WPS 1890 POLICY RESEARCH WORKING PAPER 1890 Market Development in the Experience in the United Kingdom shows that it is United Kingdom's Natural possible to move from a G as Industry monopoly to a competitive environment in natural gas without structural reforms, Andrej Juri's although it is costly and difficult. Deregulation must be accompanied by the crearior of an appropriate regulatorv and institutional framework for the sector that shields entrants from the exercise of market power by the incumbent and gives entrarnLs in the gas market equal rights in dealing with the transportation monopolist The World Bank Private Sector Development Department Private Participation in Infrastructure Division March 1998 | POLICY RESEARCH WORKING PAPER 1890 Summary findings Juris shows how, in the United Kingdom, government generated through the flexibility mechanism to choose and industry participants have responded to challenges the balancing measures with the lowest cost to society. created by opening the natural gas industry to Juris analyzes the four mechanisms used in physical gas competition. He concludes that, as a result of markets, describes developments in the U.K.'s financial cooperation between the government and industry gas market, and describes pipeline capacity trading in participants, appropriate mechanisms can be established primary and secondary markets and BGT's pricing of for operating and balancing the system and for trading capacity and transportation services. natural gas and transportation capacity. The deintegrated The most important issue today, says Juris, is whether natural gas industry in the United Kingdom is off to a industry participants can reach a consensus on how to promising start after a long gestation. enhance the existing framework to make markets more Juris describes the processes of the Network Code, a efficient. Development of the underdeveloped financial market-based method for balancing the pipeline system gas market will require cooperation between BGT and and optimizing transportation by British Gas TransGo the Office oif Gas Supply to give the International (BGT), the transportation and storage arm of British Gas Petroleum Exchange access to BGT's electronic network, (formerly the publicly owned monopoly transporter and so that it car record and settle transactions. Both BGT supplier of natural gas). The Network Code is a set of and its customers will need to contribute time and rules that determine how users of the pipeline system resources to developing an efficient tariff structure for cooperate with the system operator when seeking pipeline capacity and transportation services in the transportation services. The operator uses price signals contract and tariff markets. This paper - a product of Private Participation in Infrastructure Division, Plrivate Sector Development Department - is part of a larger effort in the department to analyze issues arising from private participation in infrastructure. Copies of the paper are available free from the World Bank, 1818 H Street NW, Washington, DC 20433. Please contact Sandra Vivas, room Q7-005, telephone 202-458-2809, fax 202-522-3481, Internet address svivas@worldbank.org. March 1998. (49 pages) The Policy Research Working Paper Series disseminates the findings of work in progress to encourage the exchange of ideas about development issues. An objective of the series is to get the findings out quickly, even if the presentations are less than fully polished. The papers carry the names of the authors and should be cited accordingly. The findings, interpretations, and conclusions expressed in this paper are entirely those of the authors. They do not necessarily represent the view of t'e World Bank, its Executive Directors, or the countries they represent. Produced by the Policy Research Dissemination Center Market Development in the United Kingdom's Natural Gas Industry Andrej Juris 2 CONTENTS Pipeline System Operation Costs in System Operation System Operation under the Network Code Natural Gas Markets Physical Gas Market Financial Gas Market Capacity Markets Primary Capacity Market Secondary Capacity Market Conclusion Appendix Structure and Regulation of the U.K. Natural Gas Industry Notes References Tables 1. Size of the U.K. Gas Market, 1994-95 2. Spot Market Prices and Volumes at the Bacton Terminal, June-July 1996 3. On-System Trading, July 22-28, 1996 4. Trading and Prices in the Flexibility Market, July 19-28, 1996 Table A. 1 U.K. Gas Price Index, Current Prices Table A.2 U.K. Gas Price Index, Real Prices Table A.3 Natural Gas Consumption, 1986-95 Table A.4 Natural Gas Production and Imports, 1986-95 Boxes 1. Participants in the U.K. Natural Gas Industry 2. Transition Costs of Opening Natural Gas Markets to Competition: The Case of British Gas Energy Figures 1. Network Code Processes 2. Mechanisms for Natural Gas Trading in the U.K. 3. Argus Monthly Sell-Buy Index, October 1995-September 1996 4. Balancing under the Soft Landing Regime of the Network Code 5. Price Determination in the Flexibility Market with the Source of Imbalance a Change in Demand 6. Price Determination in the Flexibility Market with the Source of Imbalance a Change in Supply 7. Pipeline Capacity Booking and Trading 8. Capacity Resale by Auction Figure A.1 Structure of the U.K. Natural Gas Industry Figure A.2 Index of Current Gas Prices, 1990 = 100 Figure A.3 Index of Real Gas Prices, 1990 = 100 Figure A.4 Natural Gas Consumption, 1986-95 Figure A.5 Natural Gas Production and Imports, 1986-95 3 Deregulation and structural reforms in the natural gas industries of many countries have prompted questions about how far deregulation should go and whether markets in natural gas and pipeline transportation can function properly. The experience of the United Kingdom shows that markets can be successfully created in almost all segments of the natural gas industry, as long as the design of these markets takes into account the economic and technical characteristics of the industry. These characteristics include the multiproduct economies of scale that dominate pipeline transportation and the economies of scope between natural gas supply and transportation. As the industry moves away from a vertically integrated structure, appropriate mechanisms to facilitate trading in gas markets and coordinate interactions between the pipeline system operator and pipeline users must substitute for operations once performed internally by the system operator. Such mechanisms support competition and efficiency in the natural gas industry and help optimize gas flows and transportation costs in the deintegrated natural gas industry. Once these mechanisms are in place, economic regulation can focus on markets characterized by natural monopoly, such as the primary market for pipeline capacity. This paper shows how the U.K. government and industry participants have responded to the challenges created by the opening of the natural gas industry to competition. It concludes that the appropriate mechanisms for system operation and balancing and for natural gas and capacity trading are already in place as a result of cooperation between the government and industry participants. The paper first describes the processes of the Network Code, a market-based method to balance the pipeline system and optimize transportation by British Gas TransCo (BGT), the transportation and storage arm of British Gas (the former publicly owned, monopoly transporter and supplier of natural gas). It then analyzes the mechanisms used in physical gas markets and presents an overview of developments in the financial gas market in the U.K.. Next it describes pipeline capacity trading in primary and secondary markets and the pricing of capacity and transportation services by BGT. Finally, it summarizes the lessons from market development in the U.K. natural gas industry. Pipeline System Operation The purpose of pipeline system operation is to optimize gas flows and minimize imbalances between gas intake and offtake. The main functions of system operation are: * Intake of gas of agreed volumes and quality at injection, or entry, points. * Transportation of gas through the pipeline system. * Offtake of gas of agreed volumes and quality at delivery, or exit, points. 4 * Maintenance of balance between intake and offtake. * Maintenance of a specific pressure. * Maintenance of a specific calorific value of gas. These functions are carried out through the scheduling and central dispatch of gas flows. Typically, a system operator schedules gas flows and balances the system according to the supply and demand estimated on the day preceding the gas day. During the gas day the operator relies on a central dispatch unit to respond to system imbalances by adjusting pressure, rerouting gas flows, or curtailing intake or offtake in real time. The industry structure determines the way in which the operator runs the system. In a vertically integrated industry the operator optimizes gas flows and minimizes imbalances internally. In a deintegrated industry it must coordinate these functions with other market participants. A set of rules for system operation and balancing is important in both industry configurations, but it is much more important in a deintegrated industry than in a vertically integrated one. If there are a large number of pipeline system users, coordination is required between them and the system operator, through "rules of the game" that determine nomination and scheduling of gas flows and balancing and operation of the system. Costs in system operation How the system is operated affects the costs faced by the system users for both transportation and system operation. The natural monopoly characteristics of transportation and the economies of scope between transportation and system operation mean that costs can be minimized only if there is just one system operator. But the lack of competition would mean that no market forces are acting as a check on prices, and an unregulated system operator would typically charge monopoly prices for transportation and system operation. Economic regulation of transportation services and capacity and a transparent set of rules for system operation help the regulator and users prevent such exploitation of market power by the system operator (for a discussion of economic regulation of transportation services and capacity see the section below on capacity markets). System balancing is a complex operation that imposes costs on the system users. If a system user runs an imbalance, it imposes costs on the other users. The role of the system operator is to discourage such behavior by reflecting these costs in balancing penalties. But if the system runs an imbalance, the system operator implements balancing measures that impose costs on some or all users. The operator has much discretion in selecting these measures. To ensure that the selection is based on the costs of the measures, explicit rules are needed for sequencing the measures according to the situation. In addition, mechanisms are needed to expose the system operator to the costs of system balancing. 5 ,One way to expose the system operator to such costs is through the pricing of transportation contracts. These contracts are priced according to the reliability of supply provided by the system operator. Thus interruptible transportation contracts are sold at lower prices than firm transportation contracts, because interruptible shipments are curtailed first, and firm shipments last, in the event of a system imbalance. Users purchase the contracts that match their needs for reliability of supply, paying a premium for more reliable transportation. Another way to expose the system operator to the costs of balancing is by establishing a spot market for imbalances - the excess or missing gas in the system. The system operator can use the price signals generated by a spot market to compare the costs of system balancing measures with the cost of the gas needed to restore system balance, then decide whether to purchase or sell the missing or excess gas in the spot market or to curtail gas flows on the basis of the cost of each transaction. A spot market thus brings market forces to bear on the system operator. In addition, it allows an effective penalty to be imposed on users that cause a system imbalance, a penalty based on the spot price for the missing or excess gas. This price which reflects the market value of the imbalance, is an effective penalty because the price of a positive imbalance is typically lower than the price the users paid in the gas market, and the price of a negative imbalance typically higher. System operation under the Network Code The Network Code of British Gas TransCo is a set of rules for system balancing, capacity acquisition and trading, and gas transportation and trading in the pipeline system operated by BGT. ' And it is the legal document that forms the basis of the agreement between BGT and shippers regarding the operation and use of the pipeline system. The Network Code facilitates cooperation among the participants in the unbundled, deintegrated gas industry in the U.K., requiring each participant is required to perform certain activities, or processes, that in the end lead to optimal system operation and balancing (for a description of the gas industry and its participants see box I and the appendix). Because coordinating these processes requires the exchange of a large amount of data, the participants communicate with one another through the U.K. Link, a computer system developed by BGT. ' This section draws from BGT 1996. 6 The Network Code processes are performed in four stages, according to their position relative to the gas day, the day when actual transportation of gas takes place (figure 1). The gas day runs 24 hours, from 6:00 a.m. on the current day to 6:00 a.m. on the next day. Box 1: Participants in th0e U.K NaturalGa try Delivery y operators dathi rators of the gas si ts at entry terminals. Public gas transporter is,an operator oftaission p e r a license granted by Ofgas. At present BGT and several small transmission companies have public gas transporter licenses. St:orage amaagers are the rator of s g ilities. At present. BGT is the onLy storage manager linked to the Ipipeline network. Shippers Arins with ashppesicensethatb sm erfs, sell it to suppliers, andt contract 4apblicgastanp4rfrtasottoofhestoosur. S=ppliers al ad then sell it to consumers. Spliers d ' c gas transporters. Many companies have both splesadsipr iess The Office of Gas Supply (Of it regulator of the ral gas indstry in the'U.K.. Traders are firms that buy and sell natural gas in the spot makt Traders do not deal directly with pubicgas transporters.orcustomers. Allocation agents are the ad nistratois of the entry points in the pipeline system. These agents act on behalf of shippers and calclate how much of the gs injected at a terminal belongs to each shipper. Then they infor a public gastraspor w ch calculates the transportation ~charges forf each siper Shippers 'agents aruthorzdtary eon behalfof shippers. Top-up manager is a unit of BGT thate sgs is'stoe tomeet demand in the event of severe weather duing the following w inter. Shrinkage provider is a unit ofBG that isresponsible for robtaiing the gas needed to fuel compressors and balance any leakage in the pipeline system. Source: BGT 1996. 7 Figure 1 Network Code Processes Day before Day after Non-daily gas day Gas day gas day License Gas flow Network i. Measurement from Ofgas nornination i operation i Framework . ! Scheduling > Flexibility Allocation agreement market Customer Renomination Gas and site GsDaily trading and balance registration balancing calculation Capacity booking Flexibiiity icing and trading bids Invoicing - -- . .. .. ; ~~~~~~~~(monthly) ,........... ....................... U.K. Link Shipper 'British Gas , TransCo Slhippe fiunction BGfTfunction Srrce 1oGT 1996 Stage I. Non-daily processes, pe7formed before the gCas day * Shippers must obtain a shippers license from Ofgas and then establish a framework agreement with BGT. * Shippers purchase pipeline or storage capacity, or both, from BGT (capacity booking) or from other shippers in the secondary capacity market (capacity trading). BGT charges shippers for booked capacity monthly. * Shippers register their customers and supply sites, or exit points, with BGT. Supply sites can be daily metered or non-daily metered. Typically, contract market customers have daily metered sites, and tariff market customers non-daily metered sites. Stage 2: Processes performed oh the day before the gas day * In the gas nomination process shippers inform BGT about the location, quantity, and calorific value of gas to be injected into and withdrawn from the system on the gas day (shippers can send their nomination up to one month in advance). Nomination must be finalized by 12:00 p.m. for withdrawal at daily metered sites, by 2:30 p.m. for use of storage, and by 3:00 p.m. for injection at the entry points. In the meantime BGT forecasts withdrawal at non-daily metered sites for each shipper and creates 8 non-daily metered nominations by 2:00 p.m.. All shippers' nominations must be approved by BGT. * On the basis of the approved nominations, BGT schedules the gas flows in the pipeline system to maintain safety and reliability of supply and to minimize costs. If the system cannot transport all nominated gas, BC;T contacts shippers and asks for revised nominations. * Renominations can be made between 6:00 p.m. on the day before the gas day and 3:59 a.m. on the current day. * Shippers able to adjust their supply and demand according to the expected system price post their flexibility bids for selling or buying gas from BGT on the U.K. Link. Flexibility bids become available to BGT at about 6:00 p.m. (see the section below on the flexibility mechanism). ? Shlippers trade gas in the on-system market and include information about the trade in their nominations or renominations (see the section below on on-system trading). Stage 3: Processes performed during the gas day 3 BGT operates the network according to the schedule and responds to any problem in the system through central dispatch of entry and exit ooints and the gas flows. * BGT monitors the system balance. If the system runs an imbalance, BGT buys or sells the missing or excess gas in the flexibility market. If it cannot eliminate an imbalance through the flexibility mechanism, it uses available storage facilities or, in serious cases, asks shippers to stop shipments to interruptible sites.2 In an emergency BGT issues flow orders3. * Shippers are responsible for maintaining a balance between their intake and offtake according to their nominations. If they run an imbalance, they can avoid penalties by trading in the on-system market. Stage 4: Processes performed on the day after the gas day BGT collects data about the volume and calorific value of gas at entry and exit points and in storage. At 4:00 p.m. metering data become available for the allocation process. 2 BGT's choice of interruptible sites must depend entirely on operational necessity. But on average over the year, all shippers with interruptible sites must be treated equally. 3 Flow orders are orders issued by pipeline companies that require shippers to inject or withdraw natural gas at a specific point to ensure continued flow of natural gas through the system during an emergency. 9 * The allocation process allocates the gas injected and withdrawn at specific sites among the shippers. This task is performed by an allocation agent at entry points and by' BGT at daily metered and non-daily metered exit sites and storage. Shippers receive allocation data for review. * Each shipper's balance is calculated on the basis of the allocation data.4 Shippers with imbalances above a specified tolerance level are charged an imbalance penalty. In addition, they are charged or credited for gas that is above the tolerance level, at a price equal to the last accepted flexibility bid in the flexibility market. * BGT uses the allocation data to calculate the commodity charges. It adds to these clharges capacity overrun penalties, if applicable, and credits or charges for the flexibility bids accepted. * Finally, BGT produces a detailed monthly invoice for each shipper that includes all applicable charges and credits and sends it to the shipper through the U.K. Link. The final rule of the Network Code is that BGT cannot earn positive or negative profits from maintaining system balance. So at the end of each month BGT sums up all receipts and payments for the flexibility bids accepted and the imbalance and scheduling charges and then credits or charges a share of the net sum to each shipper in proportion to the amount of gas it shipped during that month. 4 Allocation data are finalized within seven days after the gas day. If changes occur, the balance is recalculated and adjustment is made in the next invoice. 10 Natural Gas Markets The unbundling of gas supply and transportation and the opening of natural gas markets to competition have created new requirements relating to how natural gas is traded and how market participants interact. System operation rules guide the interactions between gas shippers and the monopolistic gas transporter. But the industry structure and trading mechanisms determine the efficiency of gas markets. An efficient natural gas market performs three functions: * It aggregates supply and demand to determine system demand and supply curves. * It facilitates market clearing to determine the market price of natural gas. * It signals the market value of gas. Market aggregation is achieved by concentrating trading among producers, traders, and shippers at one or several trading points. These trading points can be market centers, typically located at the major pipeline interconnection or at the major entry point to the high-pressure transmission system. In the U.K. the onshore terminals where producers deliver their gas to BGT's pipeline network have become the trading points. Market clearing is facilitated by trading mechanisms - bilateral trading, brokerage, spot markets, and auctions. Which of these mechanisms is used depends on the characteristics of supply and demand as reflected in the dimensions of gas contracts - typically time and location of delivery, pressure and calorific value of gas, security of supply, and, of course, the unit price of gas. Participants in the U.K. gas markets use all four trading mechanisms. Price signaling is facilitated by the collection and dissemination of information about prices and trading volumes by reporting and consulting agencies, journals, and newsletters. The reporting of this information enables market participants to choose trading and consumption strategies according to market signals. In the U.K. several firms regularly report spot market prices and volumes, including PH Energy Analysis and Argus Petroleum. At present there is no statistical or panel reporting of spot market prices. Natural gas markets allow the trading of long-, medium-, and short-term natural gas. While long- and medium-term gas contracts are more typical for the integrated gas industry, short-term gas contracts are important in the deintegrated gas industry because of market participants' need to achieve physical balance between demand and supply in a short time frame (typically between one day and one mronth). Thus system balancing affects how natural gas is traded. In the U.K. the balancing requirements of the Network 11 Code have led to two forms of gas trading: on-system trading and the flexibility mechanism. Short-term gas trading is conducted using bilateral trading, brokerage, auction, and spot market mechanisms. Bilateral trading, typically in which buyers and sellers negotiate supply conditions on a bilateral basis, develops first. As the volume of trading increases, bilateral trading becomes inefficient because markets become nontransparent and trading imposes high transaction costs on market participants. Bilateral trading is therefore replaced by brokerage. Brokerage is an advanced bilateral trading model in which brokers, or traders, trade on behalf of buyers and sellers. Brokers aggregate the demand and supply of their clients and trade among themselves or with other market participants. As trading volume increases, market participants need to concentrate trading at one or several trading points to reduce transaction costs, and brokerage trading evolves into spot market trading. The development of a spot market is typically followed by the development of risk management instruments. Because spot market prices reflect system short-run marginal costs of gas and the opportunity costs of capacity, they tend to be volatile, and the inherent price risk is often very high for many market participants. This leads to demand for risk diversification and, ultimately, to the development of a financial gas market where risk-minimizing financial instruments are traded. These markets can be organized or not, depending on the ability of institutions to respond to market needs. Initially, financial institutions offered mostly swaps to customers on an individual basis. Trading of standardized financial gas contracts in the U.K. started on January 31, 1997, when the International Petroleum Exchange introduced natural gas futures contracts for delivery at the National Balancing Point in BGT's pipeline system. Auctioning is typically used for efficient trading of goods when one player dominates supply or demand. In the U.K. natural gas industry, gas auctioning is conducted by BGT in trading system imbalances. The trading rules are determined by the Network Code in order to prevent abuse of BGT's monopoly in this market. Physical gas market Although British Gas has historically dominated the physical gas market, it has rapidly been losing market share since deregulation of gas supply. In the past five years its monopoly has been eroded by competition in the contract market. Its gas trading and supply arm, British Gas Energy (BGE), now has about a 33 percent share in that market, but still has a monopoly in the tariff market (table 1; for a discussion of the distinction between contract and tariff markets, and end-use consumption and prices, see the appendix). Taken together, these two positions give BGE about a 67 percent share in the overall gas market in the U.K.. Although BGE faces competition from about 40 suppliers in the contract market, its overall market share is unlikely to change substantially. On the 12 other hand, it is estimated that it will lose about 25 percent of its tariff market share after gas supply to the tariff market is opened to competition in 1998 (Royle 1996). Table 1 Size of the U.K. Gas Market, 1994-95 (millions of therms) BGE's share Market 1994 1995 1995 (percent) Tariff market 11,440 1 1,800 100 Contract market 10,780 11,200 33 Firm supply 5,720 5,900 15 Interruptible supply 3,300 3,300 50 Power generation supply 1,760 2,000 38 Total gas supply 22,220 23,000 67 Source: Royle 1996 The deregulation of retail markets, an open access policy, and the unbundling of British Gas's supply and transportation have led to the development of short-term gas trading. Until recently most gas was sold under long- and medium-term contracts between British Gas and producers or consumers. After deregulation market participants had to balance their supply and demand in the short term and thus needed an effective way to trade short-term gas. That led to the development of spot markets in entry terminals and in BGT's pipeline system. At present, there are four mechanisms for trading natural gas in the U.K.: bilateral contracts, spot markets, on-system trading, and the flexibility mechanism (figure 2). 13 Figure 2 Mechanisms for Natural Gas Trading Producer 1 Producer 2 Gas trader 2 Spot market ----------------------- L ----------------------_ Shipper 1 1 0` Shipper 2 | British Gas TransCo On-system market British Gas TransCo Flexibility mechanism Bilateral contracts between producers and shippers. Spot market trading among producers, traders, and shippers. -~ >.- On-system trading of gas and imbalances between shippers; prior notification of BGT is required. Flexibility mechanism - trading between shippers and BGT. Source: Authors compilation Bilateral contracts The traditional way of trading natural gas in the U.K. is through bilateral contracts, medium- and long-term natural gas supply contracts, between producers and shippers. The provisions in these contracts vary widely, depending on the characteristics of the parties' demand and supply. Parties typically specify the total volume of gas covered by the contract; the unit price of the gas, which can be fixed or linked to the price of other fuels (such as oil); and the financial settlement. Long-term contracts specify delivery of gas for a period longer than one year, medium- term contracts for a period between three months and one year. A typical example of a long-term contract is a take-or-pay contract under which the buyer agrees to pay regularly for a specified volume of gas regardless of whether it actually takes the entire amount. The U.K. alternative to the take-or-pay contract is a depletion contract, under which the buyer finances a share of the producer's field development costs in exchange for future gas deliveries. Historically, bilateral supply contracts were concluded between British Gas and its customers: British Gas acquired gas from producers at the onshore terminals and sold it 14 to customers at consumption sites. But the opening of natural gas supply to competition has multiplied the contractual relations between producers and suppliers. As more and more gas has become available for independent suppliers, trading has gradually concentrated where producers and suppliers have the best access to the gathering and transmission pipeline systems. Bilateral supply contracts are now based on delivery at the Bacton and St. Fergus terminals. And since the introduction of the Network Code, bilateral contracts with delivery at the national balancing point have developed (see the section below on on-system trading). The opening of natural gas markets to competition often involves transition costs for incumbent firms. One example of such costs is the investment necessary to fulfill the regulator's requirement to secure reliable supply for all consumers in the franchise area, an investment that becomes useless in a competitive market. Another is the liability arising from contracts that are not fulfilled because the regulator has altered the contractual relations. A regulator might allow cancellation of long-term contracts between suppliers and consumers to promote development of a spot market, for example, British Gas Energy will face such transition costs as a result of the deregulation of the tariff market in 1998 (box 2). Box 2 Transition Costs of Openin iNatural Gas to Comptition: The. Case of British Gas Energy Long-term bilateral contracts oen become aburden for an incumtbent supplier after the opening of natural gas markets} to competition.- iTe incumbent ofen becomes stuck with take- or-pay contracts concluded under an "obliigation-to-serv regula regime, as many of its customers switch&to competing suppliers., British Gas Energy holds take-or-pay obligations tphase about 4.6iion cubic feet a day (bcfd) of gas from producers, but it cai sell onl at 4.35bcfd inconsumer market. This results in an estimated surplus fdtof tot take-or-pay ob ns, assuming that BGf maintains a 90pert s in tr n98. TeBGE's liability from this surplus amounfts t bout 28% milo o f t p nlue 2 basis, assuming that BGE maintains a 90 percenh in 1_ttatin 998. Although BGE's surplus is not a significant volume, it represents; about 30 percent of recent spot market volumes. So if BGE delivers its surplus-gas to spot markets, it will push down spot market prices, enabling BGE's competition to attract more customers thrgh lower prices. Eventually, BGE may lose more than 10 percent ofits marklet e, whichVwould increase its take-or-pay liabilities. Source. Royle 1996. 15 Spot market trading Spot markets have developed at the onshore terminals of BGT's pipeline network as a result of the increasing need to balance supply and demand in the short term.' Four main factors are behind the development of spot market trading in the U.K.:6 1. Introduction of the 90:10 rule in 1989. This rule prohibits British Gas from purchasing more than 90 percent of the gas from any field. After it was introduced, producers started to market their gas to independent gas suppliers, which competed with British Gas in the contract market. Producers initially sold gas under medium- or long-term contracts. But as changing demand and supply conditions led to a need to balance gas requirements in the short term, they started selling gas on a short-term basis. 2. Ofgas order to British Gas to release gas to competitors in 1991. Between 1992 and 1995 British Gas made about 4.9 billion cubic meters of gas (this is total volume over the whole period) available to competing suppliers through sale in spot markets. 3. Oversupply by independent suppliers. Some suppliers committed themselves to 100 percent take-or-pay contracts but could not find customers for their gas. They took the surplus gas to spot markets for resale. 4. Delay in the start-up of three power stations. This delay led to an estimated demand loss of 6.2 million cubic meters a day, or 3 percent of the average daily demand. Stuck with the surplus gas, producers took it to spot markets. Trading in a spot market is done on a bilateral basis, between producers and shippers, or on a brokerage basis, with traders often acting as intermediaries. In the U.K. spot market trading started as a bilateral telephone market in 1989-90 between producers and suppliers (Roeber 1996). The nature of the trading has not changed substantially except for the entry of traders and the higher volumes of trading. Producers, shippers, and traders "shop around," arranging for terms that best suit their needs. Five types of natural gas contracts are traded in the U.K. spot markets: * Day-ahead gas - for delivery on the next day. * Balance gas - for delivery on a daily or weekly basis. * Monthly gas - for delivery during a specified calendar month. ' There are six entry terminals in the U.K., but only two of them, Bacton and St. Fergus, have developed into major spot markets. 6 The data in this section are drawn from Royle 1996. 16 * Quarterly and annual gas - for delivery during a specified quarter or year. * Time spread gas - for delivery against gas under contract for a different time of delivery. The products most commonly traded in the U.K. spot markets are day-ahead and monthly gas contracts for delivery to the Bacton or St. Fergus terminals. The U.K. spot markets are still generally thin, illiquid, and volatile. Trading volume ranges from 2 million to 8 million therms a day, 5 to 10 percent of the total daily supply. Prices vary accordingly - ranging from 9 to 14 pence a therm (table 2 and figure 3) Traded volumes and prices are reported by the media or specialized newsletters, such as British Spot Gas Markets, published by PH Energy Analysis, and European Natural Gas Daily, published by Petroleum Argus. British Spot Gas Markets introduced the Heren Index, which is the weighted average price of traded gas contracts for delivery in a particular month. The index, which is based on volume andl price information collected from traders, is an indicator of the market price of short-term, gas and is increasingly used as a price reference in bilateral contracts (Powel 1996). Table 2 Spot Market Prices and Volumes at the Bacton Tterminal, June-July 1996 Indicator June 1996 July 1996 Heren Index (pence per thern) 12.1275 9.6546 Number of transactions 38 35 Total volume (millions of therms 2.278 2.072 per day) Lowest price (pence per therm) 10.50 9.00 Highest price (pence per therm) 13.575 11.5 Smallest volume (therms per day) 18,000 15,000 Largest volume (therms per day) 250,000 300,000 Source: The Heren Index, July 1996 The most important issue in the further development of spolt markets in the U.K. is the need for a standardized gas contract. An efficient short-termn market should facilitate the pricing of gas according to the system short-run marginal cost of gas. A short-term gas contract has fewer parameters than a long-term gas contract, which includes a number of delivery characteristics in addition to price. A standardized short-term contract specifying a delivery to a major terminal or an interconnection in the pipeline system therefore improves the efficiency of trading short-term gas. The introduction of the "on-system" market at the National Balancing Point in BGT's pipeline system provides a "system- wide" trading point for such a contract. This is complemented by the activities of the International Petroleum Exchange (IPE) to launch the trading of standardized physical and financial gas contracts at the National Balancing Point. The IPE has succeeded in 17 developing a commercially viable natural gas futures contract, but the development of a short-term gas contract has been postponed due to communication problems between the IPE and BGT. Figure 3 Argus Monthly Sell-Buy Index, October 1995-September 1996 Pence per therm 14 12 10 8 6 4 2 0 4 I - -II [!, - Oct. Nov. Dec. Jan. Feb. Mar. Apr. May Jun. Jul. Aug. Sep. 95 95 95 96 96 96 96 96 96 96 96 96 Source: Petroleum Argus data 18 On-system trading The on-system trading is basically trading in a spot market located at an imaginary notional point in the pipeline system. Shippers use their reserved pipeline capacity to deliver natural gas to the notional point where they sell it to interested buyers. Buying shippers then use their pipeline capacity to transport natural gas from the notional point to a desired location. The pipeline system operator, which keeps track on traded volumes and provides transportation services, facilitates completion of transactions. The on-system market in the U.K. facilitates trading of natural gas at the National Balancing Point (NBP), a notional point in BGT's pipeline network at which BGT balances its high pressure pipeline system. Transactions typically involve shippers which own entry and exit pipeline capacity, and are facilitated by BGT's nomination process under the Network Code. A shipper with entry capacity to the NBP sells natural gas to a shipper with exit capacity from the NBP. After the two shippers agree on the conditions of trade, they nominate their gas flows, specifying the other party as the exit and entry poinlt. If the two nominations match in BGT's system schedule, BGT approves the trade and the transaction can be completed. Physical and financial flows of a transaction in the on-systenm market are different. The gas withdrawn from BGT's system by the buying shipper is often different from the gas injected by the selling shipper, because BGT directs gas flows subject to system optimization and does not follow contractual links. The only requirement for BGT is that it deliver the same quantity and quality of gas nominated by the contractual parties. Financial settlement of the transaction involves only the shippers; BGT does not participate. The on-system market has become popular among gas traders in the U.K. because of its central location, accessibility, and low transaction costs. The on-system trading is becoming increasingly robust and liquid, as the liberalization of the U.K. gas market advances. Shippers use the on-system market to trade a whole variety of natural gas contracts, which are much the same as those traded in a spot market: * Day-ahead gas is a common product in all spot markets. The delivery period is the next gas day; and the gas is used for daily balancing and price arbitrage. In an example of a day-ahead gas trade, on September 24, 1996, 25,000 therms of gas for delivery on the next gas day (between 6:00 a.m. Septemnber 25 and 6:00 a.m. of September 26) were sold for 13.1 pence per therm (see line '3 of table 3). * Balance gas restores the shipper's balance between supply and demand in a particular period. The delivery period ranges from one day to one month, depending on the shipper's needs. In an example of a balance gas trade, on July 25, 1996, 50,000 therms a day of balance gas for delivery over the remaining days of July were sold for 13 pence per therm (see line 5 of table 3). 19 * Short- and medium-term gas is sold or resold to suppliers, with the period of delivery ranging from one month to one year. In one such transaction 100,000 therms a day of short-term gas were traded on July 25, 1996, for delivery in October 1996 (see line 6 of table 3). Similarly, two blocks of 25 therms a day of medium-term gas were traded on July 24, one for delivery in the fourth quarter of 1996 and the other for delivery in the 12 months starting October 1996 (see lines 3 and 4). * Time spread gas represents an exchange of gas contracts with different times of delivery. Shippers settle the price difference on the basis of their projection of the price of the gas. On July 26, 1996, shippers exchanged two gas contracts for delivery of 25,000 therms a day of gas in August and October (see line 8 of table 3). They agreed that the price of the contracts was identical, based on the prevailing spot market prices. Table 3 On-System Trading, July 22-28, 1996 Volume Price Day of trade Period of delivery (thousands of therms a day) (pence per therm) I July 22 Sept. 1-30 25 12.95 2 July23 Aug. 1-31 25 13.15 3 July 24 Fourth quarter, 1996 25 13.525 4 July 24 Oct. 1996-Sept. 1997 25 12.95 5 July 25 July balance 50 13.00 6 July25 Oct. 1-31 100 13.20 7 July 26 Aug. 1-31 25 13.30 8 July 26 Time spread 25 no price Aug. vs. Oct. difference 9 September Day ahead 25 13.1 24 Source: PH Energy Analysis, British Spot Gas Markets, Petroleum Argus, European Natural Gas Daily. The flexibility mechanism The flexibility mechanism provides a framework for trading gas imbalances in BGT's pipeline network. Its primary purpose is to eliminate system imbalances caused by the deviation of shippers' gas injections and withdrawals from the approved schedule. BGT uses an auction mechanism to buy gas from or sell it to shippers in order to restore system balance. The flexibility mechanism thus effectively establishes a spot market - the flexibility market - that is much like the on-system market, except that trading takes place between BGT and shippers rather than among the shippers. Shippers bid volumes and prices, and BGT selects the bids that minimize the cost of restoring system balance. Ideally, competition among shippers should lead to bids that reveal the true system short- 20 run marginal cost of gas, so that the price of gas in the flexibility market reflects the true market value of gas. Transactions in the flexibility market are carried out through an auction because of BGT's monopoly or monopsony position as a seller or buyer of gas. The auction is guided by the Network Code and Ofgas. BGT operates the system on a nonprofit basis and so does not directly benefit from transactions in the flexibility market. Its incentive is thus to restore system balance rather than to speculate in the flexibility market. Operation of the flexibility mechanism The flexibility mechanism operates as follows:7 * Shippers decide to sell gas to or buy it from BGT, depending on their estimates of system supply and demand and the price of gas.8 If a shipper expects a system imbalance on the next gas day and has some flexibility in adjusting its own portfolio of supply and demand contracts, it posts a flexibility bid on the electronic network. A flexibility bid can be for a "system sell" or a "system buy," depending on the kind of system balance expected. (The transactions in the flexibility market are always considered from the point of view of the system.). A typical flexibility bid specifies the type of bid, the date, the quantity and calorific value of gas, the injection or withdrawal points, the duration of the implementation of the offer, and the price per kilowatt-hour. Shippers can offer alternatives to their bid or withdraw it at any time except when the bid is being evaluated or after it has been accepted. Shippers can also see other bids but not who posted them. X The list of bids becomes available to BGT at 6:00 p.m. on the day preceding the gas day. If a system imbalance occurs, BGT accepts the best bid, typically the one with the best price. (Other parameters considered are time, location of injection and entry points, and duration of implementation of the offer relative to the same parameters of the system imbalance.) That means that BGT accepts the lowest-price bid for a system buy and the highest-price bid for a system sell. The price of the last accepted bid becomes the system marginal price. BGT then notifies the successful bidders, who must implement the offers. If shippers fail to comply, they incur scheduling and imbalance penalties. All unaccepted flexibility bids become redundant at 4:00 a.m. on the current day. Transactions in the flexibility market are settled in a subsequent monthly invoice. The flexibility mechanism was introduced as part of the Network Code in April 1996. The Network Code requires all shippers to keep a daily balance between injected and withdrawn gas within a certain tolerance. If shippers exceed their daily balance, they are 7 This discussion of the flexibility's mechanism's operation draws from EIGT 1996. Changes in supply and demand cause changes in the injections and withdrawals of individual shippers, resulting in system imbalance and action by BGT in the flexibility market. If the system runs a positive imbalance, BGT must sell the extra gas - a "system sell" - to restore system balance. If the system runs a negative imbalance, BGT must purchase the missing gas - a "system buy." The price for a system sell is lower than the prevailing spot market price, while the price for a system buy is higher. 21 charged an imbalance penalty. In addition, they receive credit or are charged for the gas withdrawn or injected in excess of the tolerance. A unit price of this gas is equal to the system marginal price. The transition from monthly to daily balancing imposed substantial requirements on shippers. To phase in this change, the Network Code operated under a "soft landing" regime between April and September 1996. This regime allowed shippers to exceed their daily balance by 100 percent of the daily average of their deliveries and offlakes during the previous 30 days. The daily imbalance outside this tolerance was cashed out at the system marginal price. At the end of the month, if the monthly imbalance (the cumulative daily imbalances) did not exceed three times the tolerance level, it was cashed out at the system average price, equal to the average price of all accepted flexibility bids during the last 30 days. If the monthly imbalance was above the tolerance, the imbalance was cashed out at the system marginal price (figure 4). Figure 4 Balancing under the Soft Landing Regime of the Network Code Daily imbalance tolerance Monthly imbalance Daily Imbalance Monthly imbalance tolerance) Days in month End of the month Source: Gas Matters, March 1996 Note: The daily imbalance is equal to the difference between offlakes and deliveries on the gas day. It is cashed out at the system marginal price if it exceeds daily imbalance tolerance; otherwise it is cashed out at the system average price. The daily imbalance tolerance is based on the average of the last 30 days of deliveries and offtakes. The monthly imbalance is equal to the cumulative daily imbalance at the end of the month. It is cashed out at the system marginal price if it exceeds the monthly imbalance tolerance; otherwise it is cashed out at the system average price. The monthly imbalance tolerance is equal to three times the daily imbalance tolerance. 22 Evaluation of the flexibility mechanism The flexibility mechanism facilitates real-time, market-based reactions by the system operator to a system imbalance. BGT's ability to monitor the system and quickly identify the source, size, and location of an imbalance at any given moment allows it to determine an appropriate response. The price signals generated by the flexibility market indicate the cost-minimizing way to restore system balance. Based on the cost of gas as revealed by the flexibility bids, BGT can decide whether to use the flexibility mechanism to restore balance or to curtail shipments instead. The flexibility mechanism effectively imitates a spot market in order to facilitate trading of day and swing gas' in form of gas balances. Such gas is often lacking in spot markets, where the typical product is month gas. Trading in the flexibility market occurs only if the system is in an imbalance caused by the imbalances of individual shippers. These individual imbalances are caused by a change in supply or demand that induces a shipper to alter its injection and withdrawal schedule from the nominated one. At the same time, the change in supply or demand causes the market value of gas to deviate from the spot market price. BGT uses the flexibility mechanism to restore system balance and discover the actual market value of gas. Flexibility bids reveal the system short-run marginal cost of gas, and the market value of gas is equal to the system marginal price determined in an auction. Shippers are willing to sell gas to the system only if the market value of gas is above the spot market price and to buy gas only if the market value is below that price. Consequently, shippers with imbalances realize the market price for the gas that is above the tolerance level. The system marginal price for a system sell therefore should be below the spot market price, while that for a system buy should be above the spot market price. This gives a premium to selling or buying shippers and imposes a penalty on shippers with imbalances. An overview of price determination in the flexibility market is given in figures 5 and 6. Swing gas is very-short term gas delivered on an hourly basis. 23 Figure 5 Price Determination in the Flexibility Market with the Source of Imbalance a Change in Demand SRMC 6 Positive system Negative system imbalance imbalance System sell System buy 4 SMPbU - 3 PS0 Qw1 Q1l=QW0Qw0 Q12 Qw2 24 SRMC System short-run marginal cost of gas. Situation on the day before the gas day PS. Spot market price of gas with delivery on the gas day (day-ahead gas.) Q1io QWO The quantity of gas nominated for injection into and withdrawal from BGT's pipeline system according to the approved schedule for the gas day. The system must be in balance: Qlo=Qwo. I-IV, 1-6 Flexibility bids for a system sell and a systera buy. Situation on the gas day Case 1: Positive system imbalance - system sell QWIQw,. BGT must sell the excess gas in the flexibility market to restore system balance. BGT accepts flexibility bids I-III. SMPSe.I The system marginal price of gas sold by BGrT to winning bidders. It is equal to the price of the last accepted flexibility bid. Case 2: Negative system imbalance - system buy QW2>QWO The quantity of gas withdrawn from the system is above the nominated quantity because of an unexpected increase in demand for gas. Shippers are unable to react in real time, so the quantity of gas that is injected into the system is equal to the nominated quantity (Q02=Q10). Qi 2.QW2 The difference between the quantities of injected and withdrawn gas is equal to the size of the system imbalance, which is negative because Q12Qio The quantity of gas injected into the system is above the nominated quantity because of an unexpected increase in the supply of gas. Consumers are unable to change consumption in real time, so the quantity of gas withdrawn from the system is equal to the nominated quantity (QWl=QW.). Qil Qw1 The difference between the quantities of injected and withdrawn gas is equal to the size of the system imbalance, which is possible because Qil>QW,. BGT must sell the excess gas in the flexibility market to restore system balance. BGT accepts flexibility bids I-IV. SMPSeII The system marginal price of gas sold by BGT to winning bidders. It is equal to the price of the last accepted flexibility bid. Case 2: Negative system imbalance - system buy SRMC2 The system SRMC shifts upward because of a negative gas supply shock. QV2 Information flows 1 Bilateral natural gas contracts between producers and shippers or British Gas Energy (BGE). 2 Natural gas acquisition in spot markets. 3 U.K. Link - communication exchange between British Gas TransCo (BGT) and shippers or BGE. Facilitates nomination, allocation, flexibility and capacity bidding, balancing, and invoicing. 4 Contracts for pipeline capacity and transportat'on services between British Gas TransCo and shippers. 5 Natural gas supply contracts. The natural gas market is divided into contract and tariff markets. The contract market is composed of consumers using more than 2,500 therms a year. It is open to competition, and BGE competes directly with about 40 independent suppliers. The market share of British Gas fell from almost 100 percent in 1988 to about 80 percent in 1992. Prices are subject to negotiation between consumers and BGE or independent shippers and suppliers. BGE is required to publish its rates for both firm and interruptible gas. Published rates must disclose a charge for transportation and an energy component, including conditions of transportation. The tariff market is composed of consumers using less than 2,500 therms a year. At present, there is no competition in the tariff market, although a pilot program of retail competition involving 500,000 consumers was launched in April 1996 in southeastern England. There, BGE competes with nine other suppliers. In the first month of the program about 6 percent of consumers switched from BGE to another supplier, and it is 40 expected that BGE will lose about 12.5 to 25 percent of the southeastern market (Ernst & Young Energy Services Group 1996). In April 1997 another 1.5 million retail customers were allowed to choose a supplier, and at the beginning of 1998 full retail competition will be introduced. BGE is expected to lose about 25 percent of the entire tariff market (Royle 1996). The regulator of the gas industry is the Office of Gas Supply (Ofgas), which regulates tariffs and the industry structure. Other institutions with regulatory authority over the industry include the Office of Fair Trading and thle Monopolies and Mergers Commission, together the competition watchdogs, and the Department of Trade and Industry, the sectoral ministry. Tariffs for tariff market customers are regulated by Ofgas on the basis of the following price cap formula: RPI -X+ GPI - Z+ E+ K, where RPI is the retail price index. Xis the productivity improvement factor, currently set at 5. GPI is the gas price index, constructed by Ofgas to reflect British Gas's average cost of gas. Z is the efficiency factor of GPI, currently set at 1. E is the energy efficiency expenditure factor. K is a correction factor that allows over- or underrecovery of costs in any particular year to be corrected in later years. Tariffs cannot be changed more than twice a year without the approval of Ofgas. Tariffs for transportation and storage are also regulated by Ofgas. Tariffs are first calculated to generate revenues that cover BGT's total costs and return on assets. Then tariffs are subject to the following price cap formula: Ml = [ 1 + ( RPIt -X) / 100 ] Pt-, - K, where Ml is the maximum revenue per therm transported by BGT. RPI is the retail price index. X is the productivity improvement factor, currently set at 5. Pt is the maximum revenue per therm that BGT was allowed to earn in the previous year. K is a correction factor that allows over- or underrecovery oi costs in any particular year to be corrected in later years. This formula came into effect on October 1, 1994, when BGT introduced a new structure for transportation and storage charges. 41 BGT and Ofgas are presently engaged in talks about further restructuring of transportation and storage charges to promote the efficient use of and investment in the pipeline system and to unbundle and open to competition other lines of business, such as service connection, emergency services, and meter installation and reading. Ultimately, BGT should operate solely as a transporter of natural gas and a provider of system balance and reliability in the deintegrated, unbundled natural gas industry. Table A.1 U.K. Gas Prices Index, 1990=100 Current Prices (excl. VAT) Year Beach Residential Industrial El. Producers 1986 89.93 113.43 137.74 1987 89.05 106.78 110.53 1988 94.91 89.75 101.69 91.73 1989 99.02 93.64 98.31 100.00 1990 100.00 100.00 100.00 1991 108.61 106.89 100.91 1992 107.05 106.71 104.43 1993 102.15 102.60 102.74 106.17 1994 110.18 102.60 103.65 100.30 1995 109.59 104.13 90.35 96.69 Note: Gas Prices Index for Power Producers 1989=100 Source: DTI Table A.2 U.K. Gas Prices Index, 1990=100 Real Prices (excl. VAT) Year Beach Residential Industrial El. Producers 1986 114.12 143.94 164.36 1987 107.55 129.07 125.60 1988 108.02 102.22 115.78 98.30 1989 105.28 99.62 104.56 100.00 1990 100.00 100.00 100.00 1991 101.96 100.37 94.78 1992 96.09 95.79 93.74 1993 88.85 89.22 89.31 86.85 1994 93.93 87.54 88.40 80.48 1995 91.39 86.85 75.36 75.81 Note: Gas Prices Index for Power Producers 1989=100 Source: DTI Table A.3 Natural Gas Consumption in the U.K., 1986-1995 (GWh) '(ear Residential Commercial Industrial El. Producers Other* TOTAL 11986 299,929 84,348 151,269 6,200 46,535 588,281 11987 307,578 86,664 164,442 6,200 49,041 613,925 11988 300,515 137,420 150,235 6,200 1,345 595,715 1989 290,557 134,403 160,050 6,200 -9,479 581,731 1990 300,410 138,446 164,993 6,400 -11,817 598,432 1991 333,963 158,738 158,354 6,561 -14,116 643,500 1992 330,101 150,795 147,584 17,894 -3,234 643,140 1993 340,162 153,975 148,707 81,778 -4,798 719,824 1994 329,710 156,315 164,557 114,575 2,180 767,337 1995 326,010 171,860 165,022 145,790 3,223 811,905 * Includes public administration, agriculture and balancing items Source: DTI Table A.4 Natural Gas Production and Imports in the U.K., 1986-1995 (GWh ) '(ear Production Imports Total 1986 483040 137099 620139 1987 508126 128893 637019 1988 491249 115441 606690 1989 481257 113770 595027 1990 531377 79833 611210 11991 591795 72007 663802 11992 602322 61255 663577 11993 707685 48525 756210 11994 755763 33053 788816 1995 826722 19457 846179 Source: DTI Figure A.2 Index of Current Gas Prices, 1990=100 140 140 120 \ 120 100 4 - - - ---0 -0- Beach - Residential - Industrial X El. Producers 18 1 1 1 1 1991 80 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 Figure A.3 Index of Real Gas Prices, 1990=100 175 -- 175.00 -4- Beach k Residential + Industrial - El. Producers 150 - --- ----------------------- - - -- --- ---- ---- - --- ---- ........... .... - 150.00 125 -- - - 125.00 75 - -- - -------+------ -------_------ --- __-_75.00 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 Figure A.4 Natural Gas Consumption in the U.K., 1986-1995 900,000 0 Residential 3 Commercial * Industrial H El. Producers 800,000 700,000 600,000 -------- 500,000 400,000 300,000 200,000 - 100,000 0 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 Figure A.5 Natural Gas Production and Imports in the U.K., 1986-1995 900,000 O Production * Imports 800,000 ...... 700,000 600,000 500,000----- 400,000 --- 300,000----- 200,000 - l 100,000 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 References BGT (British Gas Transco). 1996. Gas Transportation Charges 1995/96. London BGT. 1996. Network Code: The Summary. London. British Spot Gas Markets. July 26, 1996. PH Energy Anal,ysis, London. British Spot Gas Markets. July 29, 1996. PH Energy Analysis, London. Bryce, Colin. 1996. Personal comrnunication. Morgan Stanley, London. Ernst & Young Energy Services Group. 1996. Presentation on developments in UK energy utilities at the World Bank, Industry and Energy Department, Washington, DC. June 1 1. Gas Matters. Britain's Network Code is Up and Running. March 1996. EconoMatters, London. Higson, Mark. 1993. "A Pricing Structure for Gas Transpertation and Storage." A consultation document. OFGAS, London. International Energy Agency. 1994. Natural Gas Transportation: Organization and Regulation. OECD/EIA, Paris. International Petroleum Exchange (IPE). 1997a. Natural Gas (National Balancing Point) Contract: Contract Specification. The IPE Web Page http://www.ipe.uk.com. IPE. 1997b. Natural Gas Futures Break Through Records. Press Release (July 31). London National Economic Research Associates (NERA). 1995. Gas Sector Structure & Regulation in Selected OECD Countries. London. The Office of Gas Supply (OFGAS). 1994. Proposed Changes to the Gas Tariff Formula. A consultation document. London. OFGAS & DTI. 1994. Competition and Choice in the Gas Market. A joint consultation document. OFGAS, London. Petroleum Argus European Natural Gas Daily, September 23, 1996. Petroleum Argus, London. Petroleum Argus European Natural Gas Daily, October 3, 1996. Petroleum Argus, London. PH Energy Analysis. 1996. The Heren Index: Monthly Gas Market Report and Valuation (July). London. Powell, William. 1996. Personal communication. Editor of British Spot Gas Markets, PH Energy Analysis, London. Roeber, Jim. 1996. "The Development of the U.K. Natural Gas Spot Market." Energy Journal Vol 17, No.2, pg. 1-15. Royle, Gundi. 1996. "British Gas: Light at the End of a Long Tunnel. " Investment Research U.K. and Europe. Morgan Stanley International, London. Policy Research Working Paper Series Contact Title Author Date for paper WPS1869 Risk Reducation and Public Spending Shantayanan Devarajan January 1998 C. Bernardo Jeffrey S. Hammer 31148 WPS1870 The Evolution of Poverty and Raji Jayaraman January 1998 P. Lanjouw Inequality in Indian Villages Peter Lanjouw 34529 WPS1 871 Just How Big Is Global Production Alexander J. Yeats January 1998 L. Tabada Sharing? 36896 WPS1872 How integration into the Central Ferdinand Bakoup January 1998 L. Tabada African Economic and Monetairy David Tarr 36896 Community Affects Cameroon's Economy: General Equilibrium Estimates WA'P51873 Wage Misalignment in CFA Countries: Martin Rama January 1998 S. Fallon Are Labor Market Policies to Blame? 38009 WPS1874 Health Policy in Poor Countries: Deon Filmer January 1998 S. Fallon Weak Links in the Chain Jeffrey Hammer 38009 Lant Pritchett WVP5S1875 How Deposit Insurance Affects Robert Cull January 1998 P. Sintim-Aboagvy Financial Depth (A Cross-Country 37644 Analysis) VVPS1876 Industrial Pollution in Economic Hemamala Hettige January 1998 D. Wheeler Development (Kuznets Revisited) Muthukumara Mani 33401 David Wheeler WPS1877 What Improves Environmental Susmita Dasgupta January 1998 D. Wheeler Performance? Evidence from Hemamala Hettige 33401 Mexican Industry David Wheeler WPS1878 Searching for Sustainable R. Marisol Ravicz February 1998 M. Ravicz Microfinance: A Review of Five 85582 Indonesian Initiatives WPS1879 Relative prices and Inflation in Przemyslaw Wozniak February 1998 L. Barbone Poland, 1989-97: The Special Role 32556 of Administered Price Increases WPS1880 Foreign Aid and Rent-Seeking Jakob Svensson February 1998 R. Martin 39065 WPS1881 The Asian Miracle and Modern Richard R. Nelson February 1998 C. Bernardo Growth Theory Howard Pack 31148 WPS1882 Interretional Resource Transfer and Toshihiko Kawagoe February 1998 R. Martin Economic Growth in Indonesia 39065 Policy Research Working Paper Series Contact Title Author Date for paper WPS1883 Intersectoral Resource Allocation and Fumihide Takeuchi February 1998 K. Labrie Its Impact on Economic Development Takehiko Hagino 31001 in the Philippines WPS1884 Fiscal Aspects of Evolving David E. Wildasin February 1998 C. Bernardo Federations: Issues for Policy and 31148 Research WPS1885 Aid, Taxation, and Development: Christopher S. Adam February 1998 K. Labrie Analytical Perspectives on Aid Stephen A. O'Connell 31001 Effectiveness in Sub-Saharan Africa WPS1886 Country Funds and Asymmetric Jeffrey A. Frankel February 1998 R. Martin Information Sergio L. Schmukler 39065 WPS1 887 The Structure of Derivatives George Tsetsekos February 1998 P. Kokila Exchanges: Lessons from Developed Panos Varangis 33716 and Emerging Markets WPS1888 What Do Doctors Want? Developing Kenneth M. Chomitz March 1998 T. Charvet Incentives for Doctors to Serve in Gunawan Setiadi 87431 Indonesia's Rural and Remote Areas Azrul Azwar Nusye Ismail Widiyarti WPS1889 Development Strategy Reconsidered: Toru Yanagihara March 1998 K. Labrie Mexico, 1960-94 Yoshiaki Hisamatsu 31001