costs, it will result inrelatively high specific exploration costs. In order to encourage exploration for smallergas finds, gas finds in more difficult formations, and in deep water, an incentive schemewill probably be required.

Promoting an Indigenous Gas Market

Delimitations between Distibution and Produdtlon Spheres

3.11 The distinction between the distribution and the production sphere is relevant todetermine which part of the system should be handled by the PSCs and which part shouldbe handled by the marketing organizations. The distinction could be made along the linesof whether a pipeline is collecting gas or distributing gas. By this definition, offshorepipelines should be in the sphere of the PSCs, along with pipelines collecting the gasfrom various wells of a field or within a production license. Because the design of

Production-Sharing Agreements 17

offshore pipelines is motivated by production parameters, they should also be part of theproduction-sharing agreement.

The Role of a Tmding and Thmnspoa Company

3.12 In a virgin market, the creation of a separate gas trading and transport companyresponsible for the development of the domestic gas market may be considered. Itspurpose would be to buy and sell gas and to transport, store, and blend the gas. Thecompany would acquire the ownership of the gas traded by it. The transport and tradecompany should be set up so that it would not obstruct participation by expatriatecompanies in the future.

3.13 In developing a gas market, the creation of entities for gas trading and transporta-tion that are separate and distinct from the national oil company is necessary toconcentrate gas interests in a single organizational unit focusing on gas-related issues.In view of the tasks involved (the investment in a gas grid will easily reach severalhundred mitlion U.S. dollars), the trade and transport company should have the authority,manpower, and expertise to handle atl questions involved in an efficient way and shouldbe the interlocutor for all potential suppliers, consumers, constructors, and banks.

Pdclng Polky

3.14 In the long run, the gas tading and transportation company should freelynegotiate the prices and conditions for buying and selling gas, without distortions at theconsumer end by state-imposed subsidies on the gas or distortions caused by subsidiesfor competing fuels.

3.15 If, for political reasons, certain production facilities using gas are to besubsidized, it is better to change to direct subsidies instead of subsidies via low gasprices, since the latter type of subsidies give the wrong signals and lead to inefficient useof gas.

3.16 The pricing system should allow the gas trading and transportation company tocreate its own financial means for a speedy expansion of the domestic gas tasportationand marketing system, as this will be the botdeneck for the development of gasmarketing over the first years.


3.17 On the purchasing side, prices should be structured to make the development ofexisting finds as well as the exploration for gas attractive to the PSCs. Systems that areprincipally based on the individual commercial situation of each find can basically bedescribed as cost-plus systems. By definition, they have no relation to the internationalprice of fuels competing with gas. Such systems inay be appropriate to develop alreadyproven gas finds, because they recover the capital already spent by a PSC on explorationand give a return on it. But if a PSC expends risk capital on exploration for natural gasas such, the reward should be comparable to the reward stemming from the alternativespending of risk capital in an international context, where the reward is linked tointernational energy prices, mainly oil prices. A reward (as defined by the price paid tothe PSC for the gas) that would allow the PSC merely to relaver the risk capital spentplus interest in the event of success would not offer true compensation for the risksundertaken by the PSCs because the upside potential of gas finds that can be producedat a cost below market value would be taken away from the PSC. Thus, from the pointof view of risk capital, the sales price of gas for the PSCs is best linked to theinternational price of energies that are competing for the capital.

3.18 From the point of view of optimizing the utilization of energy and infrastructureat the end user, a pricing system must be considered that reflects the international pricesof the fuels displaced by gas for the end user and the costs of serving the end user. Mostdeveloping countries are located in warmer climates, so gas consumption for heatingpurposes will be minor. The main area for gas consumption will be in the power sectorand in small and medium industry, replacing coal and, to some extent gasoil, in thepower plant sector and heavy and light petroleum-product fuels in the industrial sector.

3.19 A purchase price formula reflecting the competitive position of the gas in themarket should typically peg gas prices to a mixture of coal prices and pnces forpetroleum-product fuels. The appropriate shares of the fuels then depeAd on marketdevelopments and would be the subject of negotiations between the PSCs and the gastrading and transport company.

3.20 The purchase price at the delivery point should-ompared with the rephlcementvalue in the market-yield sufficient revenue for the gas trading and transport companyto fund the development of the domestic gas infrastructure. For example, this could beachieved by linking the part of the price reflecting the power market to the internationalprice for coal, taking into account the ratio of thermal efficiency of a coal-fired powerplant and a gas combined cycle. In that case, the investment saved by building acombined cycle instead of a coal-fired power plant might be shared between the powerplant operator as compensation for the restrictions of a take-or-pay contract and the

Production-Sharing Agreements 19

trading and transport company for the funding of the necessary gas infrastructure. Thesubstantial savings in investment for a combined cycle compared with a coal-fired powerplant may provide the funds for the construction of a large gas trunkline system withbuilt-in spare capacity to connect further industrial and commercial consumers.

3.21 In addition, some considerations should be raised based on prices of domestic fueland gasoil prices in line with international priing. Given the good marketability oflighter oil products, it seems wise to aim first at replacing lighter oil products by gas.Iniially, gas pricing for the industial market competing with heavy fuel oil might be setslightly below 100 percent of the energy equivalent of the international heavy fuel oilprice. In view of the high differential between the price of heavy fuel oil and the priceof gasoil, this pnrcing approach would leave enough revenue to the gas trade andtrsport company and to the end user to pay for the connection and conversion ofcustomers where gas is replacing gasoil, which usually requires a high investment intothe gas distribution infrAsucture. The incentives for the replacement of heavy fuel oilare compaively small, but still high enough to connect heavy fuel oil customers wherethey are near an existing gas infrastrut.

3.22 The mix of both elements in the price to a PSC should be made dependent on themarket situafion, especally on the power prqecs to be supplied with gas. The price paidshould also reflect the conditions under which the gas will be delivered-flexibility,stadiness of delivery profile, quality of gas, delivery point, and so on.

E *vbw,aeWl bWact and S#fety

3.23 The use of gas has advantages from a environmenala point of view because itscombustion is cleaner than that of the fuels it replaces and because the use of gasnormally also triggers a development towd higher efficiency. However, the laying ofpipflines has an impact on the environment-mostly tmporary-that has to be assessed.Purthrmore, suitable safety stndards must be observed for the laying and operting ofpipelines, especialy in inhabited regons. If a regulatory framework for such mattes hasnot yet been developed, it sod be possible to fal back on exsting rues in counieswith a developed domestic gas industy.

20 Long-Tenm Gas Contracts

4. REGULATION OF THE GAS CHAIN

Main Models

4.1 The following considerations concentrate on transportation as the critical elementin the gas chain because it represents the bulk of gas-specific investment. The balancebetween the links of the gas chain can be described by three main models.

Model 1

4.2 All links of the chain downstream of the delivery point are regulated by a stateauthority or state-regulated monopoly that fixes quantities and prices for all parts of thechain downstream of the delivery point (Figure 3a). The attractiveness of gas projectsfor international capital is then determined by the prices and quantities at the deliverypoint and the long-term perspective of the state authority on the oil and gas industry.

Model 2

4.3 The links in the transportation sector are regulatd and may include the capacityto adjust the movement of gas to market requirements (Figure 3b). Typica1ly, an extra-governmental authority gives guidelines for the management of the transportation sector,regulates access to existing pipeline capacity, and may determine nrles for theconstruction of new transportation capacity. The dynamics of the chain are then definedby the number and size of deals between the producing and consuming sides, whereasthe use and growth of the pipeline sector is mediated by the regulator. Producers maylook for customers of their own and will pay directly or indirectly for the cost oftransportation. Prices a producer can charge are limited by prices for competing fuels,but prices for the consumer may be lower because of gas-to-gas competition.

Model 3

4.4 The transportation companies act as trading companies, buying gas at the deliverypoint and selling it to the customer after providing transport and peak shaving (Figure3c). Regional and local companies may be interposed between the transportation companyand the final customer. No direct regulation of tariffs or of access to the pipeline isapplied, but rules of nondiscrimination are. Pipelines may be constructed by anyone,provided technical standards are respected. This provides a corrective if a trading^ompany refuses to transport gas for a deal wanted by producers and buyers. In thiscase, the balance of the system is largely in the hands of the trading companies.

21

22 Long-Term Ga Contracs

oldwwo/ TrnmsportaowP ctudo Distfbudelonolm

* -bb1 _ _ ~~.-Households

I ..4iIpndusuy

I~ELProducdon -_L consumers

p-*Ammoniaproducdofi -4*Aumona Consuwgm

Arm contoa by the Government (or va Govemment-owned companie)

D cdication ofQuandtie

o EVnsi of the gas sm, eacuding Ep on and frodu

* Pcp betwem Produc -TraupOrwrTransporter -End user of -diegasELProducer -EL ConsumerAmmonia Ka Pdue-Ammoni Consumer

Gas Connsc to be negoad bWe Proue and Tmusporte

FIGURE 3a. Model I: Government Contml of Gas Downstream of Pwducdion

Regulation of the Gas Chan 23

R* _/dw Transporatlon/ D/Piodu_dm Dbuftthm CoommptCm

-. _osehods

.- 1JrgeIupIdustIyI- -1*

'I*Powa lants

Aen reat by the regulsor ndepdet of gwnmnt)

* Acces stosg dl) ftpo apacty

e *q of tam 1br ut aou& 80^CC

o lby seing of nles for i ease of pien capac

GCs Contct to be nWtte*

* Tr=wo"Wp d Conocs Of o giv by fte rator) bewnProducerrsspo r C

* Cont beteen P am and Consmm

FIGURE 3b. Model 2: TmnsporWahon of Gas as a Regued Serice

24 Long-Tenn Gao ContraCuS

Elmdorato/ Trading DsributonlPmduict r Onc. Tnsporg) Cosmpton

I I__ __ _ i l

q ~~~~~~~~~~~~~I

L I PoWrPlant

- - bI a

=.~* -____Rega byl | ~~~~~~~~~~Tarifi for households

_ _ __ - - _ and busnse rgltod by(Eforement of nndisrimination) municipl authorkii

* Tariffi for households

* Nondiscrimination

Gas Contacts to be negodate: Betwe Pmrde and TinerBetwenTr and Cnumme

FIGURE 3c. Model 3: Transporter Acts as Trader; Demamtadon Possible

Reguktion of the Gas Chain 25

4.5 The comparative selling price of gas and competing energies defines the incentivefor the consumer to opt for gas rather than for the competing energy. The price paid tothe producer detennines the incentive to invest in additional production capacity andexploration. The margin between the two prices determines the incentives and funds forthe expansion of the pipeline system and storage. Ln Model 1, only the price betweenthe producer and the government authority is subject to negotiation. In Model 2, theinterface between the producer and the consumer is up for negotiation. In Model 3,there are two interfaces for negotiation. Thus, each of the three models requireslong-term contracts at some interface that reflect the nature of the fixed investment.

Inplications for the Contacts to be Concluded

4.6 Model 1 would at least require contracts between the state or the state-directedmonopoly gas company and each producer. Such contracts, provided they contain a pricelinked to oil and a minimum pay guarantee, may result in a similar risk patten as for thesale of oil. However, the total setup may not be very attractive to the interationalinvestor, because the sale of gas would depend on case-by-case decisions at the discretionof the government rather than on the current state of market development. Even if thereis a clearly defined market-related pricing mechanism for new gas contracts, the questionof how many new quantities will be contracted is not market-driven and thereforedifficult to assess by the oil companies. In addition, distortions in the rest of the chainare likely if pricing and the expansion of the industry are not driven by market forces.

4.7 In Model 2, the contracts would be between the producer and the consumer wherethe transport in between is supposed to be available at the cost of service. The extent towhich transportation is available and the basis of cost of service might be negodatedbetween the producer or the consumer on one side and the pipeline operator on the other.in the last resort it would be determined by a regulator, either case by case or on thebasis of generally applicable published rules. Transportafion capacity would then needto increase in line with the increase in transportation requirements, as they result fromadditional agreements between the producers and the end users. Care must be taken toensure that investment in additional capacity is made in a timely fashion and that theeconomies of scale in the planning phase of a tansportaton system are being used (andthat the preinvestment is being paid for).

4.8 Typically, a transportadon contact would define a certain transportation capacitythat must be made available over time. At least an inlet capacity and an outlet capacity

26 Long-Tenn Gas Contracts

at two defined points must be defined. That capacity must also be paid for whether usedor not. Furthermore, the exceptons to that obligation as well as the consequences of notmaking transportation available must be clarified. Then, the contractual relationshipbetween the producers and the consumers defines the dynamics of the gas industry.Whenever there is underutilized capacity in the gas system, some incentive should evolveto price that capacity down to the market-clearing price and vice versa for unsatisfied gasdemand. It should be noted that high and "lumpy" investment in the gas industry as wellas the long lead times for capacity increases may result in some imperfections when thetheory is put into practice.

4.9 Compared with Model 3, Model 2 embodies a broader range of contracts andmore particularly a tendency toward a shorter term of the contract but also a tendencytoward a lesser degree of commitment.

4. 10 Model 3 would require long-term stable contracts where a change of partnerwould only occur if there are physically two pipelines that may supply gas to the samecustomer. The main competitive pressure in this model comes from the competing fueland the fact that no one can be forced to use gas instead of other fuels.

4.11 None of the three cases, as such, would solve the question of how much revenueis reinvested in the gas industry. This goal is best served if the gas industry has positiveprospects so that it remains attractive for investors.

5. A BASIS FOR LONG-TERM GAS CONTRACTS, PART I

5.1 When gas from newly developed sources is brought to a market, a largeinvestment is generally involved on both sides. Typically, the investment is fixed for along term to create an enduring connection between the production source and the enduser. Further encouraging long-term commitments are the facts that, compared with oil,gas is extremely expensive to store and that gas markets are driven by capacity ratherthan by quantities.

5.2 The specific investment on both sides for delivery and offtake of the gas may beof the same order of magnitude upstream and downstream of the delivery point. Forexample, the investment to produce and land gas even from deep waters can be of thesamne dimension as the specific investment to consume the same capacity in a newly builtcombined cycle. The same goes for investment in large gas grids.

5.3 Unless the regulatory framework dictates otherwise, several large producers andone or a few large potential buyers typically are facing each other at the delivery pointor points. An exception may be the case of a developed gas market with large sparecapacity in the connecting grid between the wellheads and the burner tips of theconsumers. If the system is designed so that each producer is linked to a largerconsuming capacity than his production capacity and, conversely, each consumer hasaccess to more producing capacity than his own consumption capacity, this may createthe technical preconditions for gas-to-gas competition. As a result, both sellers andconsumers may reasonably rely on short-term or even spot contracts for their supply ofgas. In that case, the question arises as to whether investment in permanent sparecapacity of the system is realistically feasible over many years or whether it is not awaste of capital. A customer buying gas on a spot basis should be in a position to switchto altenative fuels without risking the commerial viability of its business. Vice versa,a producer should be sure that his investment in production capacity is still viable if hehas to compete with the low-value end of fte oil barrel or with other gas at lower prices,also takdng into account the investment in the grid in between. These conditions mayarise if gas is a by-product of oil production that must be disposed of.

27


5.4 In the case of a customer's captive investment, such as investment in a combinedcycle, the buyer might ruin the economics of his business if he has to switch to liquefiedpetroleum gas (LPG) or gasoil, for example, as a replacement for gas.5 The sameapplies to utilities that would have no alternative fuels.' These buyers will be moreinterested in long-term gas contracts that ensure the necessary pay-off time of theirinvestment.

5.5 Long-term contracts presuppose that contract obligations will be fulfilled. Thisalso means that legal instruments are available in the country to enforce such contracts.The parties linked to a deal are not only the buyer and the seller of the gas but also otherplayers in the background, such as the banks lending money, often for both sides of adeal, and maybe even further down the gas chain. The state government participates viataxes and other levies on the production and sale of the gas as well as in the profits ofthe companies involved. The state is also involved in tenms of its policy for energy andenvironment and by the effects of a gas deal on the balance of payments. The suppliersof equipment may also have some interest in the deal, as will the buyer's largecustomers. The essential interests of these parties under such a deal must also be takeninto account. Otherwise, the deal wil not be concluded, or it will run into problemslater on.

5.6 The main interest of the banks simply seems to be a secured cash flow on theirlending so that they can recover the principal plus interest. Once the lending has beencompletei, the main interest in the deal will probably be constant. The banks should beinterested in a well-balanced agreement that will ensure the commercial viability of theproject for both sides, at least undl their loans are paid back. This means that the projectmust be robust enough to stand up to the more likely changes in economic circumstances.

5.7 Overall, banks seem to take a rather neutral stance toward both parties, even ifa single bank may be biased toward its own client. In any case, the banks' views seemconstant over time. Banks may exert influence on the way the contract is concluded, but

5. The term captive innwnnent is used in this paper in the sense that ance a customer has convertedto using gas it is not possible fer that utme to switch to othr fisels without risking the profitability ofthe business.

6. Utlty is used in the semse of a local gas distibution cowmpny.

A Bask for Long-Tem Gas Contracts, Part 1 29

only rarely will they exert influence on its implementation. The role of the banks maybe reflected explicitly in a contract as a precondidon of satisfactory financing.

5.8 A necessary precondition for the long-term stability of a project is that it iscompetitive with other projects, from the investor's point of view, and that the endproduct is also competitive against possible alternative products or services.Furthermore, the deal should provide enough incentives for efficient operation on bothsides.

5.9 The state or government is involved to a larger extent in aU stages of the chainand in a more permanent way:

e In fiscal terms, the state may be involved not only through taxes and levies on thegas or on the profit of the companies involved but also through taxes and leviesand subsidies on competing fuels.

* In terms of environmental and energy policy, the state may issue technical andeconomical regulations.

i In terms of ownership, the state may be an owner or partial owner of some of theentities involved in the gas chain.

* The state may act as a guarantor of the loan.

* The state's involvement may be affected by the consequences for the balance ofpayments and via currency regulations.

* The state's powers to define and grant the legal frame of contracts are crucial.

5.10 Although the definition and implementation of a policy by the state affecting thegas industry is legitimate, it may not remain constant over time. Nonetheless, the state'sinfluence should at least be predictable, and once an investment decision has been made,the project's commercial viability should not be jeopardized. Partners in a long-tem gascontract should provide for some mechanism to cope with changes in government policy,such as changing tax regimes, and they should agree in advance on how to share theburden.


5.11 The involvement of suppliers of technical equipment may have some importancewith regard to the capacities agreed upon in the contract; their involvement will bereduced drastically after the commissioning of the system.

5.12 The buyer's large customers may depend on the contract and its risk sharing fortheir own investment for the lifetime of the contract. The interests of the buyer of thegas may be heavily influenced by its large customers so that the buyer may have to passon certain risks linked to large customers to the producers. Conversely, the buyer mayalso try to pass on deliverability risks from the producer to the large customers.

5.13 Although none of them is a party to the deal itself, the parties listed above mayhave a decisive influence on the conclusion and the shaping of the deal that may bereflected by the following contract provisions:

* 'Conditions precedent," by which the contract's coming into force may dependon financing, agreement of the state, a frther selling agreement, and so on.

* A provision that influences the start of full delivery obligations under the contract(e.g., by a commissioning test).

* A provision that may change or influence the balance of the commitments underthe contract during the lifetime of the contract-mainly exceptions to thecommitments and other force majeure clauses such as effects of state influenceand legislation, tax provisions, and passing on of customer's force majeure.

5.14 With regard to the real contract partners, Table 4 lists the main aspects to becovered by a contract, which will be discussed further later in this paper. Table 5 liststhe negotiating principles to be applied to a gas sales agreement.

Some Basic Considerations

5.15 The main commitments on both sides initially involve providing the necessaryfacilities in the chain to make the gas flow. Once facility commitments have been set up,the balance is indicated by Figure 4. In general, it is clearer to define the balance bycommitments on either side than by the rights of either side.

A Basis for Long-Term Gas Contracts, Part 1 31

TABLE 4. Main Groups of Elements in a Gas Contract

The partners in the contract ("the players")

The rules for handling the contract ("the referee")

The commitments of the partners outside the actual deal(are there other "games" involving the same players?)

The commercial aspects of the deal(what are the rules of the game?)

The commitments of each side to invest in making gas flow

The balance between partners when gas is flowing:

Gas flowMoney flowInformation flow.

The technicalities

32 Long-Tenn Gas CoNracts

TABLE S. Some Negotiating PMnciples of a Gas Sales Agreement

* Agreement should be balanced.

Parties of comparable power; at least, both sides should beable to say 'no' before signing the contract.

* Long-term character of the agreement should reflect the long-termcharacter of the investment on both sides.

- "Pacta sunt servanda."

* Keeping the balance between the parties over a long tme will requireability to make adjustments.

3 It is better to change the contract to keep the agreement than to stick tothe contract and lose the agreement.

o sBalance of power should be maintained during contract life:

Damages of comparable size if agreement not fufiUled.Alternative action possible on both sides.

A BasisforLong-Term Gas Contracts, Part! 33

Long-Tem Gas ContractsBalnce ofCo i

I

s-wt Buyce' CommC)enG"Avwwmw Long-Tam Minimum Pay

Exondons E :

e*= hfa-em F* Maim

FIGURE 4. Balzce of COmmDM#WIS in Long-Tenm Gas CoatrAs

34 Long-Term Gas Contrats

5.16 The buyer is interested in access to a given capacity to deliver the gas. The selleris interested in a given guaranteed flow-back of money. Sometimes the seller may alsobe interested in physical delivery of the gas, as with associated gas when flaring is notallowed and no other ways of gas disposal exist.

5.17 Looking at an earlier point of decision of the seller-that is, at the point wherethe seller has to decide whether to invest or not in exploration for gas in a country-theseller may want a reward scheme similar to oil, with a guaranteed sales volume and aprice linked to some international oil price.

5.18 The buyer's main interest is the availability of sufficient gas to serve thecustomers and thereby make his investment economically viable. The resultingobligatons for both sides are the seller's obligation to make available a given quantityof gas and the buyer's obligation to take and pay for it or, alternatively, not to take butnevertheless pay for a given minimum quantity of gas.

5.19 In a long-term contract, all kinds of provisions have to be built in that enable theparties to adapt to the changes in their commercial environment within the frameworkof the contract. This will mainly include a certain flexibility to adapt to changes inproduction, to new information on reservoir status or performance, or to developmentsin the market.

5.20 In the long term, it is also likely that sporadic or long-term distubances willoccur, because of force majeure or cases of negligence. If a party does not have analternative outlet for the gas, or if no substitute fuel is available, the sharing of risksfrom such diurbances must be addressed in the contract. This is done by liberating theother party from its obligations, by obliging the party in charge of the failing part toundertake measures to stop the effects of such disturbances, or by setfing or clarifyingpoible compensation, penalties, or indemnities.

5.21 Finally, the partners must have an instrument to persuade them to abide by theagreement they have signed. Such instruments, in the final analysis, will usually entaila loss of revenue for those who do not abide. Very often during negotations, the priceis the element that achieves a final balance of commitments. Therefore, it is advisableto leave discussions of price levels until the end of the negotiations and to try to coverall imbalances of the various provisions negotated so far in the pricing provisionsthemselves, especially in the price level. However, some elements of a deal, such as


those that put the very existence of a company at risk (such as insufficient reserves tomake the investment profitable) can hardly be compensated by pricing.

5.22 The following sections discuss the elements of an agreement. One way to findan approach that is as general as possible and thereby independent of the features of aspecific country would be to compare the negotiation of a gas deal with the situation ofseveral players and several possible games.

5.23 The points raised in Table 4 above will be addressed in detail:

1. Who are the players (the partners of the contract)?

2. What are the rules for handling the contract?

3. What common interest might the partners have offside the actual deal?

4. What are the commercial aspects of the deal?

Clarifying the commitments on both sides to invest to make the gas flow

Defining the balance between the partners when the gas is flowing interms of the gas flow itself, the money flow, and the information flow.

* Addressing the technicalities of each aspect.

Knowing the Partners of the Deal

5.24 When discussing and possibly entering a deal, it is of greatest importance to knowexactly who the partners are. Unless this issue is absolutely clear, the partner may turnout to have inadequate capacity or possibly even be without the mandate to conclude thedeal in question.

5.25 Table 6 gives the main objectives to be observed when identifying the partner inthe deal. Normally, these elements will be refleebed in the preamble and the assignmentclause.


5.26 Each party in the deal has an interest to know the identity of its contract partnerand to make sure that the partner will permanently be able and willing during thecontract life to fulfill its obligations. The main capacities for a contract partner to fulfillhis obligations are technical capacity, entitlement to the gas/legal access to all instrumentsto fulfill the contract, financial capability, adequate manpower, adequate managementskills/expertise, and ability to act. A specific problem in developing countries may bethe fear that the contract partner will be dissolved by the government. In this case, it maybe helpful if the government gives a guarantee to take over the commitments of thespecific company.

5.27 Because of the long lifetime of the contract, a change of partners is likely andmust therefore be covered by some provision in the contract. Normally, there is anassignment clause giving some protection against a change of partner, maldng theassignment of a given part of the deal subject to the agreement of the other party.

5.28 Apart from the criteria listed above, which are linked to some objective criteriato be able to make the deal work, there may also be some more subjective elements thatshould be fulfilled before a partner agrees to an assignment. For example, there may bereasons for a partner not to agree to an assignment to a company with which he isaready in dispute.

5.29 The process of changing the consteUllation of contract partners must be clear at anydme so that all parties involved are aware of their individual obligations.

A Basis for Long-Tenn Gas Contracts, Part 1 37

TABLE 6. Who Are the Paftners of the Deal?

* Mandate of the persons representing the companies

* Capability of the partners to carry out the deal

Financial soundness to fulfill the minimum pay ("parent's guarantee," i.e.,in most cases guarantee by the state)

Sound chain of titles to the gas

* Number of partners on each side; if more than one partner:

Rules of interaction (e.g., pro rata liability/equal treatment)

Rules of interaction lnown/clear/binding?

-Who is representing whom? (mandate of the operator?)

* Change of partner / new partners; protection against change of partner containedin an Assignment Clause

Assignee must have the capability to fulfill the contract. Who isresponsible for which obligation must be documented at all times to theother (= constant) party.

Assignment of a share in all rights and obligations in the contract or ofspecific rights

Example: Assignment of part of the income to a bank as security.


Handling the Contract

5.30 Table 7 lists the main elements to observe in the handling of a contract. The dealmay extend to more than 20 years, and after several years, the persons who participatedin the negotiations may have retired, may be in other positions in the company, or mayhave moved to another company. Even if they remain in place, their memory may havefaded. Hence, the written agreement (contract) is indispensable. The same applies tochanges to the contract.

5.31 Ensuring that conditions precedent have been fulfilled is an essential aspect ofcontractual relations. One aspect of the failure of a contract in its starting phase is thequestion of whether it is valid or not. The stumbling block is normally whether allconditions have been fulfilled. Conditions precedent are normally required because thelimited mandate of the management of a company means that long-lastirg gas dealsnormally also require the approval by the supervisory body of a company. In addition,on the seller's side, a long-term gas contract involves the commitment for heavyinvestment and, furthermore, the commitment to maintain production over a long period.Moreover, on the buyer's side, a contract involves the commitment for a largeinvestment in offtake capacity such as a pipeline grid, which often comprises the samevolume as the investment in the production capacity; a second commitment on the partof the buyer involves a long-term minimum-pay commitment that may be even morecomprehensive. This is normally not within the mandate of the management of acompany.

5.32 Conditions precedent also take care of the interest of parties that are onlyindirectly involved in the deal, such as the state and the banks. For them, a conditionalcontract may be the basis for a decision whether to support the deal by lending money.Some legal requirements may have to be fulfilled before the gas begins to flow. Theapplication for permissions of all sorts, for example, may presuppose that there is alreadya clearly defined project. Normally, all parties involved are required to make best effortsto fulfill the conditions precedent.

A Basis for Long-Tsnm Gas Contracs, Part 1 39

TABLE 7. How to Handle the Contract

Start Of contrad.

Coming into force upon fulfillment of certain conditions, e.g. approvalsby supervisory body, by government authorities, and by management (?!)

- Achievement of satisfactory transport or other agreements.

Time limit to fulfill the conditions, so fhat the other party is not boundindefinitely by a pending contract (conditions predent).

Changing the rules for the contract or part of it (e.g., bouleversmentdauses/review clauses/hardship clauses). This is done fonmally-only inwriting.

* Interpretation of the rules (of the contract). Points to be clarified:

DefinitionsL anguageApplicable law.

* Solution of disputes (e.g., by arbitration, by expert procedure; solution bytermination of the contract Is problematic).

* Elnd of contract.

Termination after xy years or upon depletion of reservoir (i.e., if it is nolonger economic to produce gas (economic assessment).

Special termination possibilities; examples:

Interference of government in main elements of the contractSevere case of force majeure on either sideFrustration, totally changed circumstances.

40 Long-Tenn Gas Comracs

5.33 During the life of a contract, the investment made on both sides would be idle ifone side did not fulfill its obligations. It is therefore important to include some rules toensure that the contract will continue to work for both sides. This should apply even ifboth sides disagree or are not able to find a solution to a dispute. Interpretation of thecontract must be clear. Except for the question of language and the written form, themain and most predominant element is the question of applicable law. The same contractmay have a substantialy different meaning depending on which law is applicable.

5.34 Laws that relate to English law tend to interpret a contract text in a very narrowsense and wiU tend to abide very strictly to the wording of the contract. Laws that aremore influenced by Continental European legislative understanding may take a morecommon sense approach and may look more at what might have reasonably been theintention of the parties.

5.35 The history of cases of disputes resulting from contracts of a similar nature thatare reflected in the legal system of a country may also play a role when choosingapplicable law. As disputes of gas contract normally involve large amounts of moneyon both sides, it is better for both disputing parties to have a realistic feeling for therange of the possible outcome of a legal dispute. Legal systems that have only a shorthistory or that have not yet handled major legal disputes will therefore not be adequate.

5.36 Regarding the likelihood that circumstances may change over the long lifetime ofa contract, conting parties should also make some provisions to adapt the contract toa change in circumstances to avoid frustration of a party that is substanilly sufferingfrom changed circumstances.

5.37 For all these examples there must be some instruments to setde a dispute. Thismay be done, for example, by court. A case in court, however, provokes publicity thatmay be to the detriment of everybody concerned, and there is some doubt as to whetherthe courts are competent to judge on the very specific questions of the gas business. Itis therefore common practice to solve disputes by expert or arbitration procedures.

5.38 Expert procedures are adequate if the disputed case has an objective basis, suchas the question of the size of recoverable reserves, even if this is linked to uncertaintiesthat may be judged in a biased way because of the specific interests of the partiesinvolved. However, the decision of an expert need not reconcile the diverging interestsof the parties but rather aims at rendering a judgment on a question that-given perfectknowledge-ould be solved in an objective way.

A Basks for Long-Tenm Gas Contracts, Pan 1 41

5.39 Cases dealing with deviating interests of both parties should not be referred toexperts but rather to arbitrators. A typical example is the question of the price level,which always affects the balance between the parties. Single elements of a priceformula, however, such as the replacement of some indices by others, could neverthelessbe dealt with by an expert.

5.40 The expiration of a contract is usually explicitly defined in the contract itself. Forcontracts linked to a specific field, agreeing on a fixed duration might, however, risk thatthe reservoir will be exploited in a suboptimal way from the producer's point of view,leaving quantities of gas underground at the end of the contract life requiring productionfrom the reservoir is produced at a depletion rate that, from a cash-flow or present-valuepoint of view, is less than opdmal.

5.41 There is a typical conflict of interests regarding the term of a contract. Subjectto restrictions of the reservoir, the producer will tend toward high production rates inorder to make maximum use of economies of scale and to maximize the net present value(NPV), thus shortening the lifetime of the contract. The buyer, however, will beinterested in a longer lifetime in order to keep his business going as well as to be ableto serve customers who have a high payback time. The buyer may, however, beintrested in a high production capacity to adapt to changes in the market or in hispurchasing portfolio. Depending on the scale of the risks and on the performance of thereservoir, the buyer will prefer to set the depletion rate as low as possible. If the periodof the contract is not fixed, it is usualy interpreted in the seller's favor-that is,depending on the depletion of the reservoir.

Ascertalning Common Interests Outside the Deal

5.42 It may be of great interest to consider the long-term relatons between twocompanies outside the deal in question. Table 8 lists various elements that may be thesubject of such considerations.

5.43 The deal in question wiU normaUy be restricted by either actual marketing orproduction restrictions. It might be of interest to the partners of a deal to agree on rulesfor what should happen if such restrictions do not apply any longer, either because themarket has developed beyond the volumes agreed or because additional gas becomesavailable. Tlis may result in new rights or obligations on either side.

42 Long-Term Gao Contracts

5.44 Furthermore, the deal in question may be just one element in a longer chain ofdeals upstream and downstream. Other issues could be covered to ease theimplementation of a deal, such as granting the necessary rights of way or training ofstaff. Finally, elements could be included outside the gas business to achieve an overallcommercial balance.

TABLE 8. Possible Relations Outside the Deal

* Provisions dealing with market increases beyond the scope of the deal

* Provisions dealing with availability of additional reserves

- Activities upstream or downstream of the delivery point, e.g. creating jointcompanies for transport, treatment, marketing, storage, handling of by-products(which may result in heavy investment commitments)

* Elements to ease the performance of the deal (examples: rights of way, stafftraining, common R&D)

* Elements to find an overall balance, e.g., use of material and equipment

6. A BASIS FOR LANG-TERM GAS CONTRACTS, PART II

Commercial versus Technical Elemento of the Deal

6.1 The main elements that define the balance of a deal may be divided into twotypes: the commercial or material elements, which include matters of delivery points,required investments, quality, quantity, and pnrcing; and the technical or practicalelements, which relate to handling of the gas stream, metering, testing, and so on. A fullrundown is provided in Table 9, where the left-hand column shows the matial orcommercil points that should be covered by the contract itself, and the nght-handcolumn shows the more technical or practical considerons.

6.2 It may be a good idea to deal with many of the technical or practical elements ofa deal in a sepae, supplementay document or documents, which can be changed moreeasily than a contract. These supplementary documents may reflect new technicaldeveiopments, new means of communication, or more advanced meteing devices. Thestaff involved in dealing with such matters usually consists of experts in the fieldsconcerned; changes to the documents generally do not involve senior management.Experience indicates that amendments to such supplementary agreements are often seenas reasonable and necessry and that they generally do not change the commercialbalance of the overall contract.

Commercial Elments of the Deal

Delimitatio of Spherws

6.3 As a basic commercial starting point, sellers and buyers of gas should come toa general understanding on the division of work between them. Normally, the deliverypoint or points-which must be defined exactly-would be the intersection of spheres.Upstream of the delivery ooint is the sphere of responility of the producer/seller,whereas downstream of the delivery point is the business and the reponsibility of thebuyer. It must be rememberd, however, that sometimes a buyer has activities upstreamand a seller has activities downstream. Cross-participation cannot be excluded, either.in any case, a specific deal should have a clear-cut division of the sphes of interest.

43

44 Long-Tenm Gas Contraas

TABLE 9. Commerdal versw Technicl Elements of the Deal

Commercialhnaterlal Techicallpractical

Delineation of spheresDefine delivery point(s) Handling of gas streams

Investment to realize the projectDefine investment obligation Coordination ofof both sides investment of both sides

QuantityCommitments Metering, operatingSharing of risks rules information flowExceptions (force majeure)Penalty/Incentive schemes

QualitySpecification Specification definition

Consequences, if offspec Applicable test iformation onquality

PriceDetermination of price Billing and payment rulesformula

Due date of paymentMinimum pay price,default rebatesTaxesCurrencyReview of the price formula

InformationScope of information to be Means of communicationgiven to the other side

A Basifbor Long-Teim Gag Contracts, Paut n 45

6.4 Practicalities are also important. If there is one seller and one buyer at onedelivery point, agreement must be reached on the technical details of how the gas istakn-in other words, whether it is pushed by the seller's compressor into the buyer'spipeline or whether it is drawn by the buyer's compressor from the seller's pipeline.Normally, the gas will be metered at that point.

6.5 If the same seller and buyer arrange for several delivery points, the limits foreach point must be clarified, along with the rules for switching obligations from onepoint to another. If several sellers or buyers are involved at one delivery point, theymust agree on rules for delivery of gas in a commingled stream, because only the totalstream will be metered. The parties must then clarify how the gas will be allocated tothe various contracts and particularly how metering and other differences are accountedfor.

Ohligation to Invest in a Project

6.6 During the construction phase (i.e., before the gas stats to flow), the easy caseis if only one side has a heavy investment with a long lead time. That means that theother side either has idle capacity or needs only marginal investment to increase or installthe necessary capacity witiin a short lead time. In the case of a large onshore field withpure methane and a low reservoir depth, for example, only a relatively small investmentfor treatment of the gas is necessary. Additional investment would be required only fordrilling additional wells, which would take only a shceT time. The schedule until the startof deliveries would then rather be determined by the partner having the large investment.

6.7 If heavy investment with long lead times on both sides is involved, poorcoordination will result in idle investment. Although one side usually does not suffer theconsequences of the other's cost overruns, coordination is nonetheless needed with regardto the time schedule. Here, the agreement must state clearly the obligation of either sideto overcome difficulties such as construction delays, difficulties in obtaining thenecessary permits, and loss of production equipment. The parties could be obliged toprovide substitute or backup capacity through extra investment. Alternatively, theagreement may call for automatic penalties or indemnification for the delay of the startof deliveries. Penalties would act as an incentive to avoid the problems, or they maysimply be lump-sum compensation. If delays are substantial, the other party may beallowed to end its commitment so that it may apply its investment to other uses.

46 Long-Tern Gas Contracs

6.8 During the delivery phase, too, the contract should clarify the extent to which aparty is obliged to invest, reinstall, or maintain delivery or offtake capacity. If capacityhas been lost, this obligation may depend on whether it was lost through force majeureor negligence. In either case, the other side should have the option of reducing itsobligation to the same extent that the defaulting party is unable to fiMll its obligations.Special provisions under the force majeure or liability clauses cover these issues.

6.9 Again, some practicalities are worth noting. During the construction phase, eachparty will be obliged to inform the other on the progress of the work, usually by writtenreports, possibly by meetings to discuss the progress, or even by common siteinspections. During the delivery phase as well, each party is obliged by a generalinformation clause. Buyers who depend on the performance of the reservoir will ask forregular meetings to discuss reservoir performance and technical equipment as well asresevoir management programs. The largest part of infurmation usually is provided bythe seller, because the buyer's long-term obligation is largely to make the minimumpayments agreed under the contract.

u" and Qalty

6.10 For the period when both parties have completed the infrastrucure of the projectand have done the necessary marketing, triggering additional investment also in theinfrastr re further down the gas chain, the rles for the physical use of that investmentare defined by the provisions on quantity and quality laid down in the contract.Long-term rules are needed because of the long-term investment with a fixed location andcapacity. Because the partes have only a few ways of reacting to unforseen events andchanges, the siaring of the main riss must be defined in advance.

6.11 The seller's main commitments under the quantity provisions are to "makeavailable" a defined amount of gas of a certin quality over a given period. The buyer'scommitment is to take at least a minimum share of the gas made available and/or to payfor it. Tshis obligation might be reduced to an obligation to pay for a certain amount ofthe gas made available, but without the obligation to take it. Because gas is linked tocapacities up and down the gas chain, a transaction has operational implications on bothsides that must be anticipated. On the one hand, botdenecks downstream may preventactual acquisition of the gas by the buyer. On the other, for example, a seller may beobliged to require physical offtake of the gas, as in the production of assocated gas thatcannot be disposed of otherwise (e.g., when flaring is prohibited) or when the technicalflow characteristics of the production and treatment facilities require a minimum offtake.

A Basis for Long-Terim Gas Contracts, Par 47

6.12 Failure to fulfill an obligation raises the question of compensation. Becauselengthy and time-consuming disputes may result from discussing damages, a lump-sumsolution is an acceptable alternative. This would involve a minimum payment for thebuyer and default rebate for the seller if commitments are not fulfilled. In both cases,the sum would depend on the extent to which contractual obligations were not fulfilled.

6.13 A lump-sum system instead of compensation may give very clear penaltiesenforcing appropriate behavior on the part of the parties. The main effect of suchpenalties will often be that the problems for which the penalties are foreseen are avoided.

6.1J4 Some cases of nonfulfillment may be excused because of force majeure (i.e., theycould not be avoided by a reasonable and prudent operator). Force majeure cases dononnally not cover reservoir risks and marketing risks. Both of these can be foreseenand depend largely on management decisions. They form the core of the business of theseller or the buyer and are normally covered by specific provisions outside the forcemajeure clause.

6.15 Prowsions for Dealing with QantOy and Qualty Issues in the Contract. Therelation between the main business risks on either side defines the basic balance in thecontract and is therefore crucial for almost all other provisions in the deal. Theseprovisions include the term of the contract, delivery profile, flexibility of the contract,information on the reservoir, and consequences of nonfulfillment. Indirectly, thatrelation has also a bearing on the provisions on prices (either because the product is onlysuited to specific market segments because of the delivery paten and the risks involvedor because extra costs are involved in marketing the gas). The typical elements of thecontracts are explained below; for an overview, see Table 10.

6.16 Depledon- and Dedication-type Contracts. In both depletion- and dedication-typecontracts, the buyer is linked to a long-term performance of the reservoir. Under adepletion-type contract, the buyer may have bought only a portion of the gas recoverablefrom the reservoir and would therefore share the risks of the reservoir with some otherbuyer. Under a dedication-type contract, a single buyer has bought the whole gasrecoverable from the reservoir. Normally, the buyer is then also linked to theperformance of the reservoir, and the main features of a depletion-type conrat in turnwill apply. In most long-term contracts of either type, the flexibility of annual offtakeis limited to somewhere between 10 percent and 30 percent, and thereby the length ofthe production profile is quite independent of the buyer's offtake.

48 Long-Tenn Gas Contra . _

6.17 The central element in a depletion-type contract is the definition of the profile ofannual quantities, which in turn is driven by considerations of reservoir management.This definition includes the original profile as well as changes to it over time stemmingfrom additional knowledge accumulated about the reservoir or changes in reservoirbehavior or management. Normally, the contract will contain provisions defining thebuildup of the quantities depending on well come-in; the start and duration of the plateauperiod, as well as the plateau rate and changes therein caused by changes in knowledgeof the reservoir; and the start of the decline and the shape of the decline.

6.18 Any change in the profile originally agreed would have to be made by anannouncement deadline. Absolute limits may apply to the annual quantities as well asto the change rates from one year to the next or from the original rates to the new rates;commercial consequences would be included in the contract if larger changes werenc.:essary. Disputes on the economically recoverable reserves of a reservoir or onconsequences thereof that cannot be resolved between the parties will normally bereferred to an expert procedure for decision.

6.19 In both depletion- and dedication-type contracts, subsdtuionpossibilides must beclarified. Under a substitution clause it is possible, at the seller's discretion, to delivergas from another source in fulfillment of the delivery obligation from the source allocatedto the contract. Substitution mainly deals with exchanging risks. The question of forcemajeure then refers to the situation of the substituting source. As a protection for thebuyer the contract may specify limits on substitution and provide for rules governing theextent to which gas delivered from another source may later be delivered to other buyersfrom the dedicated source and vice versa.

A Basisfor Long-Term Gas Contracts, Par I 49

TABLE 10. Main Types of Risk-sharing between Reservoir Management and Markeing

Reservoir management Contractype/rikk sharing Consequences for marketing

Gas as a by-product

No outlet needed Gaz & bien plaire Sales as a replacementof fuel on a spot basis

Outlet neededno daily outlet flexibility Gas as produced Sales on a

spot/interuptible basis

Limited daily Depletion type Long-term sales possible,outlet flexibility high daily but daily flexibility must

Min Pay be provided in additionto long-term insrents

Gas as a substantial part of the ineome

Large daily outlet Depletion type, Long-term instrumentsflexibility, but income secured by are needed to phase outrestrictions due to annual Min Pay, market volumes or to tiereservoir maagement muiti-annual profile in gas from other sourcesnecessities (e.g., pressure depends on reservoirmaintenncopima reovery path)

No restrictions due Supply-type oriented, Instruments are needed toto reservoir management income secwred bridge field-specificnecessities (e.g., by Min Pay, risk or pass them on toreservoir large reative remaining reserve the customersto volumes sold risk

Resource management

No physical/commercial Supply type Adequate conract forcapacity restictions; long-em maketinglarge gas reservesavailable fixed term

Management of the fixed packagedevelopment of a income secured by amualsequence/portfolio Min Pay; no singleof reservoirs (depletion policy) reservoir risk


6.20 Supply-type Contracts. In a supply-type contract, delivery obligation isindependent of field management considerations, and supply is not linked to a specificfield; hence, the seller has an obligation to substitute from other fields. The profile isfixed by contract or by the customer and is not dependent on reservoir performance. Ifthe profile is variable, then it is determined by the buyer or at least by market needs.On the buyer's side, a prolongation and increase or decrease options for the plateau arealso possible features.

6.21 In a supply-type contract, the following questions have to be addressed:

* How is the tern or duration of the contract linked to the supply rate (packagedeal versus term deal)? The agreement may foresee a fixed amount of gas thatmay be taken within a certain range of annual capacity limited by theminimum-pay quantity and by the maximum availability. In that case the periodof the contract is a function of the average annual offtake (ackage dea4.Altenatively, a given range of capacity may be set over a fixed term. In thatcase, the overall amount of gas taken is a function of the average offtake (terndeal). A package deal is more representative for a seller pursuing a depletionpolicy, whereas a term deal is more likely when investment in capacity is crucialfor the seller's policy.

a Are capacity questions detemined by volue or energy? In the market, theenergy consumed, not the volume, is decisive. However, for all capacityquestions, the volumes are decisive. Gross calorific value (GCV) is partly givenby the field quality and is partly by the seller's technical/commecaconsiderations (e.g., whether and to what extent inert gases and higherhydrocarbons have been removed). More market-oriented contracts thereforetend to be handled in terms of energy instead of volume.

6.22 Contracts in Between. Some arrangements are possible whereby only a part ofthe reserves is sold to one specific buyer and the remaining reserves either remain unsoldor are sold to another buyer in such a manner that any reduction in reserves is firstallocated to that other buyer. These are supply-type-onented contracts, in which the firstbuyer is only affected by a reduction in reserves after the uncommitted reserves or thesales to the other buyer have been completely reduced.

A is for Long-Term Gas Conracts, Part 11 51

6.23 Gas as Produced. The typical case of gas as produced is gas that is a by-productof oil and has to be disposed of because flaring is not allowed and there is no other wayto dispose of the gas. The buyer would have to take the gas (and not just pay) becausethe offtake as such is the objective of the deal. High indemnifications are agreed in casethe gas is not offtaken, because of the high loss of oil revenue that may be involved. Asa protection for the buyer, most gas-as-produced contracts foresee a limit for the offtakeobligation of the buyer and define some limits on variations in delivery rates as well assome announcement rules. Deliveries may fluctuate but nonnally are relatively reliablebecause of the high incentive to produce in terms of oil revenue.

6.24 The price for gas as produced is comparatively low because the lack of flexibilityonly allows for marketing the gas in low-value sectors of the market or because of theextra costs incurred for storage and backup facilities if the gas is to be marketed in thehigh-value market segment.

6.25 Gaz a Bien Plaire. Gaz bien plaire is rather an exception to the contractual-typerules. Compared with a single spot sale, the parties to such an agreement would set inadvance the delivery point, the quality of the product, and the price of the gas in caseit should be delivered. Both parties are free to deliver or take at the sole discretion ofeither party.

6.26 Concwlsions on Types of Contracts. Supply-type or supply-type-oriented contractsseem typical of a developing gas industry in a gas-rich situation. Such contracts may bea way to ensure the commercial viability of captive investment down the chain whilemaking use of the economies of scale of the field and of the transporation system byselling additional gas to noncaptive customers at a lower price.

6.27 On the other hand, depletion- or dedication-type contracts seem to be morerepresentative of a gas-short situation with one or several medium-sized or small fieldsdiscovered. There is no way to interconnect the fields, either because of their locadonor because of geological reasons or inadequate incentives for exploration if the gasindustry is still in its developing stage and if only a few finds have been made so far. Ifthere are enough depletion-type contracts where the gas is collected by a trading andtransport company, that company may balance out the individual rish via a portfoliopolicy. Otherwise, the buyer must look for the appropriate market segments, especialyif storage is not possible for geological or cost reasons.

6.28 A depletion-type contract is linked relatively closely to the economic features ofan oil field, because the profile resulting from the minimum pay is close to the income


curve of an oil field due to the depletion of the reservoir. The decisive question,however, is wiieiher there is a market that can afford to take such gas.

6.29 In the case of associated gas, a country need not necessarily be gas rich; the gaswould be cheap compared with the competing fuels and might be sold on a spot basis,for lack of another suitable oudet.

6.30 Possible Degrees of Commitment. Gas deals may be marked by various degreesof commitment. Under a.firm commime, obligations are absolute and must befulfilled; the consequences of nonfulfillment are compensation claims or automaticallyliquidated damages. However, there may be some defined exceptions that do not requirecompensation, such as force majeure and reservoir reasons. If commitments cannot befulfilled, the contracting party must invest to fulfill its obligations, even if it is noteconomic to do so.

6.31 Commitments to best endeavors/efforts and reasonable endeavors/efforts are bothopen to nuances of interprtation and to judgment on the exact size of compensation orcommitment when a dispute arises. Best endeavors are clearly a stronger obligation thanreasonable endeavors, and the commitment to best endeavors usually involves theobligation to invest and to spend money to fulfill the obligation even if it might not beeconomic. On the other hand, reasonable endeavors provisions may not imply aninvestment obligation and would oblige action only if it does not entail loss. Bothdegrees of commitment will be subject to interpretation of the exact size of thecommitment when the case arises.

6.32 A provision giving sole discretion to one party gives practically complete freedomto that party. The advantage is that the matter to be decided is clearly defined.

6.33 Clauses referring tofiature agreements cover aspects that cannot be defined or thatthe pardes do not wish to define clearly at the time a contract is concluded. These arethen left to a future agreement. For such agreements, too, a large variety ofcommitments is possible: these range from an obligation to meet and discuss an issue;to an obligation to negodate in good faith; and even to a clear obligation to reachagreement along defined lines, such as state-of-the-art or standard business practice.

A Bois for Long-Tern Goa Contrads, Part 11 53

6.34 Profile of Commn nent during the Tenn of the Conrnct. During the term of acontract there are different stages with different degrees of commitment and also withdifferent mles for the main commitments of the contract. The text details the mainperiods of a contract, and Figure 5 presents a brief survey.

6.35 Run-in Period. During the run-in period there is only a reasonable endeavorsobligation on both sides to tae/make available as much gas as possible. A run-in periodmay last several weeks or months. It is reasonable for both parties to provide for it inorder to test the equipment as well as to gain experience with common procedures andcommunications. The provisions may also foresee the commissioning of equipment. Theend of the run-in period may be determined by definition or by a delivery test.

6.36 The consequence of the test, which usually would last several days, could be anadjustment of contractual obligations during the period of firm commitment in line withthe outcome of the test. The idea of a test to end the run-in period and to start theperiod of firm commitments seems to originate from oil-industry practice. It gives someprotecon to the seller because he is committed only to the extent he can actually meethis obligation. On the other hand, it provides some protection for the buyer, too, becausehis offtake obligation is also adjusted to what is reasonably possible and to what he canrely on.


daily/annual quantity

4-

2

| Run ln\Build-up Plateau | (Zialon) DeclinB |

Duradon Sevwal Seve r -520 3-10 severalweeks/ months years years Yasmonths uptose.

-. _____ virlyears______I_____

Carmct- Testng of Stepwise Long and Stepwlseiecs Equipment BuDid up Stable Downgrading

Delivery of Delveiy_ _ _ _ _ _ ______ Period _ _ _ k_

Coitt J Reasonable I Firm Firm __n) Firmm I t Endeavours I I

mpormnt Duration - Duraton - Level * how Long - Duration ofEerMents of Steps Stepsto be -Level -Changes -StepnssDeied ot Steps - how De- of Steps

- how oS- termined, -Announce-terin9d, by whom mint, byby whom whom

- Defntion ofEnd of_..Dvedres

FIGURE 5. Typical Phases or Profile of a Long-tenn Gas Sales Contm

A Basis for Long-Term Gas Contrads, Part 11 55

6.37 Buildup Period. With the buildup period, the firm obligations on both sidesgenerally start. The buildup period will typically consist of several steps by which thecontractual quantity is gradually increased up to the plateau or peak level. Each stepmay take several months or even a year. The determination of the buildup steps must notbe rigidly fixed in advance in the contract and may be done either by the producer or thebuyer, as follows:

o Nomination by the producer. This may be preferable because of the bringing-inof wells or modules of production equipment, in that the length and steps maydepend on the technical capacity of the wells or the production modules. Theseller here will announce the exact start and level of steps by giving severalmonths notice. As a protection for the buyer, there may be limits on the heightof the steps and their duration as well as rules on the announcement periods.

3 Nomination by the buyer. To take into account market developments as well asthe phase-in of the contract quantities into the market, it is typically the buyerwho nominates the buildup steps under a supply contract. Nonnally, these stepswill be of a duration of one year each, at least in areas where there is an annualpattem (e.g., caused by climate). The announcement period may be between oneand two years. The seller will have some protection with regard to the steepnessof the steps.

6.38 Plateau. The main requirements for a plateau period are a reasonable length anda reliable delivery rate. The requirement for a plateau period mainly stems from therequirement of downstream investment. From the seller's point of view, there isnormally no reason for a plateau period, except when the production capacity may belimited over a longer time. Normally, the seller's considerations are rather driven byNPV and discounted cash flow (DCF) considerations, considerations of reservoirmanagement, or both.

6.39 The seller will ask for possibilities to change the plateau rate, the plateau length,or both as a function of the performance of the reservoir or as a function of additionalfinds in that reservoir or in its neighborhood. The buyer's interest, on the other hand,will be a long and stable plateau, possibly with the option to change the plateau rate toadapt it to changes in the market. In case of a long lead time before the start of theplateau period, an increase or a decrease option for the plateau rate may be granted tothe buyer; this option is either linked to a one-sided decision by the buyer or to objectivecriteria such as reservoir conditions and developments in the market.

56 Long-Ternn Gas Contracs

6.40 Prolongadon. The seller may hope for additional finds or better-than-anticipatedperformance of the reservoir, and the buyer has a natural wish to stay in business. Aprolongation provision therefore could benefit both sides. It could be a one-sided optionlinked to objective criteria (reserves or market) or just a clause to negotiate in due time.

6.41 Decline. During the decline period, seller and buyer will have a common interestin gradually phasing out deliveries because of a decline in the production rate of thereservoir and because of phasing out of the contract in the market. However, the sellermay be interested in not dropping below a certain level at which the cost of maintainingproduction capacity is bigher than the revenues under the contract.

6.42 Instnuments for Plexibilty In Gas Contmcts. Flexibility is critical in a numberof ways. Because gas cannot be stored easily, requirements for flexibility of supply andacceptance must be decided before the capacity of the gas chain is finally fixed. Thedesigned capacity determines investment down the chain, and the revenue created usingthat chain is then a function of the utilization rate of this capacity. On the producer'sside, creating flexibility can either be considered as an extra investment (on amargnal-cost basis) or as lower uilization of the investment-as a lower guarantee ofuilization of the investment via a lower minimum pay.

6.43 On ".e seller's side, capacity may be expanded easily in large onshore fields nearthe delivery point where only additional drilling costs and field piping are needed, butin other cases there may be clear limits to capacity after which a jump in investment willbe required in production or delivery infrastructure. This holds, for example, foroffshore platforms, which have a limit on topside weight that in turn limits treaumentcapacity, or for LNG trains, which have a certain optimal size that cannot be exceededfor technical reasons. Long-distance onshore pipelines also have limits, which are givenby the maximum diameter and maximum design pressure of pipelines available and theoptimal distance between compressor stations. After that capacity has been reached, ajump in investment will be required.

6.44 In most cases, the seller will tend to invest in the infrastrcture for an optimalcapacity. As long as this capacity is not reached, extra flexibility may be provided bydesigning the system for a higher capacity at marginal investment as long as the projectis still in the planning phase. Once the system has been built, however, extra flexibilityamounts to asking for a lower minimum payment.

6.45 In the first case, the cost of flexibility can be identified as a separate item so thatflexibility can be sold on its own. A decision can then be taken as to whether it is more

A Basisfor Long-Tenn Gas Contraas, Part 1 57

economic to provide flexibility upstream or downsteam (depending on opportunity costof fuel switching, costs of LNG or LPG peak-shaving plants and the geologicalavailability of storage facilities and their economics) as well as on the cost of transportingthe flexibility from the delivery point to the place of consumption. The sale of flexibilityis linked to a gas-rich rather than to a gas-short situation, because otherwise theproduction capacity would be used to produce gas and not flexibility.

6.46 In countries in the northern hemisphere, there is not only a substantial seasonalpattern but also large variations in the size of seasonal peaks as well as in annual demandcaused by climate. Further variations in annual demand derive from business cycles andthe phase-in or -out of other contracts (e.g., depletion-type contcts).

6.47 In countries near the equator, the climatic influence will be different from that inthe northern hemisphere. No seasonal influence is felt from heating demand, butpossibly some indirect influence derives from hydrology or irrigation needs and theireffect on hydropower generation and thus on gas demand for power generation.

6.48 Because seasonal demand variations in countries with hot climates-if there areany variations at all-are linked to climate only indirecdy (e.g., by the power systems),considerations pertinent to the northern hemisphere must be treated with caution in thetropics. Specific methods to cope with seasonal demand variations linked to the powersystem (e.g., overcapacity for power but not for generated electricity in tee hydrosystem) may be cheaper than the cost of providing any extra capacity in the gas system.This also applies to backup considerationt

6.49 On the buyer's side, then, instrumentalities are needed to cope with long-termdevelopments, such as market growth. These may take the form of investment inadditional capacity. Instrumenlities are also needed to cope with fluctuations in demandon an annual or daily basis. In such cases, the capacity must already be available, orcustomers would have to be cut off. Here, at least, the long-term and short-term captiveinvestments should have priority to be served from remaining supplies.

6.50 For all flexibility considerations it is always importnt to remember that the gasindustry is a chain of fixed linked capacities. Where the daily maximum capacity undera contract is available all year round, the seasonal peak and the annual demand must becovered by the same maximum availability. Unless the annual contractual flexibility islarge or the seasonal demand variation low, some extra peak shaving will be required.There may, however, be contracts where the maximum availability on a daily orshort-term basis is higher an the annual availability. Such a contract would not only


provide quantities but also some peak flexibilities, which might either have a separateprice or would otherwise be provided for in the price of the gas (cf. Figures 6a and 6b).

6.51 The flexibility in a contract is defined as the difference between the availabilityand the offtakelminimum-pay obligation within a given time span. This may be agreedupon on an hourly, daily, weekly, monthly, quarterly, annual, or multi-annual basis.Different flexibilities may be defined for different durations. It is not unusual to link allrights and obligtions to one parameter, such as a daily quantity, and to determine allrights and obligations on a hourly, monthly, and annual basis as a multiple or fractionof that variable. The need for storage capacity depends heavily on the annual and dailyflexibility and their relationship to each other, as shown by Figures 6a and 6b.

6.52 Taking daily quantity as a main parameter, the daily avrilability may be defined,for example, as 140 percent of the daily quantity, and the maximum hourly rate-if itis defined at all-may be 1t0 percent of the daily quantity divided by 20 hours so thatan hourly offtake pattern over the day is possible. The minimum flow on an hourly basisor the daily minimum pay may then be defined as a percentage or share of the dailyquantity if not zero. From 75 to 89 percent of availability is on the high side, but it isnot unusual for associated gas. The annual availability may be 365 times the dailyavailability or sorie lower multiple for reasons of maintenance on the seller's or buyer'sside but also for reasons of reservoir management and because the maximum capacity isneeded for peak-shaving demands, but not throughout the year. The annual minimumpay will also normally differ from 365 times the daily minimum pay (i.e., it will beligher). The daily quantity or the annual quantity may as such not represent anyobligation. However, in some legal systems (e.g., under English law), the terms dailyor annual contract quantity must be used with caution, because they might define aparticular commitment.

6.53 Minumun Pay. There is a difference between an offtake obligation with damageclaims lined to it, which must be determined on a case-by-case basis, and aminimum-pay system, in which compensation claims are replaced by an obligation to paya certain amount of money for quantities of gas taken that are less than the minimum-payobligation.

6.54 So-called lost minbium pay is usually used on a daily basis, and because of itsclear consequences it may have an even stronger effect than the threat of damage claims.

A Basis for Long-Term Gas Contracts, Part i1 59

OailyXl 1111 ; Sales

Daiiy Conwactal Capacity

I Average Annual Capacity,,¢ 10 0 \ t ~~~......................... ...........

Off takes

Average Annual Min. Pay,, -- ~.-...-.-.-.-----................. ---* ___.

I IDaily Mi. Pay

Winter Summer

FIGURE 6a. Seasonal F exiiy wih DAily Capcty Equd to Average Annual Capcty


DailyBI iii Sales

1 \ i Daily Contaczual Caoacity1 Extra Flexibility I

ISuppliedb1SellerI/ Reducir:g Storage Needs I Average Annual Capacity

........... I . .......-- 7Offtakes

Daily Min. Pay into

Winter Summer

FIGURE 6b. Seasoad fexitY with Daly Capac Greatr han Average AnW Capaciy

A Basis for Long-Tein Gas Contracts, Part 1 61

It implies a very strong incentive to take the gas, and a producer may use that tool tomake sure that the gas is offtaken by the buyer. The price fer the minimum pay is notnecessarily identical with the price for the gas taken. AU elements linked to variableproduction costs and royalties and profit elements can be excluded. The buyer mayargue that the seller should not benefit from the buyer's problems in not taking the gas.

6.55 Make-up minimum pay is a minimum pay that can be made up within a certaintime. If the intention of a minimum pay is to ensure a cash flow rather than a gas flow,the minimum pay will mostly be dealt with on an annual basis and sometimes on aquarterly or even a monthly basis. The cash-flow target is fulfilled if the minimum payis treated as a prepayment that will be offset against future payments for takes in excessof the annual minimum pay. The mechanism whereby the payment obligation forquantities taken in excess of the annual minimum pay is reduced in line with quantitiesor money already paid under an earlier minimum pay is usually called make-up nght.

6.56 The basic idea of the minimum pay is that a minimum cash flow for the producershould be secured. It is therefore hard to accept that a make-up price should elapse atall if the gas is stiU producible. The seller has already received the money for the gas,possibly less some deductions for variable cost not incurred. There is no reason, then,not to set off the money already paid against future deliveries that are in excess of theminimum pay agreed and do not require additional capacity not yet installed. However,make-up rights usualy elapse after three to five years; ten years have also been agreed.

6.57 The minimum pay can be regarded as prepaid gas, so the mak-up gas is free, oronly the variable costs (deducted in the minimum-pay price) must be paid. Another wayto look at a minimum pay is as an "installment" that will be credited once an equivalentamount of gas is taken above the minimum pay. Under such an arrangement, the sellermight even have to pay back part of the money received if pnces have fallen.

6.58 In both cases, the minimum pay would still be a severe penalty on the buyer andinvolves a strong incentive to take the gas. First, the risk always remains that makingup gas is not possible before the time limit for exercising the make-up right elapses andthe minimum pay is finally lost. Second, it involves lost interest, although speculationon rising prices might, if realized, compensate for the interest lost.

6.59 Normally, make-up quantities are accounted for after the minimum-pay quantityfor the year has been taken. The possibility to make up gas may also be construed onlyafter a quantity of gas higher than the minimum-pay quantity has been taken. Such asystem is not very logical, however, and it would create very complicated rules.

62 Long-Tern Gas Contracts

6.60 Another alternative would be similar to a minimum-pay/make-up system but inwhich minimum pay only has to be paid after it is clear that no make-up quantities willoccur. In that case, the risk of minimum pay would still be bome by the buyer. Onaverage, the minimum pay line is still fulfilled over the full contract term. However, inthat case it would be the seller who suffers a loss of interest between the time that thequantities were not taken and the time of make-up or final payment. It would not bereasonable for the seller to grant a completely unlimited minimum pay credit, so this willbe limited, for example, to 10 percent of the annual quantity and expire after 3 to 5years. A credited minimum pay might be a good instrument to bridge the differenceduring negotiations between the flexibility offered and the flexibility asked for.

6.61 Carry-forward. If it is assumed that the cash flow needs of the seller are definedby a minimum-pay line and that the seller should not benefit from a situation in whichthe buyer suffers, gas taken in excess of the minimum pay could be credited against theminimum-pay quantities in later years, reducing the minimum-pay obligation in thoseyears. This right is usually called carry-forward right. With such a right, all quantitiestaken in excess of the annual minimum pay would be accumulated on a specific accountuntil they are used or expire. The carry-forward right stemming from a specific yearwill usually expire after a certain period. The expiration periods used in Europeancontracts are usually of the same duration as those set for make-up rights.

6.62 To optimize the price he gets for his supplies, the seller may have to seek someproteeion against excessive use by the buyer of carry-forward rights. Some limitationis already given by the daily minimum-pay obligation. Furthermore, the seller mayinclude a provision whereby the use of a carry-forward right in any year should notexceed a certain percentage of the annual quantity.

6.63 At first glance, carry-forward looks similar to minimum pay, but there is oneimportant difference: Carry-forward right is created by a higher utilization of the systemupstream and downstream than was foreseen by the definition of the minimum pay. Asthe minimum pay is considered to be a benchmark where investment upstream anddownstream is profitable, so carry-forward stems from the situation in which both partieshave extra revenue in excess of their minimum need. If in later years the buyer is unableto take as much gas as needed to fulfill the minimum-pay obligation, it would seemunfair that the buyer must suffer not only from the underutilization of the investment butfrom a minimum pay penalty while the seller gets away with an extra profit from earlieryears.

A Baois for Long-Tern Gao Contract, Pan 11 63

6.64 Carry forward and, to a lesser extent, minimum pay are good instruments to caterto multi-annual variations caused by business cycles or climatic aberrations that are notcovered by the annual flexibility but that may balance out over the years.

6.65 Start of the Contract Year. For administrative purposes it may be advisable todefine the contract year in line with the calendar year. However, if seasonal influenceson gas sales are notable, other definitions may be more appropriate from the buyer'spoint of view. For the buyer, it is advantageous to have the time periods with highofftakes and with high influence on the total annual offtake forced by seasonal influencesat the beginning of the contract year. It is then easier to plan or to optimize matters suchas the use of carry-forward at the end of the contract year, when the main facts aboutannual offtake necessities are already known. In Europe, where winter demand may beas high as 70 percent of the total sales in a year, it is most common to start the contractyear on 1 October. The definition of the start of the contract year seems to be ratherneutral for the cash flow targets of the seller, however.

6.66 Correction Ements. The risk of multi-annual offtake fluctuations in the marketmay be covered by a large flexibility between the annual minimum pay and the annualavailability. This would leave the buyer the possibility to cope with all these variations.If, in a given year, the various influences do not result in the absolute minimum-payquantity, the low minimum pay agreed would offer the buyer a flohxibility that could beused for price optimization between suppliers.

6.67 An altemative to a flexibility large enough to cover all possible varations wouldthen be to agree on a somewhat smaller flexibility but to allow for modificationsdependent on the actual situation with regard to climatic influences or business cycles.Where variables such as business activity or climatic influences exceed certain limits, theparties might agree on modifications to the minimum offtake as well as to the annualavailability. For climatic variations this may be a function of the deviation of the actualtemperature from the long-term average temperature or rainfall or, for business activity,as a function of some business indicator or of the gas sales in a given year. This modelwould still be able to handle the main concerns of the buyer, although the buyer does notget free flexibility to take more gas from other sellers.

6.68 It will not always be easy to find indicators that are representative and objectiveenough or to define or negotiate the relation between them and the change in offtake oravailability obligation. One example would be th.e annual average temperature of alocation that is representative of the sales area or the average rainfall in an area withinfluence on the hydrology. The parties might agree that for each degree celsius above

64 Long-Teim Gas ContraCs

a certain average temperature the annual offtake obligation is reduced by x percent. Theadjustment of the annual offtake obligation or availability obligation as a function ofsome objective parameters is in a sense the fine tuning of the risk and chance patternwith regard to flexibility between seller and producer.

6.69 Exceptions to Obligations. Two are notable. First, planned adjustments of theobligations may be related to reservoir management or to market developments. Thesequestions were discussed earlier, in connection with the quantity profile over the years.Second, a suspension of the obligations may be acceptable, as long as they are balancedbetween the parties to a contract. If one party is relieved of its obligation, the othershould be compensated bv being relieved of a corresponding obligation or by benefitingfrom an additional equiv ant obligation by the first party.

6.70 A disturbance somewhere in the gas chain will block everything upstream anddownstream unless switching or storage is possible. When a disturbance is caused byforce majeure, one rule would be that each party undertakes to resolve its own problemswithout maldng a damage claim against the other party. The parties' commitmentsvis-a-vis each other would then be reduced accordingly. For example, if availability isreduced, the offtake and minimum-pay obligations are reduced by the same amount.

6.71 An event considered to have happened by force majeure is beyond the control ofthe party concerned acting in accordance with the standard of a reasonable and prudentoperon; it is an unavoidable nsk. Any party affected upstream or downstream in thechain would have had the same risk if it had been involved in doing the job by itself.

6.72 The interrelated nature of the gas chain means that the extent to which disturbanceup or down the chain may be passed on must be defined. This means defining the extentto which the disturbances are also regarded as force majeure by those not directyinvolved. As a protection for the party that is indirectly affected but not involved in theactual event of force majeure, claims could be passed on from the buyer vis-k-vis thebuyer's customer to the seller. If this is not done, the partners at the point in the chainwhere the disturbance occurs may be inclined to consider the event as force majeurebecause they may find it easier to pass the consequences up or down the chain. Thismay be counterbalanced by passing on the claims to possible titles, if these events are notforce majeure. The reduction of obligations because of force majeure or any otherreason means that the obligation is only reduced for the moment, and the obligated partywill live up to it as soon as the preventing cause is over.

A Bois for Long-Term Gas Contracts, Part 1 65

6.73 The party whose system is not working properly will have to undertake aUnecessary measures to fulfill its obligations as soon as possible. Some limits may applyto an obligation to rebuild facilities in line with the standards of a reasonable and prudentoperation. It may be considered unreasonable to invest in treatment facilities at all whenthe field is already in decline and will only be producing for a short time.

6.74 Although the main obligations still persist even if they are suspended, it isdifficult for the party not affected to undertake new commitments, which, for the seller,means selling gas on a long-term basis that he is not able to deliver to the buyer or, forthe buyer, signing new long-term contracts. To deal with such cases, and to deal withthe question of whether it is economic to reinvest, a clause to the effect that the partieswil meet to agree on the consequences in the event of a very severe long-lasting forcemajeure may be included in the contract.

6.75 Damage Claims. Although the risk of underutilized capacity is more or lesssymmetric, the risks of damages arising from nonfulfilment of delivery obligations maynot be. Normally, in case of force majeure, no damage claims will be possible.However, in some cases, and in an event of force majeure, automatic consequences mayensue for nonfulfillment of the contact.

6.76 For the seller, damage caused by being prevented by the buyer from deliveringthe gas is normally just the money the seller would receive for the sale of that gas. Ina take-or-pay contract that would be automatically covered because the buyer must payfor the gas not takn, albeit possibly at a somewhat lower price.

6.77 In a few cases, a stop of offakes by the buyer may technically harm the systemof the seller. The seller would be expected to take due precautions to be able to stop theflow of gas. However, takdng less than the minimum flow or taking less than a certainminimum quantity may harm the treatment facilities or even have a negative effect on thereservoir. In addition, loss of revenue from oil or other liquids normally producedtogether with gas may ensue if flaring is banned and if no gas offtake or other disposalof the gas is possible.

6.78 Damage to the buyer, conversely, may-but should not-be relatively small ifalternative sources are available. In that case, the buyer's damage is limited to thedifference in price plus the difference in cost stemming from the different conditions ofthe substituting gas, such as delivery structre, quality, and delivery point. The buyermay otherwise be forced to draw on storage or even cut off supplies to consumers. Ifthe buyer is the end user of the gas, however, the buyer may be forced to use an


alternative fuel that might have supply costs much higher than the price of gas. A typicalexample would be a combined cycle that can only run on very clean distillates such asLPGs or gasoil. In this case, the additional costs incurred by using such a fuel may wellbe about the gas price or even higher. If alternative supplies are not available, part ofthe buyer's investment will be idle.

6.79 The link between the elements of the gas chain is very strict and may even includelinks to the electricity grid. Electricity is necessary for most production processes butis only a small component costwise. The damage caused directly or indirectly by ashortfall in gas production may therefore trgger losses far beyond the price of the gas.For the buyer, then, inclusion of the customer's losses becomes crucial to the extent thatdamage claims from the customer cannot be limited.

6.80 The seller will try to avoid claims for losses incurred by the buyer's customerseither by explicitly excluding them in the contal arrangements or by agreeing tocompensate them in a lump sum per gas unit not delivered or made available-througha rebate for example. Furthermore, overall limits on possible damage claims may beagreed. Under some legal systems, however, damage claims can neither be excluded norbe limited if their origin is severe misbehavior, such as gross negligence by a leadingresentative of the company. In no case, however, should contracting parties accedeto restdctions on possible damage claims caused by willful misconduct: this wouldencourage breach of contract.

6.81 For all cases of nonavailability or failure to offtake gas because of force majeureon the buyer's side, provisions must be included that allow accurate calculation of thereduction of the daily and annual delivery and offtake obligations, respwectively, causedby such shortfalls.

6.82 Technkalkes of Handing the Gas Flow. Two main aspects are characteristicof handling the gas flow. First, arrangements must be made to handle the gas flow in linewith the agreements and according to the instructions of the party entitled to specifycertain parameters. The issue of material importance here is the announcement period,frequency and the extent of changes in offtakes (within the contraclly defined limits)or in the case of a gas-as-produced contract of deliveries. That issue has a great impacton the design of the upstream and downstream system and should therefore be dealt within the contract itself. Second, the volumes and quality parameters of the gas flow mustbe recorded for invoicing purposes and to keep track of the other rights and obligationsstemming from actual deliveries.


6.83 The practical question of communications regarding the handling of the gas flowcontrol is better left to a separate document, which may more easily be changed asexperience dictates. This document may include addresses, timing, and format ofinformation routines as well as an agreement on the means of communication. Recordingthe gas flow is usually dealt with in the contract itself, however, under an extra provisioncalled "metering." The following points have to be dealt with (a) type of meter,applicable standards, and accuracy; (b) unit of measurement; (c) check meters; (d)cost-sharing of equipment; (e) correction of errors; and (f) settling of disputes by experts.

6.84 Quaty Spec(fcadon. The elements of the quality specification depend on therules of the country concerned or on the specifications defined for use in certainapplications. Generally, it is the high quality of the gas (only very few impurities) thatenables gas to catch some premium for some specific applications. Therefore, specifyingthe quality is of great importance.

6.85 When loolkng at the quality of the gas a distinction may be made betweenspecifications describing the combustion properties of the gas, such as the GCV and theWobbe index; specifications linked to the transportation properties of the gas, such as thecontent of inert gases (e.g., N2) or the water and hydrocarbon dewpoint; and impuritiesthat may cause damage to property or harm to persons.

6.86 The GCV plays a specific role, being the link between the volume and the energycontent of the gas. In a volume contract, where rights and obligations are linked tovolumes, actual GCV defines the amount of energy actually delivered. Variations inGCV would then create a risk that the contracted quantities of gas deviate from marketneeds. Another question would be whether the GCV is still suitable for the customer'sappliances. On the producer's side, GCV depends on the field quality and the removalof the higher hydrocarbons as well as of the inert gases. The removal of higherhydrocarbons is mostly a commercial issue: usually propane, butane, and heptane plushigher hydrocarbons are removed, and ethane is left in the gas. The extraction of inertgases is also a more a commercial than a technical question. Hence, substantial changesof the GCV are a marketing risk for the buyer but a commercial option for the seller.

6.87 For energy contracts, rights and obligations are defined in terms of energy, andcapacity needed in the downstream system depends on GCV; no extra marketing risksare involved regarding quantity. The lower the GCV, the higher the capacity needed.For protection, the buyer will normally ask for a range within which GCV must fall.

68 Long-Temn Gas Contracts

6.88 In addition to specification of the gas, a quality article would clarify theconsequences of not meeting the specifications. For gas that does not keep within thelimits for harmful or damaging components, the buyer should have the right to refuseacceptance. The gas would then be considered unavailable and subject to the relevantcontractual consequences. A different regime could be applied when limits are passedthat do not entail immediate risks but only have commercially negative consequences,such as exceeding the limits for inert gases. In such cases, the parties could agree ona rebate, but the buyer would still be obliged to take the gas. The question of who willhave to take the risk to adjust to new quality requirements that may be imposed by agovernmental authority or that may be caused by changes in the state of the art mightalso require clarification.

6.89 A definition of the qualities and how to determine compliance with such qualitiesin the contract or in a related document. This definition should include test methods aswell as a description of the metering facilities and calculation methods (see Appendix).

Pdclng Provisions in General

6.90 The quantity risks (i.e., marketing risks) are taken mainly by the buyer byaccepting a minimum pay. The exceptions are force majeure risks, which are taken byboth sides. After the risks and chances have been balanced out and the quantity and riskpatterns are determined in negotiations, the final balance between the parties may bereached by pricing.

6.91 Table 11 shows some aspects of both sides in negotiating the pricing provisionsTable 12 shows issues influencing the pricing provisions.

6.92 Several pricing systems are possible. Because gas (unlike most othercommodities) is linked to capacity aU the way down to the market but has to competewith commodities in the market, a price might be agreed per capacity of gas to be madeavailable, whether used or not. Alternatively, a price could be set per unit of gasdelivered. In addition, a cost-plus-linked price could be agreed, versus a price derivedfrom the replacement value of the gas against its substitute in the market.

A Basls for Long-Term Gas Comracgs, Partn 69

TABLE 11. Negodiaton of the Pdce ProWslins

Producer's pects

Costs can be identified; after investment is finalized capitalexpenditures (CAPEX) are given; estimate of operadonalexpenditures (OPEX) possible with ex post verification

Mainly one decision point: invest in project or not.

After investment is final only few actions are left.

-- Buyer's aspects

- Market is an everyday exercise

- New customers almost always have fuel oil as an alternative

- Replacement value may differ from cusimer to customer

- Cost allocation not well defined

-- Vis-a-vis market sectors-- Vis-A-vis the various sellers

-Stepwise buildup of the infrastructure.

70 Long-Teim Gas Contraacs

TABLE 12. Issues Influencing the Piiclng Provisions

* General situation

Gas-short country or gas-rich countrySharing of risks and chances (cost plus vs. netback)Place (share) of the gas compared with competing fuelPenetration strategy, penetration speed aimed at

* The "Quality" of the Product (the price should reflect the'quality' of the product):

Reliability of the gas, steadiness of the profile (e.g., linkedto the reservoir or not)

Flexibility of deliveries

Quality.

* Considerations to reflect the market

- What are the competing fuels?

- Shares of the competing fuels

- Changes of competing fuels over time or by pricedevelopment

- Premium may change due to technical development

- Changes in basic market structure (gas-to-gas competition)

- Changes in specific marketing costs due to changes inmarket structure (e.g. load factor) or changes in salesvolume

* Taxation

ABsis for Long-Teni Gas Conracts, Part 11 71

6.93 Substitutes in the marketplace are predominantly oil products or coal, and inpractically all cases these are tradable and storable goods that are not linked o a fixedcapacity. Pricing linked to a replacement value in the market is therefore dominantlylinked to the quantity of gas instead of to a delivery capacity. Inversely, in cost-pluspricing, it seems logical to have a high share of the price as a capacity charge and asmall share as a com:nodity charge (or demand charge). The reason is the small portionof costs that depends on the actual production rate and the high portion that depends onthe capacity installed and kept in operation. It is, however, common practice to construea cost-plus price predominantly as a commodity charge. Linked to a minimum-payconcept, the main target (to guarantee cost recovery), is achieved here, too.

6.94 Extra peak capacity may be provided at a capacity charge, however, based oncosts of capacity, or it may be determined by looling at the price for dual-firing capacityon the market.

6.95 The relation between a cost-plus price and a replacement value is as follows. Ifthe cost-plus price for the gas is higher than the replacement value of the gas in themarket, the gas cannot be economically marketed. Looking at the situation the other wayaround, if the replacement value of the gas is less than the cost-plus price for the gaschain down to that point, it would not be profitable to invest in its production.

6.96 If there is an extra profit between the market replacement value and the cost-plusprice to reach the marketplace, two questions arise that strongly influence the furitherdevelopment of the gas industry: how the extra profit is distributed between the seller andthe buyer; and whether the extra profit is spent within or outside the gas business. Somemodel examples are discussed below.

6.97 A special case that is not untypical of developing countries consists of oneproducing field and mainly one large customer (e.g., one field to one power plant).Here, a bilateral contract with a minimum-pay clause may not achieve the overalleconomic optimum. A contract would lead to the optimization of two subsystems thatmay not be identical with the optimum of the overall system, especially if the price forthe gas does not reflect commercial alternatives for one of the parties and would therebyonly determine the split of income between the parties. This could also be achievedwithout a contract or a price but just by a company combining both ownership of the gasproduction facilities and the gas-consuming facilities.

6.98 Cost-plus seems a typical pattern in a gas-rich situation. By definition, reservesare large compared with the immediate demand in the market. The easiest situation is


a gas-rich situation with some large captive users to start the development. This wouldleave room to invest in a larger capacity of the pipe and storage grid than is immediatelyneeded as well as in the production capacity. Thus, over time, additional marketsegments may be picked up that can only be phased in gradually, or market segments thatare based on a low replacement value because of their interruptible basis can be tied in.

6.99 Another case is that the development may start with a low-ost field and cost-pluspricing. There may then be an extra margin between the purchasing pnce of gas and theselling price of gas compared with its market value to finance the con.struction of aninitial gas infrastructure and to give incentives to establish a market. Once gas isavailable at a location, the market for it will develop firther. Over time, the pricebetween the seller and buyer may be raised to the replacement value of the gas. Thismight bring in other gas finds that can only be developed at a higher price. It might evencreate an incentive to explore for gas. In such a case, the depletion policy of a large gasfield will most likely not be determined by cost/income considerations alone but ratherby an overall depletion policy with regard to marketing or caused by policyconsiderations imposed by a government or i, a monopsonistic buyer. The motivationmay include keeping a large gas field in reserve as a short-term backup for actualshortfalls, as a backup for a decrease in reserves in other fields, but also to supply theflexibility needed to cover annual and seasonal demand fluctuations and as a long-termbackup for an increase in demand in the market.

6.100 In a case of several fields of medium or small size, the cheapest fields may bepicked up first at a cost-plus price to develop the gas distribution infrastrucxre and themarketing of gas. Later, the more expensive fields may be tied in, either because of ademand at a higher price level or because the higher purchasing costs by the buyer arerolled in. This makes sense if the gas distribution infrastcture is underutilized. Thesystem of rolling in, however, only works if the buyer can discriminate between thesellers of old and new gas (be it by a contract or by regulation). A system ofredetermination of the pricing during the lifetime of the contract would be contrary tothat approach. The system presupposes that gas fields are already proved or will beproved in the process of looking for oil without giving gas-specific incentives forexploration.

6.101 As soon as a supply gap opens up, it may be closed by the buyer by offering aprice for new supplies high enough to make the development of additional capacityattractive.


6.102 Whether to phase out of the market or whether to pay a price high enough tomake the development of additional capacity attractive would in that system depend onwhether the price for additional purchasing capacity plus the cost to sustain or enlargethe capacity is less than the loss of (additional) income resulting from not selling suchquantities in the market.

6.103 In a case in which only a few large suppliers are involved, possibly includingcross-border deals, the main features are as follows: First, discrimination between thesellers is hardly possible. Second, it is unlikely that gas will be sold on a cost-plus basisbut would rather be sold on the basis of a market replacement value. Especially if anincrease in demand has to be supplied from the existing suppliers, price discriminationby the buyer vis-a-vis existing suppliers is not possible, and no cost-plus system istherefore possible. In that constellation there is no possibility for the rolling in of higherprices. Before offering a price for additional quantities of gas that exceeds what gas mayyield in the market Qess the costs to bring it to the market), a buyer would rather notincrease its market or phase-out of it than accept a nonmarketable price with possibleprejudice for all other gas supplies. Conversely, a supplier would be very cautious ofselling new additional gas below the price agreed for existing gas supplies.

6.104 In a case in which the dominant share of supplies comes from many fields withassociated gas, costs attributable to the production of gas are small, and a negativecommercial impact may result from not disposing of the gas because of the potential lossof oil income. If associated gas is the dominant source of gas for the gas industry, itmight be risky to base long-term captive investment on gas that is driven by oilproduction over the short and long term. At least the share of gas dedicated to captiveinvestment such as combined cycles or local supply grids will be rather low and willrequire some backup facilities. The bulk of gas would be used in applications where gascan be replaced at shorter or longer notice without jeopardizing the commerciality of theinvestment (i.e., in a market with short-term interruptibility or medium-term phasing outpossibilities).

6.105 This constellation may result in a ricing system that is oriented to the price ofheavy fuel oil without any noticeable premium, because short-term interruptibilityexcludes an investment premium; on the contrary, the investment for dual-firingcapability must be recovered by a lower price for the gas. In the case of many producersof assodatd gas, situatiors may emerge during seasons with low gas or energy demandwhere producers will even undercut the heavy fuel price line (i.e., where a gas-to-gascompetition emerges).


Picing Provisions in Detail

6.106 Obviously, the conditions agreed for the gas have to be taken into account whendiscussing pricing. Both sides will have different evaluations of the various elementscontained in the conditions other than price. Flexibility will be evaluated by the producerbased on the extra investment or on the loss of secured income via a reduction of theminimum pay, whereas on the buyer's side it may be evaluated via the access it gives toadditional market segments4 or via the costs of storage and peak shavir.g saved.

6.107 Issues may also arise in a contract in which both sides may agree on the costsnecessary to deal with the issue but have different views of the likelihood of issues, suchas force majeure actually happening.

6.108 In negotiating the price, all elements agreed so far will be taken up, especiallywhen one side feels unsatisfied about the conditions. Either the pricing ranges overlapand there is a deal, or they do not overlap and there may be no deal. In such a case,looking anew at the conditions may help -elements that are of great value to one sideand of a smaller value to the other side can still be changed.

6.109 Cost-plas Approach. Although cost-plus pricing seems to be morestraightforward than netback pricing, several elements in cost-plus pricing might betopics for discussion:

0 Inclsion of exploration costs. Should only the cost of exploration for the findconcerned be included or should there be an extra charge to cope with the costof dry exploration wells? The approach could also be that the actual replacementcosts to discover an equivalent amount of gas are included, which, however, aredifficult to assess. A pricing system that only recovers the actual explorationcosts incurred does not give compenaton for the exploration risks. This mightnot be necessary if exploration is motivated anyway by oil, and gas finds are justa by-rroduct.

* Cost of productionfacitities. How should depreciation be dealt with?

* inanng assumptions. What will be the share of equity and interest on equity?

* Calulations. Should the calculation be based on historic costs or shouldreplacement costs be calculated? In that case there might be an argument to pegthat part to some investment index.

A Basis for Long-Term Gas Contraas, Part 11 75

o Allocation of costs. If gas is a by-product, the question arises as to how toallocate the cost of facilities common to oil and gas. As costs are dominantlylinked to a capacity to deliver gas and not to the volumes, it is also important toconsider if and how a capacity-related charge should be transformed into acommodity charge. The minimum-pay quantity would be one obvious solution.

6.110 Maile Replacement Value/Netback Approach. The concept of marketreplacement value is intended to estimate the actual or potential value in the marketresulting from replacing some other fuel by gas. Compared with a cost-plus approach,this concept does not refer to a single historic decision but looks at a variety of decisionsin the marketplace to be taken at present or in the future. The approach thereforeinevitably includes hypothetical elements. The decision of a large number of customersmay in addition be influenced by many arguments, such as reliability of supply,environmental attitudes, and so on, which can hardly be expressed in terms of money.

6.111 Figure 7a shows how the replacement value and the netback to the delivery pointare determined vis-a-vis one competing fuel. The starting point is the thermalequivalency. Here, the difference between the net calorific value (NCV) and the grosscalorific va1.ue (GCV) has to be taken into account. For fuel oils, the net calorific valueis normally quoted, whereas gas is usually measured in terms of gross calorific value.Furthermore, the ratio between the net calorific value and the gross calorific value is inthe order of 0.90 for gas and of 0.95 for higher hydrocarbons. The difference is causedby the evaporation of the water resulting from the combustion of any hydrocarbon. Thisenergy might be recovered by condensing the water, but this would require additionalinvestment. Therefore, a comparison with other fuels is generally based on NCV. Ina price fcrmula, this would be reflected by a factor representing the specific energycontent (NCV) per unit of gas ard the competing fuel, resectively, multiplied by theratio between the NCV and the GCV for the gas (which, in most cases, will be very nearto 0.90).

76 Long&Te Gas Contracts

Gas Price

Price of Compeing FuJel

-1) Thermal Equivalem( Blased on Nolt Calorific Value )

2) Addiffons to the Markcat Valus of Gas:a) Depending on Price ( e.g.: Efffciency)b) Independentof Price (Lower PEX, Taxt Diffrendals/

LowerCAPEX)^--3) Cost ot Sales

a) Depending on Price ( Fuel Gas, Price Related Taxes )b) lndependemt of Price ( OPEX/ CAPEX )

FIGURE 7a. ReplOcewjn Vige of Gs Yeasgs Coinedg PaelNetback

A BasiforLong-Temu Ga Contracs, Part 1 77

6.112 For the purpose of finding the market replacement value, a distinction must bemade between two different forms of premium for gas vis-i-vis other fuels. The firsttype comprises premiums linkec to the price of the fuel (i.e., mainly differences inefficiency plus possibly some taxes proportionate to the price). This difference' isexpressed by a different (usually higher) inclination of the market value line comparedto the equivalency line. In terms of a price formula, this would translate into an increaseof the coefficient representing the equivalency of value between gas and the competingfuel. The second type comprises differences in investment and operating costs (exceptfor fuel costs). These differences result in a parallel shift of the equivalency line. Thisshift will be constant for differences in operating costs, while it will be inverselyproportionate to the load factor for expenditures linked to capital expenditures. In termsof a price formula, this would be expressed by adding a constant (i.e., an elementindependent of the price of the competing fuel but not necessarily independent of the loadfactor).

6.113 However, it must be remembered that deliveries with a low load factor willnormalUy require a correspondingly high investment for load balancing on the part ofeither the producer or the buyer.

6.114 The consideration presented applies to a single customer. If this is a bulkcustomer with a large share in overall sales, it might be possible or even necessary toreflect that customer's situation specifically in the formula-for example, by introductionof a capacity charge element.

6.115 In case it is a whole market segment where gas is competing with another fuel itwould be necessary to look at the as -ige of the customers in that segment. Here, itmight also be necessary to make a distinction between customers with captive andnoncaptive investment. Furthermore, different qualities of competing fuels may play arole.

6.116 It must also be noted that this theoretical market replacement value is notnecessarily equal to the price realized in the market. It may not represent the amounta customer would be prepared to pay, or it might even be too high and thus result in aloss in sales volumes.


6.117 The next step in looking at the average market replacement value is to estimatethe shares of the various competing fuels with regard to the gas sale. When calculatingthe market replacement value back to the price at the delivery point (the netback price,Figure 7b), all costs incurred to bring the gas to the customer in the right quality,delivery structure, and so on have to be deducted. Theoretically, this could be done byallocating to each buyer or market segment of competing fuels the costs related to it.However, in most cases, this is a theoretical exercise, because it is difficult to distinguishwithin the overall cost the cost elements caused by specific segments because of possibleintegration and synergic effects. The load factors are also different, and peak demandwill not occur simultaneously.

6.118 Precisely determining a netback is difficult, and to give the end user someincentive as well providing an incentive between the pipeline and the producer, a gaspurchase price formula normally agreed between a pipeline and a producer will besomewhere in between the cost-plus and the netback scheme. A pure cost-plus scheme(Figure 7c) would not give the producer an incentive to enlarge the basis for production(i.e., drilling new wells), nor would the corresponding pure netback approach representan incentive to a trading and transport company to upgrade the gas grid and to undertakeadditional marketing efforts. One might therefore look for some solution in between thetwo approaches, sharing risks and chances. The approach adopted will also depend onwhere additional investment is most imminently needed to enlarge the overall system.

6.119 In a more mature market it seems appropriate that the trading and transportcompany gets a relatively small share of the risks and opportunities caused by oil pricemovements, whereas the producer gets the larger share of both. For the producer, theprice risk pattern is thus relatively similar to the price risk pattern an oil producer is usedto-namely, bearing the oil price risk but no quantity risk. A buyer can only take therisk of a minimum pay if he can be sure tht the gas can be marketed; therefore, he canonly take a limited price risk in relation to the price of ulhe competing energies.

6.120 Under a cost-plus system this may work if there is enough 'old" cheap gasleaving enough room to roll in higher-piiced gas and to even out possible losses fromhigher-priced gas. In a pure netback system, this would automatically be the case.However, with decreasing prices the point could be reached where the price to be paidat the delivery point is negative.

A Bais for Long-Term Gas Contracs, Pam BI 79

Gas Price

Market Value 8 Gas Price : Pipelines(Consumer) Consumer Cost

R ~~~~~~~~~i Producees

4

~~~~~~~~~~Price of competing fuel

/ - -- ------ - Gas Purchase Price Formuwl t ~~~~~~~(Net Backc Case)

Cost =Cost incl. Interest on Equity

FIGVRE 7b. Shaling of the Market Value: Nethak Case

80 Long-Tenm Gas Contracs

Gas Phce

I~~~~~~~~~~~~~~~~~

Gas PriceConsumer

Market Value /P;pefne ts(Consunet,:Cs

7~~~~~~~a Pudis erk F i-/ / I~~~~~~~Ca-st Pu ae

ICost - Cost incL Interest an Equfty

FIGURE 7c. Sharing of te Marke Value: Cost-plus Case

A Basisfor Long-Terin Gas Contracts, Pan I1 81

6.121 In reality, the price to the end user is likely to be less than the replacementmarket value to give an incentive to use gas instead of competing fuels. This may bedone in various forms, one of which would be a flat rebate per unit of energy to the endconsumer. This form risks giving a signal for inefficient use of the gas by undervaluingthe gas. Another system could be to give incentives to new customers by partlyfinancing their investment for the installation of gas appliances or by lowering thecapacity charge, if any. Then, the price per unit of gas could remain in line with thereplacement market value of the gas and thus give the right signals for an efficient useof the gas.

6.122 When a pipeline comp-iy acts as a buyer of gas and discusses the price it expectsto pay for gas 'at the delivery point," the pipeline will normally use as a reference in itsdiscussions with the gas producer-that is, the original seller of the gas-the price thegas will bring when it is resold to the end consumer and not to theoretical market-valueconsiderations.

6.123 A gas price formula somewhere between a netback and a cost-plus formula willthen define various areas where the producer or the pipeline is making a profit or a lossrespectively (cf. Figure 7d). Unless the line defined by the pricing formula goes throughthe point where the netback formula and the cost-plus formula intersect each other, zoneswill exist where one party is suffering while the other is still getting profits (cf. Figures7e and 7fl.

6.124 When looldng at a formula for gas related to the price of competing energies, anyformula is described by the gradient of the line and the level at which it intersects they-axis. A price formula can be written in various forms expressing the same relation (cf.Appendix). Table 13 lists some of the main technical elements of the pricing formula.

6.125 One of the main problems that is particularly difficult for developing countries isto find suitable indices to which the gas price can be pegged. This applies to inflationindices that may be suitable in a cost-plus formula. It applies to an even higher degreeto fuel oil prices, because in most developing countries fuel oil prices are subsidized orspecifically taxed in one way or the other or otherwise influenced by the government sothat they seldom reflect the market price. For many developing countries, it maytherefore be reasonable to peg the gas price to some inrnational fuel oil prices. Here,crude oil prices are more easily available than product prices. The argument againstcrude oil prices is that part of the crude oil barrel is also sold in the transportation sector,


Gas Pfrce

Consuner

Market VaIue Pcpeline's(Cons=mer)N Cs

/ / ~~~~~~~~~tc a of coMpetn fsi

Ga PUrdas Frie Formula

Cos Cost .cL Inherest on Equity

FIGURE 7d. Shring of the Mardt Value: Mxed Case (eween Nedack and Cos*-phu)

A Basis for Long-Tern Gas Contracs, Part 11 83

Gas Price

Gas Price/Consumer

Pipeline'sCost

Pipeline: AProf Zone I Loss Zone

Producer.~ P,-ofIt Zone Loss Zone

Cost =Cost ic!. Interest on Equity

FIGURE 7e. Shai ing of Good Thnes and Bad Thues Concdence of Pmjkl and Loss Zones

84 Long-Tenn Gas Contraas

Gas Price

Gas PriceConsumer

ieline's

Plipeline: EM Profit Zone 8l Loss ZoneProducer: E Profit Zone MLoss Zone

Cost =Cost ~inc. Interest -n Equty

FIGURE 7f. Sharing of Good Thaw and Bad ThUs: haequl*y of Profit and Loss zonas


TABLE 13. Main Elemens of Pring

o Price per energy/per volume

e lPricing system- Average price vs. capacity and demand charge- Price zones (as a function of offtakes).

* Price formula

a. Market-related elements- Indices to reflect replacement value of competing energy- Shares of competing energies- Thermal equivalence factors (GCV vs. NCV)- Factors to share changes in mirket value.

b. Cost-related elements- Indices to reflect development of costs- Shares of cost elements.

C. ISme-related elements- Reference-periods- Time lags- Dates of recalculation.

a Extras to the price formula- Bottom/ceiling minimum-/maximum conditions- Different formulas for different price ranges.

o Terms of payment (due date)

o Currency

e Taxes (on competing fuels / on gas)

e Price revision


which is no competitor to gas. Furthermore, crude oil prices are influenced byfluctuating refinery margins. It may be better, however, to accept these distortions of theindex than to bear no relation to any market whatsoever. The same holds true for coalprices. For coal there is only a relatively small world market. Reliable price quotationsfor coal are not easily available. One suitable idea might be to use import statistics ofthe country concerned because they reflect the market value in the country and are alsolinked to some real trade.

6.126 Other aspects linked to indices axe the time lag (i.e., the difference between themonths the index refers to and the month of delivery for which it is entered into the priceformula); the reference period (the perod over which the indices are used); and thefrequency of adjustment (every month, every three or six months, or every year).

6.127 For a cost-plus formula linked to some inflation indices, long-time lags andreference periods favor the buyer, because inflation is almost always positive. When thegas price is pegged to oil product prices, long-time lags and reference periods providefor a certain stability but also bring the risk of substantial distortions if there are heavyprice movements.

6.128 Various possibilities are available for mixing price formulas, such as minimumand maximum conditions, defining different price formulas for different price ranges, andapplying minimum-maximum conditions to the formula in total or only to some elements.

6.129 A price formula that is the maximum, for example, of a netback formula and acost-plus formula would mean that the producer's costs are recovered in any case andthat he will possibly get extra revenue out of the market. Such an arrangement wouldleave the buyer only with risks and without any possible reward. A price formula thatis a minimum or a maximum of the two basic approaches will tend toward pronouncedimbalance.

6.130 For a single component, a maximum condition referring to the maximum valueof two alternative fuels would possibly reflect the bivalency of the customers to whomthe gas is sold and who might be able to choose between two fuels, such as coal and fueloil, at short notice.

6.131 Providing different price formulas for different price ranges could adequatelyreflect different segments of the market that may be lost at certain absolute price levels.Different quantity reactions at different price levels also have an impact on the loadfactor and, through this, on average costs.

A BaLs, for Long-Teim Gas Contracts, Pan ri 87

6.132 Terms of payment are linked to price because of the interest involved, so that thetime span between two due dates could easily be translated into a price differential.Inflation might be an extra issue, as well.

6.133 If a minimum pay is agreed, a payment of one twelfth of the annual minimum payper month might be agreed as prepayment even before the month of delivery.

6.134 Making the payment in the currency of the market in vwhich the gas is sold isconsonant with market-oriented pricing principles. Paying in local currency should notbe a problem as long as the currency of the country is freely convertible and transferable.The main difficulty would be inflation. In theory, at least, the exchange rate should bereflected in the fuel oil prices in local currency. As long as the price of gas is linked toa local fuel oil price set by a market and reflecting developments on the international oilmarket via the exchange rate, there should only be a limited inflation risk for the sellerlinked to the period between the time to which the oil index refers and the due date.

6.135 If the local currency is not freely convertible, a seller-at least for the partreflecting his costs-would insist on payment in an internationally accepted currency.

6.136 A list of points to be observed in the pricing provisions can be found in Table 13.

6.137 The total price formula may be checked every few years by a price review. Themain elements to be looked at are listed in Table 14.

6.138 Normally, it is only the price that may be reviewed, not the other conditions. Forthe other conditions one might argue that the investment in capacity has already beenmade so that no great changes are possible. On the other hand, a review of the marketand -ts influence on pricing may be done more easily, and the result will be just anadjustment between the sharing of the revenue from the market. An important aspect ina price reopener is that the point at which discussions are started and the yardstickrequired to acnieve a result are quite clear. Furthermore, a final settlement must bepossible, even if the parties are unable to agree with each other on a solution.

6.139 One of the most difficult questions linked to the price is how to treat taxes. Onephilosophy could be that each partner takes care of the taxes in his sphere. It might alsobe necessary to deal with taxes on the competing fuel or fuels because if these taxes arefully passed on to the fuel consumer, this will increase the netback value of the gasaccordingly. Conversely, a tax on gas usage or transportation may be regarded as anadditional cost element on the buyer's side.

88 ,Long-Term Gas Contrads

TABLE 14. Elements of a Pce Reopener

* Who Is entitled?Each side applying the same rulesEach side is entitled but applying different rulesOnly one siF1e is entitded.

* E%xamples of when a party Is entitled (trigger):Substantial changes in economic circumstancesAutomatic right as soon as a defined parameter (e.g., price) has changedby more tha. xAutomatic right after the elapse of y years.

* Examples of how often:Every x years (e.g., every 3 to 5 years)Extra free triggering right during the term of the contractNo defined frequency, but as often as the conditions linked to parameterchanges) are fulfilled.

* What guidelines are possible for finding a new solution?- Stop suffer Oosses) on the deal or as company (account for past glory?)- (Re)establish (new) balance between the pardes- Ensure marketability- Ensure profitability of investment of one part (netback, cost plus).

* What solutions are avaflable it parties cannot agree?- Expert procedure- Arbitration procedure- Court- Stop the contract.

A Basis for Long-Tenn Gas Contracts, Part I1 89

6.140 Infoimation. The flow of information is particularly important when the otherparty has to share risks or the consequence of some events. The main areas in whichinformation is needed to evaluate risks are, in the construction phase, to report on theprogress of the other side; in the production phase, in the case of a depletion-typecontract, to judge the risks linked to the reservoir by the buyer; and on any matter thatwill affect avalability, stemming from force majeure or not. Specific information rightsshould be applied with regard to shortfalls to judge whether they are cases of forcemajeure or not.

6.141 The general principle is that information should be timely and complete.Information will be treated with some confidentiality; however, exceptions to theconfidentiality rule may have to be addressed. With regard to specific informationrights, some details may be listed in advance to avoid later discussions. To the extentthat confidential information is dealt with, mainly in connection with the reservoir, theremay be third parties to look into confidential information. For a reservoir, this may bea consultant. For commercial questions, it may be an auditor.

6.142 Technkal es. The means of communication must be clarified as well as thecorrect addresses, and so on. Technicalities have to be clarified regarding invoicing,currency, due date of payment, and preservation of files, as well.

7. WHAT IS DIFFERENT FOR GAS-TO-POWER PLANTS?

7.1 The aspects of gas contracts dealt with so far mainly concern prospective dealsbetween a gas producer and a pipeline (a company trading and transporting gas). Yeta company operating one or several gas-fired power plants may have a demand for gasthat may easily reach the same order of magnitude as a deal between a pipeline and aproducer. Hence, specific attention to the unique features of contracts for gas-to-powerplants is warnanted.

Basic Features of Gas-to-Power Plants

7.2 A power company has two options for obtaining gas; it may conclude a direct dealwith a producer, or it may of course deal with a pipeline company. Obviously, a powercompany is in a different situation vis-a-vis a gas producer than is a gas pipelinecompany because in the planning stage at least the power producer almost always hasalternatives to gas, such as coal- or oil-fired condensing plants or hydropower.

7.3 Once a decision to use gas has been made, however, the question of optimizinggas utilization compared with other fuels is a permanent one, especially if there areseveral jower plants, some of which are not based on gas and are interlinked by a grid.Even if power based on gas has the lowest long-term marginal costs-because of thespecifically low investment of capacity of combined cycle geneating-the short-termmarginal costs of gas in a given combination of power plants must not necessarily be thelowest in every constellation of arrangements. The answer to that question very muchdepends on the shape of the load distribution curve. A minimum pay is in any case avery severe restiction on the opimization potential of a power plant system.

7.4 Because electricity is very often treated as a service supplied to customers at cost,power companies are more often technically oriented than commercially oriented.

7.5 Very often, a power company has as large a shareholders' capital as agas-producing company. Specific investment in a gas-fired power plant is as high as oreven higher than the specific investment in gas supply capacity. The specific savings ininvestment in a combined cycle compared with a coal-fired power plant easily reachesthe specific investment and even the size necessary for gas production and supplyfacilities. The size of the investment would therefore not in itself be a hindrance for apower company to go upstream into the gas business.

91


7.6 There is a direct physical link to the electricity consumer via the gas power plant.Any interruption of gas supply to the power plant could result in a blackout, causingsubstantial damage or loss of income to the electricity customer. Reliability of supply istherefore of high importance unless there are short-term switching possibilities ',or thepower plant to resort to some other back-up power plants (e.g., hydro or fuel-switchingpossibilities).

7.7 The offtake of gas in other sectors is more or less a linear function of the targetedoutput (e.g., space heating, use of gas in small industry). ras for power, however, issubject to a permanent optimization process.

7.8 The short-term marginal costs of producing an extra kdlowatt hour are mainlydetermined by the costs of fuel. The profitability of the business of an operator usinggas in a power plant is, in the short run, heavily dependent on the fuel costs comparedwith a normal industrial gas user, for whom the cost of gas has only a limited influenceon the profitability of its business. For end users, where gas competes with fuel oil, thecost difference linked to the different appliances associated with gas or oil utilization issmall compared with the fuel costs as such. Even where demand for gas is not subjectto large seasonal influences, a seasonal pattern for gas demand may result from its usefor power generation. This is especially the case if hydro has a large share in powergeneration because of its dependency from seasonal factors such as rainfall, glacier melts,and irrigation needs.

7.9 In earlier times (during the 1970s) gas for power was gas used in gas-to-steamurbines with only a slight advantage in efficiency and some saving, since nodesulfrizaton was needed, and the premium between low-sulfur heavy fuel oil andhigh-sulfur heavy fuel oil could be captured. In tlis setting, moreover, power plantscould easily switch back to fuel oil. That is not the case, however, for the present-dayuse of gas in a combined cycle.

7.10 Today, investment in combined cycles is most typical for grass-root power plants.This is a captive investment, because it is linked to gas turbine technology and therebylinked to very clean (and possibly with the exception of gas) expensive fuels. In otherwords, because of its quality, gas is competing with investment goods. If later on (butstill long ahead of full depreciation of the combined cycle) no more gas is available, thepower plant opertor will regret not having chosen coal.

7.11 The following aspects play a role when considering investment in a gas-firedpower plant. It is much cheaper to bring the gas to the power plant (the place where the

lWat Is Dbseremfor Gas-to-Power Plat? 93

power is needed) than it is to bring the power plant to the source of the gas. The reasonis the much higher specific investment in the transportation of energy in the form ofelectncity compared to gas, even taldng thermal efficiency into account. Furthermore,transmission losses are much higher for high-voltage cables than are transportation lossesfor largedmeter pipelines. Another neat effect of a gas pipeline is the buffer it offersto cope with daily peak demand (the buffer being a function of the length, the square ofthe pipe diameter, and the pressure drop in the pipeline). From the oveall economicpoint of view of a country any least-cost expansion considerations for the constructionof new power capacity should include the costs of constructing and operating the part ofthe gas system allocated to power generation, in cases whare gas-based power isconsidered an alternative.

Contractual Consequences

7.12 In the following, the items of Tables 6-9 are discussed with regard to the specificfeaues offered by gas-to power activities.

Wo are the Pa,1ners to the Contract?

7.13 Very often, the power company is entirely state-owned. Such companies areoften run well in operational and technical terms but have a certain lack of commercialtfinling. As electricity is often treated as a service, a cost-plus philosophy iswidespread; it might thus be more important to convince an authority of the need for aprice increase than to convince the customer. Where there are changing srcues in theelectricity sector in a country it might also be essential for the gas suppliers to have someclear guarantees as to who will be the partner in the future.

Rides for Handling the Contrct

7.14 Because of the heavy specific investment, which is specifically as large as theinvestment upstream in the gas chain, and because of the captive character of thisinvestment, the power plant will have every interest in long-term stability (i.e., inavoiding any shortening of the term or reduction of the delivery capacity originallyagreed as long as the price for the minimum-pay quantity is reasonable in relation to theprice of competing sources of fuels and the returns on the generated electricity). On theother Fend, if the gas-to-power plant is definitely incapacitated, then the gas supply is ofno use to the plant operator. Because of the large offtake linked to the single device, thefate of the contract may also be in the balance.


7.15 Construction of a new power plant will depend on many permissions and permits.It is unreasonable to trigger a large investment upstream and a corresponding minimumpay obligation before it is clear that all essential permits have been obtained. In additionto the usual conditions concerning approvals by the supervisory bodies and possibly thegovemments, a long list of conditions precedent linked to various permissions for theconstruction of the power plant may have to be included.

Commenial Elements of the Deal

7.16 Delineaion of Spheres. This is a key element of the deal. Because pnrcing ofgas-to-power pants may end up with a two-part tariff with a relatively low commoditycharge (e.g., linked to coal prices), the seller of the gas will be concerned to ensure thatthe price level of gas-to-power plants is not used to destroy the level of prices linked tofuel oil in the rest of his market. The seller might wish to earmark the gas for use in thepower plant. It is not unusual for a power plant operator to run several gas-fired plantsat several locations. Instead of concluding a deal for each locatior,, he might concludea comprehensive deal and define switching possibilities between delivery points. Thismay involve certain restrictions on using maximum capacity at all points simultaneouslyas well as some rules on adding up offtkes for the fulfillment of an overall minimumpay.

7.17 Project Investment. A heavy investment is involved on both sides; the investmentfor the gas consumer is often specifically larger than for gas supplier. The investment inthe power plant requires long lead times for its realization. Careful coordination ofinvestment schedules is, therefore, necessary. Mutual communication on the progressof work up to site inspections should be agreed.

7.18 Profile. The profile of the offtakes over the operating life of a power plant isnormally straightforward. After a short run-in period, the capacity needed will beconstant over the years. The duration may be between 15 and 25 years. There areschemes, however, where the minimum pay is lowered after several years to reflect theeconomic aging of the plant, by which it would typically change its rating from base-loadto middle-load or even peak-load.

7.19 Quanty-related Aspects. Long-term security of supply is a must for the powerplant to justify the choice for gas vis-a-vis a coal-fired power plant, at least if gas isneeded for a combined cycle and not for use in some dual-fuel condensing power plant.The buyer should ask for a portfolio of supply sources securing deliveries for a time span

Wla Is DJfemfor Oa-to-Power Plants? 95

that is long enough to pay out the investment in the combined cycle. When there is alink to the reserve risks of one specific reservoir, the power plant operator should makesure that he has a first-priority access to the reserves and that, even under veryconservative estimates, the reserves will be sufficient to guarantee the commercialviability of his investment. Short-term interruptions seem to be technicalyunproblematic; back-up fuels (e.g., gasoil) are available at relatively low storage costs,although they do cause high operating costs.

7.20 Rebates for defaulting on delivery obligations or just a penalty for nondeliverymay be as high as the gas price itself or even higher, if the yardstick is the cost of thereplacement fuel (i.e., gasoil or LPG). Conversely, the gas supplier is also dependent onreliable payment for a minimum quantity because of the large offtake volumes. Even tothe extent that offtake is covered by the minimum pay, the supplier is stiLl dependent onthe creditworthiness of the buyer. However, as force majeure events normally reducethe muinimum pay quantity of the buyer, the commercial situation of the seller alsodepends on force majeure situations not happening too often and not lasting for too long.

7.21 Force majeure by a power plant is dfflicult to define, because there will alwaysbe minor interruptions in the operation of a power plant. The frequency of disturbancesin a power plant depends on the quality of the maintenance, duration of staff training,and availability of spare parts. For a power plant, the fulfillment of a minimum payquantity may not be so much a function of commercial or overall economic parametersas it is a reflection of the plant's availability.

7.22 To avoid lengthy discussions over whether force majeure caused each and everyinterruption, it might be better to allow for a relatively low minimum pay but to restrictthe reduction of minimum pay caused by force majeure instead. It might be agreed, forexample, not to reduce the minimum pay quantities in the event of short-term forcemajeure. The reasoning would be that it is foreseeable that a certain number of suchcases will happen and that this is already reflected in the low minimum-pay quantity. Onthe other hand, gas may be used in a dual-fuel power plant to replace heavy fuel oil. Intatat case there is no captive investment, and gas may be used on an interruptible basis(priced by heavy fuel oil or even less to pay off the dual-firing capacity). Then it will benecessary to define the rules of interruptibility. Such rules may be linked to climaticparameters (e.g., shut-down right if temperatures drop below the freezing point or certainannouncement periods to allow for safe fuel-switching operation). Some limits also maybe placed on the total duration of interruption. The case of a dual-fuel power plantwould also very well suit the case of a gas-as-produced contract.

96 Long-Tenn Gas Cotrads

7.23 Corrections accounting for climatic influences might be linked to the impact ofhydropower production. Thus, a minimum pay could be modified by some indicator forthe incidence of rain, and so on.

7.24 Regular maintenance is mandatory for a power plant, and the reliability of theplant depends on thorough maintenance at frequent intervals. The contract should provLlefor this, unless the flexibility is large en ugh anyway and there is no daily minimum pay.Otherwise a mechanism for determining and coordinating of maintenance should beincluded in the contract.

7.25 Many countries that do not experience a large seasonal swing in power demanddo have distinct peaks during the daily load curve. In such cases, the power operatormight use some peak gas turbines, for which a peak gas snpply will be needed. Theoperator might ask for peak capacity for some hours every day, which could perhaps besupplied from the line pack.

7.26 In any case, the gas offtake volume that is commercial for a power plant is afunction of the relative costs to produce a Idlowatt hour. This volume is dependent onthe part of the load distribution curve served that, because of marginal cost ranking, ismost economically served by power based on gas. A minimum-pay contract with apower plant should grant a price that makes the marginal costs of gas-based electicitycheaper than the marginal costs of alternative fuels for some duration during the year,corresponding to the minimum-pay level.

7.27 Quality-reled Aspecs. In the case of a combined cycle or a gas turbine theadvantage of using gas is based on the clean combustion properties of the fuel. Its verylow acid content and almost total lack of heavy metals such as vanadium make gas suitedfor use in gas turbines with high inlet temperatures (and thus high efficiencies).Deviations from the quality specifications defined for such turbines bring the risk ofserious damage-such as destruction of the blades. Specific attention must therefore begiven to defining, monitoring, and controlling such quality specifications. For dual-fuelboilers, quality restrictions will be of less importance. On the contary, these deliveriesmay even be used to dispose of offspec gas and to manage the quality in the gas grid.

Wa is Dferemntfor Gs-lo-tPower Planks? 97

Pricing

Gas PMicing Based on Cost-plus Considerdons

7.28 Determining a cost-plus price for gas-to-power plants is in general based on thesame criteria as for other gas deals. For the power plant owner, a cost-plus andminimum-pay scheme would be commercially similar to investing himself in the gassystem. The difference would be that for the gas part the investment risks (operatingrisks, but also risks linked to reserves) would be borne by the gas supplier and not thepower plant.

7.29 On a cost-plus basis it is easy to calculate the advantage of gas-to-power plantscompared with coal-fired power plants. The short-term marginal cost comparison withcoal will show a rather stable differential, whereas a comparison with fuel oil may showa fluctuating pattern. The power plant will only opt for gas if there is a rent that is inthe case considered completely acquired by the power plant.

Gas Pdcing based on Netback Consideraions

7.30 For pricing based on netback, the considerations for a power plant are moresophisticated than those for the general market for gas because the customer is using gasfor production, not ttading. In addition, a large share of the investment is inked to thechoice of gas as fuel, and much of the operating cost is determined by the fuel costs.There also may be su'bstantial differences between the ranldng of gas compared withalternative fuels based on the longterm margial costs as compared with the short-ternmarginal costs of using gas. Finally, gas prices may have a substantial effect on theprofitability of the business of the company.

7.31 When pricing is based on the point in time bfore the investment decision for gasis taken, the maximum price is determined so that the kdlowatt hours produced by useof gas in a combined cycle costs as much as the production of one lilowatt hour basedon an alteave fuel. This has to take into account the investment for power generationcapacity as well as other annually fixed costs over the economic lifetime of the powerplant, which may be shortened if gas is no longer available (see Figures 8a, b, and c).It must be clear that reserves are sufficient to justify the long-term investment in the(captive) combined cycle; otherwise, the price must be determin-W so that the captive partof the investment will be recovered before resves are exhausted.

98 Long.Tem Gas Contracts

Investrnent

$A(W;

2000

1500-

1000. ee-

3000 200 40

Annuity800'

$/kW/a| other Annual Costs

;.~~~~00 0 tf -. _.

400o- i--*e-* nvest$ment e.g

200 *_.* Other Annual Costs200Q - -------*** **4**

lrnvestment

04 200 400 600

- o- Coal SteaM

Figures are only Indicative . Gas CC

FIGURE 8a. Ndback Gas CC veus CoUlStea hlesbwt and A

MwafI D&verentfor Gas-to-Power Plws? 99

cSt/kWh,,20,18j

14- _ .

12 ~ ~~~~+OPEX'*'

10\ Annuity'\

8-

Load FactorO 0.2 0.4 0.6 0.8 1.0

cts/kWh1 Cts/kW 20- 11

18 1016 914\ Netback/kWh 812 for Gas CC

vs. Coal Steam 610d8.

4. 2

2 Costs of Fuel 1

0 0.2 0.4 0.6 0.8 1.0Figures are only indicafive

Assuming a thermal efficieny of a Gas Combined Cycle of 50% COW CoI StsamWithout Cost of Fuie - GasCC

FIG C/A 8b. Ndbac Gas CC vensw Coal/Sew CeAn* per kWh

I00 Long-Tenn Gas Contracs

cts/JkWh.1

20

18-

i2. ~4 OPEX12AAnnuitn\Y

8 N

4

.1og - . - . - . 7 -- a Load Factor0 0.2 0.4 0.6 0.8 1.0

CtS/kWh,l cskWh*GC CaS20. 11

*10

16 *9

NetbacWkWh 812 for Gas CC 7

vs. Coal Steam 6

8 4

Gasoil in CC 3HFO' ; _

Costs of Fuel i d

.0 0.2 0.4 0.6 0.8 1.0

Figures are only indicative*Assu=ing a thenal efficiany of a Gas Combined Cycle of 50% .- CoalJSteam

weUsed in Spare Capacty - Gas CC

FIGURE 8c. Netck Gas CC vrwers CoaLStew Ceti per kWh w4th Gasol wad PFO

Wa Is D(fferent for Gas4o-Power Plants? 101

7.32 The difference in annually fixed costs may be addressed by the following: an up-front lump-sum payment; a two-part tariff system; the rolling in of the annually fixedcosts into an average price, by dividing by the volume of gas used in the year concerned;or a long-term average load factor consideration, possibly using discounted cash flowmethods, assuming that the deviations will balance out over the years. A scheme for thenetback pricing approach for gas in power generation compared with other fuels basedon the point in time before the investment decision is taken is shown in Table 15.

7.33 When pricing is based on the point in time when the gas is taken, gas-to-powerproduction should not be more expensive than available alternatives. This applies eitheron a bivalent basis for possible substitutes of gas (normally gasoil) or by use ofalternative fuels (typically HFO) in another power plant that has spare capacity and isalso linked to the power grid (cf. figure 8c). The marginal costs to produce a kilowatthour based on an alternative fuel would limit the price acceptable to a power plant, themain element being the price of the alternative fuel multiplied by the ratio of thermalefficiency.

7.34 When pricing is based on the available alternatives to change the fuel input intothe power generation system, building of new power capacity can result in a new rankingfor the combined cycle in the load curve (e.g., the middle range or peak lead). Additionof coal gasification in front of the CC might be combined. However, that technology ispresently at the pilot project stage, so use would not only entail additional investment butalso some loss of efficiency. Pricing of gas to power also can be based on a netbackcalculation from the income from selling the electricity produced on the basis of gas.

Conclusions on Pncing

7.35 To avoid any disadvantage for the power plant operator from the use of gas, thegas price should not exceed any of the following lines:

* Equivalent long-term costs of a coal-fired (or fuel-fired) power plant-that is, gasprice = equivalent of coal price x ratio of efficiency (CC/coal-fired powerplant) plus the cost differential in OPEX and CAPEX per kWh divided by thethernial efficiency.

a Costs to use short-term altemative fuel in the combined cycle (i.e., mainly gasoil)or the costs of other fuel to be used in spare capacity-if available-multipliedby the ratio of thermal efficiency.

102 Long-Term Gas Contrais

TABIS 15. Schemefor Netback Ping Approach for Gas to Power

GAS Gas GasType of power plant/fUel Coal HFO Steam Turbine CC

Other usable fuels HPO, Gas, Gas, Gasoil Gasoil Gasoil GasoilGasoil

Height of Boiler (m) 60 60 30*De SOx 120 yes no -

Cost Category

Investment ($/kW) 1.500 1.200 1.000 6-800 800700 400 200 -

1. Netback vs. CC (S/kW)

Annually fixed oosts- Annuity/linked to - fixed percentage

interest rate of inesent -

- crew linked to wages high medium medium ow low-med.- Maintenance, other costs high medium medium low low-med.

lind to investment __

Sums of annually fixed costs (in $IkW/yr) by adding up, linked to interest rate, wages, investment

2. Nedbc vs. CC calculated as difference to last column (in $/kW/yr)

Netback vs. CC calculated as difference to last column/but divide by actual load factor in% x 8.760 h to obtain the annually fixed cost per kWh

OPEX without fuelAshes yes no no -

Blaster/CaCo3 yes yes no -

I Water yes yes ya- low

Sum (cts/kWh) including or excluding average of fixed costs

3. Netback for OPEX part = Diffe:zmncm from last colwm (ci. or excl. fixed costs) in cts/Wh

FUEL used Imp. Coal (LS)HFO Gas (Oil) Gas (Oil) Gas (Oil)Prices in US cts/kWh NCV 0.5 0.7 (1.5) (1.5) X

Efficiency .33-.38 .34-.39 .35-.40 .25-.33 45-.50+ future + future

(in kWh el/kWh th) potential poteti

Fuel costs (cts/kWh,,) 1.5 2.0 (3.8) (4.5)0.5/0.33 0.5

4. Netback gas price, ondy fuel part = equate with last column and solve for X, multiply result by GCV/NCV for (as

5. Total Netback Gas: Netback for OPEX including average of fixed coss divided by CC effidency, multiplid byGCV/NCV for Gas plus Netback Gas, fuel part

* Steam Part; ** efficiency of 0.50 assumed; HFO: Heavy Fuel Oil, CC: Combined Cycle.

What Is Dfferen for Gas-to-Power Plants? 103

o Coal equivalent x ratio of efficiency (CC/CGCC) + amortization of theinvestment in coal gasification plant over the remaining lifetime of the CC/kWh.(Coal gasification is supposed to be state of the art.)

* Netback of earnings from selling the additional electricity generated by using gas.

7.36 In addition, regarding currency, because the power plant operator might have tobuy fuel oil or coal in large quantities on the international market, it would not seemunreasonable to ask for a payment in U.S. dollars.

104 Long-Term Gas CoUtra _.

8. WHAT IS DIFFERENT FOR GAS CONTRACTS WIT ILTIES?

8.1 This chapter attempts to define and analyze the typical features of utilities and todescribe the interaction between a utility and a pipeline. The issues listed in the tableswill then be examined with regard to elements that must be addressed specifically by apipeline and a utility in a gas sales contract.

Specific Features of Utilies

8.2 Typically, a utility is obliged to deliver gas to all applicants within a certain areaat defined tariffs. In industrialized northern countries, where gas is widely used forheating, the obligation will extend to supplying nouseholds and other small end users,whose average demand will be on the order of some tonnes of fuel oil equivalent.Because the low-pressure pipeline grid in cities tends to correspond to the street grid, itstotal length will approximate that of the streets.

8.3 However, where gas is not used for heating-or air conditioning, which so far isan atypical application-the average consumption per household drops to less than 10percent (i.e., some 100 kg of fuel oil equivalent). In almost every case, then, becauseof the very large investment in the grid and in metering and regulating facilities, it istotaUlly uneconomic to use gas in households that do not require it for heating or cooling.Accordingly, in such regions, the utility would not be obliged to supply smal end usersand would only run a grid of a comparatively short length, mainly sering industrial andcommercial customers.

8.4 A major distinction among utilities would then be whether they supply gas forheating or not. The following charcteristics usualy apply to those that do: They supplyto households, have an obligation to supply all applicants, run a large low-pressure grid,invest heavily in this grid, invest heavily per end user, must meet seasonal variations indemand, and have limited control-because of the general supply obligation-over thedevelopment of demand.

8.5 In contrast, utilities that do not supply gas for headng purposes supply mainly tocommercial and small and medium industial customers whose use would be on the orderof 100 tons of fuel oil equivalent per year or more. In addition, instd of a low-pressure distribution grid, they maintain a medium-pressure infructure, such as a ring-or star-shaped grid, with branches to industrial or commercial areas, providing

105

106 Long-Tem Gas Conracs

low-pressure distribution only in exceptional cases not stemming from a generalobligation. Finally, utilities that do not supply gas for heating enjoy relative freedomfrom load variations resulting from seasonal factors-except for holiday periods-butinstead observe cycles on the order of a day or a week, and they require less investment.

8.6 Most countries will have at most one utility per city, although some large citiesmay be serviced by a number of utilities. A pipeline company may contract with manyutilities and will therefore try to use standardized contracts. A utility will ordinarily haveonly one pipeline company as a supplier. This does not apply in the case of open accessto the main pipeline, where utilities would be free to have direct access to severalsuppliers. For utlities of limited size, the question arises as to whether it is in a positionto supply gas to large end users such as power plants or whether those end users arebetter supplied by the pipeline company that supplies gas to the utility.

8.7 Utilites are subject to a number of difficulties. First, they are vulnerable to localeconomic and political influences. Tariff formulation, for example, may be heavilyinfluenced by local governments or parliaments and politicians. Second, whereas theyhave high captive investment in the utility grid, their customers do not necessarily haveany captive investment. The profitability of the customer's business would not beimpaired in most cases by switching from gas to another fuel. Finally, the expansion ofa utility's sales depends on the local economy and on regional politics as well as on themarketing efforts of the utility. Contrary to the case of gas-to-power plants, for example,utlities therefore do not necessarily face a stable demand or a defined peak capacity overtime.

8.8 A utility will tend to have many standardized customers. However, unlike in morenorthern climates, it is not a foregone conclusion that the utility will supply gas tohouseholds in most developing countries. Because of the lack of demand for heatingpurposes, the average volume may be so small that the installation of a metering facilitydoes not pay, not to speak of the specifically high investment in the grid.

8.9 Whatever the characteristics and handicaps individual utilities may face, thecrucial questions that have to be addressed in a contract between a pipeline and a utilityare as follows: First, how can the utility adapt to changes in the market? Second, howcan the utility cover peak demand-by its own instruments or as a service by thepipeline? Third, to what extent will risks (reserve and operational) be passed on to theutility? Should provisions for exclusivity be included?

UWuu Is Dfferentfor Gas Contracts with UtilitMes? 107

Specific Issues in Contracts between Utilities and a Pipeline

8.10 In the following, the issues discussed in Tables 6-9 are discussed with regard tothe specific issues linked to gas contracts with utilities.

Who Are the Palners?

8.11 The utility is often owned by a municipality, and thereby it is subject to politicalinfluences from that entity (see Table 6, in chapter 5). The economic freedom of theutility may be rather limited, especially if the utility is selling gas at set tariffs. Thepipeline, on the other hand, is usually not a producer. Therefore, utility may not dependon a specific field risk but rather may be linked to a portfolio of risks. In addition, thepip,line may have some storage facility available as backup. If the pipeline is not theonly possible supplier, then the contract will in any case have to clearly define thequantity frame and address the specific split of chances and risks between varioussuppliers. If the pipeline is the only supplier to the utility, then the question for theutility is how to make sure that supplies under the contract are achlly in line with itsneeds. For the pipeline, on the other hand, the may be an interest in standardizedcontracts, especally if it supplies gas to many utilities.

How Shoud the Contmcd Be Handled?

8.12 One specific element might be the comparison with similar contracts concludedbetween the pipeline and other uilities (see Table 7, in chapter 5). Another point is thenecessary stability of the contract stemming from the large captive investment, especilyin the case of the general supply obligation by the utility.

Wqa Are the Commerlai Elements of the Deal?

8.13 The main elements (summarized in Table 8, in chapter 6) are detailed below.

8.14 Delneation of Spheres. Under the delineation of spheres, it wil be importantto clearly define the geographic area in which the utility will supply gas to customers aswell as to define the maximum specific consumption the utility itself will direct towardend users and the amount that the pipeline will supply to the end users (as when supply


to power plants is too large to be dealt with by a utility and is therefore left to apipeline). The pressure level of the supply pipeline may also be taken as a criterion.

8.15 Investment Obligations. On the pipeline's side, investment obligations mayinclude several independent inlet points to the utility's grid and an obligation to provideincreased capacity over time in line with the development of the utility's market. On theutility's side, once the infrastructure to provide the main consumption area has been laid,further investment stems from the development of sales to customers, especially whenthe utility is obliged by law or regulation to supply all customers in its area.

8.16 Quantty Commitments. In a general supply obligation, a deal between a pipelineand a utility will most likely deal not only with annual quantities but also with daily orhourly capacity. Two extreme types of contract may be considered:

Nomml minimum-pay contract. A normal minimum pay contract similar to thecontract between a pipeline and a producer may apply in the case of utilities thatdo not need load balancing, have their own means of load balancing, or haveother suppliers. This type might be suited to a situation without general supplyobligation. The flexibility of the utility would then be given by the sadbetween minimum pay and maximum availability, possibly with some buildupperiod of the contractual quantities to adapt to for market developments.

Supplies needed within a dfined capacity without minunwn pay. In an extremecase, no restriction might apply with regard to capacity, provided that the actualpeak capacity will have to be paid by the capacity charge. In that case, there willbe a two-part tariff with a capacity charge and a commodity charge. The capacityfor which a charge has to be paid may be defined by the contract. Or, if no fixedcapacity is agreed in the contact, the peak capacity or some other figure that isrepresentative of the share in the capacity of the pipeline used by the utility willhave to be paid (e.g., peak on a daily or weekly basis or an average of severalpeaks). The pipeline has a buffer, and peak utilization by the various customersdoes not occur simultaneously. Such a contract would be best suited to thesituation of the geneial supply obligation of the utility. In tat case, the risk ofdevelopment of demand is taken by the pipeline. As a counterbalance, the pipelinewill ask for exclusive rights to supply the utility. The main provisions linked tominimum pay would not apply.

What Is Djeff for Gas Contrads with UhilIla? 109

8.17 Sharng of Risks. Passing on of the specific reservoir risks by the pipeline to theutility is also possible. However, the commercial viability of the captive investment ofthe utility should be on the safe side with regard to reservoir risks; otherwise, setting uplocal distribution should be thoroughly reconsidered. It must be kept in mind that by farthe most expensive part of the whole gas chain is the last few feet to the small end users.

8.18 Force majeure linked to the sources of supply is possible, but it is unattractive tothe utility; a risk portfolio may be a better alternative. Service by a pipeline may includeka backup, because cutoffs of noninterruptible supplies could damage the image of gas.

8.19 Incentive Scheme. An incentive scheme is already dealt with implicitly by atwo-part tatiff, consisting of a capacity charge and a commodity charge. Some moresophisticated incentive schemes are possible, such as rebates on capacity charge duringmonths or weekends with a low load or rebates on the quantities of gas depending onspecific time periods or after a certain threshold quantity has bee,n taken.

8.20 Force majeure on the utility's side is mostly restricted to technical events. A weakdevelopment of the market is not force majeure. It might nevertheless be considered asa reason for reducing the minimum pay or for reducing the capacity ordered.

8.21 Qualiy. Because metering at the user's end is based only on volumes, with noindividual metering of GCV, uniformity of GCV is necessary for reliable metering.

8.22 Prcing. Normally, there is a two-part tariff. The capacity charge will reflectsome costs of capacity and will be pegged to cost or inflaton indices. The commoditycharge between a utility and a pipeline normally will be derived from the end-user priceof competing fuel oils. The currency paid will normally be local currency because thatis what is invoiced to the final customer.

8.23 Infoimation. Some information should be given by the utility to the pipeline withregard to market development, especially regarding peak supplies witiin a definedcapacity when no minimum pay applies.

Relations Outside the Deal

8.24 Two specific points between utilities and a pipeline may be addressed. The firstis the obligation for the pipeline to make an offer to cover additional demand by theutility. The second is equal treatment (best treatment) compared with other comparableutilities.

110 Long-Term Gas Contrats

9. GAS IN DEVELOPING COUNTRIES

9.1 The first section of ftils chapter discusses some elements that appear to apply toa large number of developing countries. It should be noted that some of these elementsmay not be found in a given country and that some elements characteristic of thesituation of a specific county are not mentioned here at all. The second section attemptsto draw some conclusions for a gas-oriented policy as well as for the content of gascontracts in developing countries.

What Is Different for Developing Countries?

Location

9.2 Generally spealdng, most developing countries are located within the beltdescribed by the 30th parallels, North and South, whereas most industrialized countriesare in the northern hemisphere. The geographic location is of course independent of thestatus of development of a country, and gas issues related to geography and climate mustalso be addressed in countries with developed gas industres if they are in tropical orsubtropical areas.

9.3 The geographic and climatic character typical of developing countries has anumber of implications for the gas industry. For example, gas is not used for heatingin most developing countries, and to date it has also been uneconomic to use gas for airconditioning; accordingly, in households it is used only for cooling and water heating,if at all. Large shares of gas, then, are typically soli for use outside the household-thatis, for power generation or for base load. In addition, population density in manydeveloping countries is less than in industrial countries. A few very large populationcenters in which economic activity is concentrated may be suitable for the large, fixedinvestment of a gas grid, but many people and commercial activities remain outside thissphere.

9.4 Tropical and subtropical countries do not experience large seasonal variations indemand based on climate; instead, offtake varies in daily or weekly cycles because ofsocial patterns linked to the organization of work. The seasonal variations of gas offtakethat do occur are often induced by power system requirements stemming from variationsin hydropower production, which in turn are caused by variations in rainfall and insmelting and irrigation needs. On the other hand, a hydropower system may level outsome short-term fluctuations (peaks during the day or the week) in the power system.

111


Economic Situation

9.5 The development of gas is attractive for currency-saving reasons. A country couldtry to substitute indigenous gas for energies that require high foreign-currency spending.In many developing countries, however, the gas industry is mostly still at thedevelopment stage, so that there is no developed infrastructure and no developed market.Moreover, the gas reserve basis often consists of only a small number of discoveries(because of limited exploration efforts), and therefore the diversification of supply neededfor secure operation is generally only in the initial stages.

9.6 Despite the economic challenges to encouraging production and use of gas indeveloping countries, some good reasons remain for pursuing such projects. Mostdeveloping countries suffer from power deficits in the sense of a lack of security ofpower supply. Moreover, total electricity produced is often far below demand. Use ofgas turbines is a proven technique for covering peak demand and providing backup toprevent an electricity grid from collapsing. Furthermore, combined cycle and evenhigh-efficiency gas turbines have very favorable specific investment and operating coststhat make the use of gas attractive for base load power generation. Clearly, because ofthe geographic, climatic, and infrastructural factors, the promotion of a gas industry indeveloping countries will have to concentrate on a small number of large customers,especially at the beginning.

Poikical Siuaton

9.7 In developing countries it is typical for state influence on the energy sector to begreat. Private capital is often only marginally involved in dhe gas industry and in theelectricity industry. In most cases, gas and its substitutes are price-controlled, and lowpayment disciplines are common, with parastatals often playing a "leading" role.Restrictions on currency transfer and inflation are serious problems.

9.8 Many developing countries are still trying to develop legal systems capable ofdealing with large commercial disputes. In the wake of frequent or sudden politicalchanges, new governments may not feel bound by acts of their predecessors. So thequestion arises as to whether old contracts or laws will be honored.

Gas in Developing Countries 113

Consequences for Gas Contracts

Whso Are the Panners?

9.9 A typical constellation of seller and buyer would be as follows (see Table 6). Theseller is either an international oil company or the national oil company; especially ifthere is no concession system but instead a system of production-sharing agreements, theseller will formally be the national oil company, even if commercial decisions are largelyinfluenced by the public service commission. The buyer is a state-owned gas company;it may be a department of the national oil company, or it may be an electric utility,which is often state-owned or at least under the dominant influence of the state.

9.10 The most important point is to ensure that none of the partners vanishes-forexample, because of a complete restructuring of the industry. Lack of financialsoundness may also cause some specific problems. It seems very difficult to foreseecontracual solutions for such problems. One possible solution would be a state guaranteeto take over the respective commitments in the case mentioned. Alternatively, it mightbe possible to take over the respective business activities, including the assets of a fadingor failing contract partner. As a lever on the government, the nonfailing partner shouldhave an option to stop temporarily or finally the fulfillment of contractual obligation.

How Shoul the Contmct Be Handled?

9.11 Applicable Law. It will be difficult not to accept the national law of a country,even if expatriate companies fear bias. To give some predictability, at least, the statusof the national law should be fixed in the contract, if possible (i.e., no modifications aftersigning would be taken into account).

9.12 ArbtAtion. If the national law is applied, it may be conceivable at least tospecify that the place of arbitration must be outside the country. This might also benecessary to ensure that enough experience is available on how to handle largecommercial disputes.

9.13 Changed Cirumstaces. The contract may include a boileversement clause-aright of either side to look for a new balance because of drastically changedcircumstances such as a new regulatory framework.


9.14 Interference of Government. To discourage government interference, a contractcould include an option whereby the party suffering from the interference may invokeearly termination of the contract because of the interference of the government in thecontract itself. A case would be the imposition of new taxes or levies that arespecifically aimed at the gas industry, destroying the commercial balance of a deal orcompletely frustrating one of the partners.

Commercil Elements of the Deal

9.15 At the point in time when the decision for the main investment in the prcject hasto be made by the non-state-owned partner, the investment obligation on the state-ownedside should be final-and not dependent on any fiscal authorizations by the governmentor by parliament (cf. Table 8).

9.16 Quantiy. The emphasis should be on a security of supply high enough toguarantee the commercial viability of the investment in the gas chain. Buyers with highcaptive investments may ask for priority delivery in case of curtailments. Specificinformation on the reservoir and reserve situations should be given to the buyer; potentialconsequences may be linked to the status of the reservoir with regard to determining thedelivery and offtake obligations. For a gas merchant company, the passthrough of risksin both directions is of high importance. In view of the developing stage of a gasindustry, a review clause may not only address pricing issues but may also provide arevision of some quantity-related provision.

9.17 Sharing the reservoir risk is of great importance. The economics of a power plantand a gas grid may deteriorate if no long-term gas supply is available. This could becovered pardy by a gas price that allows the gas buyer to recover its captive investmentlinked to gas within the lifetime of conservatively estimated recoverable reserves.

9.18 For 1i3ost developing countries, because of their climatic situation, flexibility willbe of less importance, especially if there is no linkage to the hydropower system. If thegas offtake is linked to variations in the hydro system, this should be taken into accountwhen defining the flexibility. To level out variations in the hydro system, a multi-annualflexibility might be agreed.

9.19 Price. Special attention should be given to subsidies or taxes or levies oncompeting energies. An open price review may be risky, however, if a parastatal'sinteests are at stake. With regard to indices for the price formula, it may be difficult

Gas in Devwloping Couwri 115

to find publications reflecting the local market value of competing energies, if there isa market at all. It therefore may be necessary to revert to some international indices,eve, if they do not exactly reflect the value of competing energies.

9.20 A sensitive point is to determine the consequences of nonpayment. Thecreditworthiness of what are normally a very few customers is extremely important tothe seller. The consequences of nonpayment could be addressed by stopping deliveriesif payment is unsettled for a specific term (e.g., more than two months); by placing ahigh penalty interest rate on overdue payments; by requiring an escrow account or aletter of credit to cover several months' payment obligation; or by providing for accessto the capital and infrastructure of the failing party.

9.21 CuWrrncy. Special rules should be included to guarantee the transfer possibilityoutside the country.

Relations Outide the Deal

9.22 The right to participate in market increases by additional sales may be attractiveto the seller (cf. Table 10). Conversely, options to contract new finds will be attractvefor a gas tading company. Creation of joint companies along the gas chain is anattractdve means of splitfing risks and bringing in commercial and managerial know-how.

Concluding Remarks

9.23 The foregoing chapters were an attempt to describe the variety of possible gascontracts and to emphasize tha gas contracts are individual rather than standard-tatthere are no ready-made recipes for them. It is even fair to say that the contctualarrangements are strongly influenced by the personalities of the individuals involved,and, indeed, these individuals do bear the primary responsibility for achieving andmaintaining a long-lasting and mutually beneficial gas deal.

9.24 Persons involved in gas deals may find it worthwhile to consider the advice ofImmanuel Kant: 'Habe den Mut, Deinen Vestand zu gebrauchen.' (Have the courageto apply your own reason.)

116 Long-Terin Gas Contracts

APPENDIK

Price Pormulas:

There are different ways of writing down a price formula:(A, B being indices to which the gas price is pegged)

The Abstract Form:

p = P"O + a A + b B

The Additive Form:

P=P.+a(A-A.)+b(B-B.)

The Multiplicative Form:

-3= P9<(q+r A; + s B)

Each form can be transformed by arithmetical effort into any other (see below). It istherefore a practical, rather than a commercial question, as to which form is used:

The abstract form is best suited to the comparison of two different priceformulas.

The addwive fonn allows for the easiest economic or commercial interpretationwhen the gas price is pegged to the price of competing fuels. The parameters a,b determine the absolute change of the gas price per absolute change in the priceof the competing energy, A - AO and B - Bo.

* The mudtiplicative form offers an obvious interpretation when the gas price ispegged to inflation or cost indices. In that case r, s determine by whichpercentage the relative change in the respective index is geared to a relativechange of the gas price or in the case of "q" to which extent the gas price is notaffected by the changes in the indices.

117

118 Appendix

Equivalence between the additive form and the abstract form:

P = PO + ax (A - AO) + b x (B - B)

= (P.-axA,-bxB) + axA + bxB

=P' 0 + axA + bxB

Transformation of the multiplicative form into the additive form:

P = P'ox (q + rxA/A' 0 + sxB/B'o), whereq + r + s = 1

= P'0 x q + A x (P'O x r/A'0 ) + B x (PO' x s/B'.)

(for convenience: r' = P'o X r/A'0 and s' P'O x s/B'0)

P = P'O x q + r' x A + s' x B

theni by adding zero:

P = P' x q + r' x A + s' x B(- r' x A'o - s' x B'0+ r' x A'o + s' x B')

= P'0 x q + r' x A', + s' x B'o+ r' x (A - A'0)+ s' x (B - B')

PO + r'x (A - A') + s' x (B - B')

Append_, 119

Transformation of the additive form into the multiplicative form:

P= Po a x (1 pA -A O) + bO x p- qP=P 0xI+ axA- a A+bx(B-B) B.

=P.xl(l -A 1- A A .

PO PO PO AO b P0o B

'where q" = I - p AO- b B0PO PO

P 0Op

r" = i Bo

then qn + rW + s" = 1

P = PO (qW + rn + s" 4 )A0 BO

Joint UNDP/World BankENERGY SECTOR MANAGEMENT ASSISTANCE IPROGRAMME (ESMAP)

LIST OF REPORTS ON COMPLETED ACTIVITIES

Reglon/Counhy Activky/Reporl 21d Date Number

SUB-SAHARAN AFRICA (AiR)

Africa Regional Anglophone Africa Household Energy Wohop (nglish) 07/88 085/88Regional Power Seminar on Reducing Electic Power System

Losses in Africa (English) 08/88 087/88Institutional Evaluation of BOL (English) 02/89 098/89Biomass Mapping Regional Workshops (nglish - Out of Print) 05/89 -

Francophone Household Eney Workshop (French) 08/89 103/89Tnterafrican Electrical Engineering College: Proposals for Short-

and Long-Term Development (English) 03/90 112/90Biomas Asement and Mapping (English - Out of Print) 03/90 -

Angola Energy Asesmnt (English and Portuguese) 05/89 4708-ANGPower Rehabilitation and Technical Assisance (Enlish) 10/91 142/91

Benin Energy Ass_ (English and French) 06/85 5222-BENBotswana Energy Assessment (English) 09/84 4998-BT

Pump Electrification Prefeasibility Study (English) 01/86 047/86Review of Electricity Service Connection Policy (Englih) 07/87 071/87Tuli Block Farms Electrification Study (English) 07/87 072/87Household Energy Issues Study (English - Out of Print) 02/88 --Urban Household Energy Strategy Study (Engli) 05/91 132/91

Burkdna Faso Energy Assessment (English and French) 01/86 5730-BUJRTechnical Assistance Program (English) 03/86 052/86Urban Household Energy Strategy Study (English and French) 06/91 134/91

Burundi Energy Assesmet (English) 06/82 3778-BUPetroleum Supply Management (English) 01/84 012/84Stalus Report (English and French) 02/84 011/84Presentation of Energy Projects for the Fourth Five-Year Plan

(1983-1987) (English and French) 05/85 036/85Improved Charcoal Cookstove Strategy (English and French) 09/85 042/85Peat Utilization Project (English) 11/85 046/85Energy Assessment (English and French) 01/92 9215-BU

Cape Verde Energy Assessment (English and Portuguese) 08/84 5073-CVHousehold Energy Strategy Study (English) 02/90 110/90

Central AfricanRepublic Energy Asssement (French) 08/92 9898-CAR

Comoros Energy Ass t (English and French) 01/88 7104-COMCongo Energy Asement (English) 01/88 6420-COB

Power Development Plan (English and French) 03/90 106/90C6te d'Ivoire Energy Assessment (English and French) 04/85 5250-IVC

Improved Biomass Utilization (English and French) 04/87 069/87Power System Efficiency Study (Out of Print) 12/87 -

Power Sector Efficiency Study (French) 02/92 140/91Ethiopia Energy Assssment (English) 07/84 4741-ET

Power System Efficiency Study (English) 10/85 045/85

-2.-

Region/Country Acdvity/Repori mlk Date Number

Ethiopia Agricultul Resdue Briqueting Pilot Project (English) 12/86 062/86Bagasse Study (English) 12/86 063/86Cooking Efficiency Project (Englsh) 12/87 --

Gabon Energy Assessment (English) 07/88 6915-GAThe Gambia Energy Assessment (Engish) 11/83 4743-GM

Sola Water Heating Retrofit Project (Englih) 02/85 030/85Sola Photovoltaic Applications (Englsh) 03/85 032/85Petroleum Supply Management Assistanco OEnish) 04/85 035/85

Ghana Ewa Adsment (Englsh) 11/86 6234-OHEnergy aionalztion inthe Industril Sector (Engsh) 06/88 084/88Sawmill Residues Utilization Study (Engish) 11/88 074/87

Guinea Energy Assessnent (Out of Print) 11/86 6137-GUIGuinea-Bisau Energy scnnt (English and Portuguese) 08/84 5083-GUB

Recommenaded Technical Asmstance Proj,cts (Englsh &Portuguese) 04!85 033/85

Mansgement Options for the Electric Power and Water SupplySubsectors (English) 02/90 100/90

Power and Water nsitutional Restruing (Frenach) 04/91 118/91Kenya Ener Asement (English) 05/82 3800-KE

Power System Efficiency Study (English) 03/84 014/84Status Report (English) 05/84 016/84Coal Conversion Acion Plan (English - Out of Print) 02/87 -

Solar Water Heating Study (English) 02/87 066/87Peri-Urban Woodfuel Development (English) 10/87 076/87Power Master Plan (English - Out of Print) 11/87 -

Lesotho Euft a (Ehgfi&) 01/84 4676-LSOLiberia Energy Ate (English) 12/84 5279-LBR

Recommended Technical Asiste Projects (English) 06/85 038/85Power System Efficiency Study (English) 12/87 081/87

Madagasca Energy Assessment (English) 01/87 5700-MAGPower System Efficiency Study (English and French) 12/87 075/87

Malawi Eergy Assessment (English) 08/82 3903-MALTechnical Assistnc to Improve the Efficiency of Fuelwood

Use in the Tobacco Industry (English) 11/83 009/83Status Report (English) 01/84 013/84

Mali Ener Agt (English and French) 11/91 8423-MLIHousehold Energy Strategy (English and French) 03/92 147/92

Islamic Republicof Maurinta Energy Assessnt (English and French) 04/85 5224-MAU

Household Energy Strtgy Study (English and French) 07/90 123/90Manitius Energy Aem t (English) 12/81 3510-MAS

Sttus Report (English) 10/83 008/83Power System Efficiency Audit (English) 05/87 070/87Bagasse Power Potential (Engish) 10/87 077/87

Mozambique EV Ammsmesnt (English) 01/87 6128-MOZHousehold lectricity Utilization Study (Eglish) 03/90 113/90

Niger Enor A _t (French) 05/84 4642-NIRStatus Report (English and French) 02/86 051/86Improved Stoves Pject (e gish and FrePch) 12/87 080/87

.3 -

RefionlCowsny AcIivtyRepov 71tke Date Number

Niger Household Energy Conservation and Substitution (Englishand Frnch) 01/88 082/88

Nigeria Energy Aessment (Bnglish) 08/83 4440-UNI

Rwanda Enegy A et (glish) 06/82 3779-RWEnergy Assessment (English and French) 07/91 8017-RWStats Report (English and French) 05/84 017/84Improved Charool Coolitove Strategy (Engli and French) 08/86 059/86Improved Charcoal Production Techniques (English and French) 02/87 065/87Commercialiton of Improved Charcoal Stoves and CabonizaionTechniques Mid-Term Progress Report (English and French) 12/91 141/91

SADCC SADCC Regional Sector Regional Capacity-Building Progamnfor Energy Surveys and Policy Analysis (English) 11/91 -

Sao Tomeand Principe Energy Aessment (Enh) 10/85 5803-STP

Senegal Eneg A _t (Egsh) 07/83 4182-SEStatus Report (English and French) 10/84 025/84Industria Energy Conservation Study (English) 05/85 037/85Prepatory Assisance for Donor Meeting (Engish and French) 04/86 056/86Urban Household Energy Strategy (Englis) 02/89 096/89

Seychelles Energy A t (English) 01/84 4693-SEYElectric Power System Efficiency Study (English) 08/84 021/84

Sietra Lecme Enerr A _met (Eglish) 10/87 6597-SLSomalia Energy A (English) 12/85 5796-SOSudan Mnement Assistance to the Ministry of Energy and Mining 05/83 003/83

Energy Assessment (English) 07/83 4511-SUPower System Efficiency Study (Eaglish) 06/84 018/84S-tas Report (English) 11/84 026/84Wood Energy/Forestry Feasibility (English - Out of Prnt) 07/87 073/87

Swaland Energy At (English) 02/87 6262-SWTanzwia Ener Asw_nmt (En") 11/84 4969-TA

Pen-Urban Woodfuels Feasibility Study (English) 08/88 086/88Tobacco Curing Efficiency Study (Eng) 05/89 102/89Remote Sning and Mapping of Woodlands (Enlish) 06/90 -

Indusial Energy Efficiency Technical Aistace(Eglish - Out of Print) 08/90 122/90

Togo Energy Assssment (English) 06/85 5221-TOWood Recovery in the Nangbeto Lake (English and French) 04/86 055/86Power Efficiency Imrovement (English and French) 12/87 078/87

Uganda Energy Assessment (English) 07/83 4453-UGStatus Report (English) 08/84 020/84Instittional Review of the Energy Sector (English) 01/85 029/85Energy Efficiency in Tobacco Curing Idustry (Enh) 02/86 049/86Fuelwood/Forestry Feasibility Study (English) 03/86 053/86Power System Efficiency Study (English) 12/88 092/88Energy Efficiency Inpovement in the Brick and

Tile idustry (English) 02/89 097/89Tobacco Curing Pilot Project (ngish - Out of Prit) 03/89 UNDP Terminal

Report

-4-

RegionfCowajy Ac4vly/Repoul Mlle Date Number

Zaire Energy Assement (Englsh) 05/86 5837-ZRZambia Energy Asessent (Englsh) 01/83 4110-ZA

Status Report (oEnglish) 08/85 039/85Energy Sector Insitutional Review (oEnglis) 11/86 060/86

Zambia Power Subsecto Efficiency Study (Englsh) 02/89 093/88Energy Strategy Study (Engbsh) 02/89 094/88Urban Household Energy Stategy Study (Engish) 08/90 121/90

Zimbabwe Energy A sment (English) 06/82 3765-ZIMPower System Efficiency Study (English) 06/83 005/83Status Report (English) 08/84 019/84Power Sector Management Assistance Project (English) 04/85 034/85Petroleum Management Assistance (English) 12/89 109/89Power Sector Management Institution Building

(English - Out of Print) 09/89 -

Charcoal Utilization Prefeasibility Study (English) 06/90 119/90Integrated Energy Strategy Evaluation (English) 01/92 8768-ZIM

EAST ASIA AND PACIFIC (EAP)

Asia Regional Pacific Household and Rural Energy Seminar (English) 11/90 -

China County-Level Rural Energy Assessments (English) 05/89 101/89Fuelwood Forestry Preinvtmt Study (Englih) 12/89 105/89

Fiji Energy Assessmnt (English) 06/83 4462-FIJIndonesia Energy Assessment (English) 11/81 3543-IND

Status Report (English) 09/84 022/84Power Generation Efficiency Study (English) 02/86 050/86Energy Efficiency in the Brck, Tile and

Lime Idustries (English) 04/87 067/87Diesel G ating Plant Efficiency Study (gis) 12188 095/88UJrban Household Energy Strategy Study (Engish) 02/90 107/90Biomass (asifier Preinvestment Study Vols. I & H (English) 12/90 124/90

Malaysia Sah Power System Efficiency Study (English) 03/87 068/87Gas Utilization Study (English) 09/91 9645-MA

Myanma Energy Assessment (English) 06/85 5416-BAPapua New

Guinea Energy As t (English) 06/82 3882-PNGStatus Report (lis) 07/83 006/83Energy Strategy Paper (English - Out of Print) - -JIstitutional Review in the Energy Sector (Enlish) 10/84 023/84Power Tarff Study (Eni) 10/84 024/84

Solomon Ilands Ener A t (English) 06/83 4404-SOL13nergy Ass_ent (igi) 01/92 979/SOL

South Pacific Petroleum Transport in the South Pacific (EniShut of Print) 05/86 -

Thailand EnerBy A _ (engsh) 09/85 5793-TMRural Enegy Issues and Options (English - Out of Pint) 09/85 044/85Accelerated Dissemination of lmproved Stoves and

Charcoal Kilns (English - Out of Print) 09/87 079/87

.-5

ReiedunlCows ActvWy/Report Thk Date Number

Thaiand Nordheast Ron Via Poredsy and WoodfeldsPreinvedment Study (Englsh) 02/88 083/88

Impact of Lower Oil Plices (English) 08/88 -Col Developmn and Utilization Study (Engl"h) 10/89 -

Tonga Energy A ent (Engsh) 06/85 5498-TONVanuatu Energy AusamexYft (En"Eh) 06/85 5577-VAWes¢n Samoa EIurgy Amume2ntw (En"Esh) 06/85 5497-WSO

SOUTH ASIA (SAS)

Bangladesh Enery tanu (BEglish) 10/82 3873-BDPriority Investment Program 05/83 002/83Status Report (Engish) 04/84 015/84Power Systm Efficiency Study (Englsh) 02/85 031/85Small Scale Uses of Gas Prefebility Study (English -

(Out of Print) 12/88 -

3ndia Opportuities for Commerciition of NoonventionalEnergy Systems (Englsh) 11/88 091/88

Mahanashts Bagasse Energy Efficincy Project (Eng"sh) 05/91 120/91Mini-Hydro Development on Iifigation Dams and

Cand Drops Vol. II and m (Engish) 07/91 139/91WindFarm Pro-Investment Study (English) 12/92 150/92

Nepal Energy Aessment (English) 08/83 4474-NEPStatus Report (English) 01/85 028/84

Pakistan Household Energy A _t (English - Out of Print) 05/88 -

Assessment of Photovoltaic Programs, Applications, andMarkets (English) 10/89 103/89

Sri T anka Ene¢gy A_ gmt (En") 05/82 3792-CPower System Loss Reducton Study (English) 07/83 007/83Status Report (English) 01/84 010/84Industrial Energy Conservation Study (Englhsh) 03/86 054/86

EUROPE AND CENTRAL ASI (ECA)

Eastern Europe The Fuure of Natural Gas in Eastern Europe (English) 08/92 149/92Poland Energy Sector Restucturing Vols. I-V (English) 01/93 153/93Portugal Energy Assessment (English) 04/84 4824-POTurkey Energy Assessment (En"lish) 03/83 3877-TU

MIDDLE EAST AND NORTH AFRICA (MNA)

Morocco Energy Assessment (English and French) 03/84 4157-MORStatus Report (English and French) 01/86 048/86

Syria Energy Assessment (English) 05/86 5822-SYRElectric Power ' 'iciency Study (English) 09/88 089/88Energy Efficie. i, .-provement in the Cemen' Sector (EngLsh) 04/89 099/89

-6 -

Re,on/Counhy AcdWk/Report Ihk Date Number

Syria Er Efficiecy Implovement i the Ferlizr Sector(English) 06/90 115/90Tunisia Fuel Substituto (Englh and Fnch) 03/90 -

Power Efficiency Study (glish and French) 02/92 136/91nergey Magement Stregy in the Rsiential andTerty Secos (English) 04/92 146/92

Yemen Enftf¢AbEcssm Oitnglish) 12/84 4892-YAREnery Invetment Priorities (Englsh - Out of Prit) 02/87 6376-YARHousehold Enery Sategy Study Phase I (English) 03/91 126/91

LATIN AMEURICA AND TBE CARIBBEAN (LAC)

LAC Regional Regional Seminar on Electric Power System Loss Reductionin the Caribbean (Englih) 07/89 -

Bolivia Energy A ment (Englsh) 04/83 4213-BONaional Energy Plan (Englih) 12/87 -National Energy Plan (Spanish) 08/91 131/91La Paz Privae Power Technical Aistance (En ) 11/90 111/90Natuvrl Cs Distibution: Economics and Regulaton (English) 03/92 125/92Prefeability Evaluaion Rural Electrificadon and Demand

A^esesn(t (Eni and Spanish) 04/91 129/91Private Power Geraton and Transmission (Englih) 01/92 137/91

Chile Enr Sector Review (Enl - Out of Print) 08/88 7129-CHColombia Energy Strategy Paper (English) 12/86 -Costa Rica Energy Aus mot OEngih and Spanish) 01/84 4655-CR

Recomnmended Technical Assistance FPojects (Englih) 11/84 027/84Fores Residues Utilization Study (Englih and Spanish) 02/90 108/90

D . .

Republic Ene rgsysns (Ensh) 05/91 8234-DOEcuador EnergyAssnet (Spanish) 12/85 5865-EC

Energy Strategy Phase I (Spanish) 07/88 -

Energy Strategy (English) 04/91 -

Prvate Minihydropower Development Study (English) 11/92 --Haiti Energy Atd (English and French) 06/82 3672-HA

Status Report (English and Frech) 08/85 041/85Household Energy Strategy (English and French) 12/91 143/91

Honduras Energy d (English) 08/87 6476-HOPotroleum Supply Managemnt (English) 03/91 128/91

Jamaica Energy Assment (English) 04/85 5466-JMPetroleum Procurement, Refining, and

Distribution Study (English) 11/86 061/86Energy Efficiency Building Code Phase I (English-Out of Print) 03/88 -

Energy Efficiency Standards andLabels Phase I (English - Out of Print) 03/88 -

Management Information System Phase I (Engish - Out of PRint) 03/88 -Charcoal Production Project (English) 09/88 090/88FIDCO Sawmill Residues Utilization Study (English) 09/88 088/88

-? -

Region/Country Acdvi*y/Report lid Date Number

Jamaica Energy Sector Strategy and Investment Planning Study (English) 07/92 135/92Mexico Improved Charcoal Production Within Forest Management for

the State of Veracruz (English and Spanish) 08/91 138/91Panama Power System Efficiency Study (English - Out of Print) 06/83 004/83Paraguay Energy Assessment (English) 10/84 5145-PA

Recommended Technical Assistance Projects (English-(Out of Print) 09/85 -

Status Report (English and Spanish) 09/85 043/85Peru Energy Assessment (English) 01/84 4677-PB

Status Report (English - Out of Print) 08/85 040/85Proposal for a Stove Dissemination Program in

the Sierra (English and Spanish) 02/87 064/87Energy Strategy (Spanish) 12/90 -

Saint Lucia Energy Assessment (English) 09/84 5111-SLUSt. Vincent andthe Grenadines Energy Assessment (English) 09/84 5103-STV

Trinidad andTobago Energy Assessment (English - Out of Print) 12/85 5930-TR

GLOBAL

Energy End Use Efficiency: Research and Strategy(E-nglish- Out of Print) 11/89 -

Guidelines for Utility Cudomer Management andMetering (English and Spanish) 07/91 -

Women and Energy-A Resource GuideThe International Network: Policies and Experience (English) 04/90 -

Assmment of Personal Computer Models for EnergyPlanning in Developing Countries (English) 10/91 -

Long-Term Gas Contracts Prnciples and Applicaions (English) 02/93 152/93

020393

LSMA1A1c/o Industry and Energy DepartmienitThe World Bank1818 H Street, N. W.Waishington, D. C. 20433U. S. A.

principles and applications - documents & reports - all...

Documents